ML18040B044
| ML18040B044 | |
| Person / Time | |
|---|---|
| Site: | Susquehanna  |
| Issue date: | 03/09/1984 |
| From: | Curtis N PENNSYLVANIA POWER & LIGHT CO. |
| To: | Schwencer A Office of Nuclear Reactor Regulation |
| Shared Package | |
| ML18040A730 | List: |
| References | |
| PLA-2125, NUDOCS 8403210072 | |
| Download: ML18040B044 (778) | |
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{{#Wiki_filter:SSES-FSAR TABLE 1 6-1 REFERENCED REPORTS A. Ge eral Electric Company Reports Repor Referenced in ~ C Number Title FSAR Section 0 (0 APED-4824 aximum Two-Phase Blovdown from 6.2 ( ril 1965) o A PED-4986 Cons uences of Operating Zircaloy- 4 2 2 Cla Fuel Rods Above the Critical Heat Fl (October 1965) . v~ APED-5286 Design Bas s for Critical Heat Flux 1.5 Condition i BMRs (September 1966) APED-5458 Effectiveness f Core Standby 5.4 Cooling Systems or General Electric Boiling Mater Rea tors (March 1968) APED-5460 Design and Performa ce of General 3.9 Electric BMR Jet Pum (July 1968) APED-5555 Impact Testing on Colle Assembly 4.6 for Control Rod Drive Me anism 7RDB 144 A (No v em ber 19 67) APED-5640 Xenon Considerations in Desi of 4. 1 e 4-3 Large Boiling Mater Reactors une 1968) A PED-5652 Stability and Dynamic Per formance 4.1 of the General Electric Boiling Mater Reactor APED-5706 In-Core Neutron Monitoring System 7.6, 7.7, for General Electric Boiling Water 6. 2a.5 Reactors (November 1968, Revised April 1969) APED-5736 Guidelines for Determining Sa fe Appen ix Test Intervals and Repair Times for Engineered Safeguards (April 1969) APED-5750 Design and Performance of General 5.4 Electric Boiling Water Reactor Main Steam Line Isolation Valves (March 1 969) Rev. 17, 9/80
S S ES-PS AR gage TABL 1 6-1 CONTINUED Report Referenced in Number Title Fsaa section APED-5756 Analytical Methods for Evaluating the Radiological Aspects of the General Electric Boiling Mater Reactor (March 1969) GEAP-10546 Theory Report f or Creep-Plast Computer Program (January 1972) GEAP-13112 Thermal Response and Cladding 4 2 Performance of an Internally Pressurized,' irca loy-Clad, Simulated BMR Bundle Cooled by Spray Under Loss-of-Coolant Conditions (April 1971) NE DE- 103 13 PDA-Pipe Dynamic Analysis Program 3 6 for Pipe Rupture Movement (Proprietary Filing) NEDE-11146 Design Basis 'for New Gas System 11 3 (July 1971) {Company Proprietary) N EDE-20386 Fuel Channel Deflections 2 NEDE-21156 Supplemental Information for Plant 4 4 Modification to Eliminate Significant In-Core Vibration (January 1976) NEDE-21175-P B MR/6 Sue 1 Assem bl y E va 1ua t ion of 3 9 Combined Safe Shutdown Earthguake (SSE) and Loss-of-Coolant. Accident (LOCA) Loadings (November 1976) N EDE-213 54-P BMR Fuel Channel Nechanical Design 3 9 and Deflection (September 1976) NEDE-23014 HEX Ol User's Manual (July 1976) "15 2 NEDN-10735 Densif ication Considerations in BMR, 2 Fuel Design and Performance (December 1972) NEDO-10173 Current State of Knowledge, High 4 2, 11-1 Performance BMB Zircaloy-Clad U02 Fuel (Nay 1970) R EV 1 8/78
SSES- FS AR Page 3 TABLE 1. 6-1 COHTINrJED Report Referenced in Number Tit le FSAR Sect ion NEDO-10174 Consequences oi a Postulated Fuel 4 Blockage Incident in a Boiling Mater Reactor (Nay 1970) NEDO-10299 Core Flow Distribution in a Nodern 4.4 Boiling Mater Reactor as measured in Mon ticello (Jan ua.-y 1971) NEDO-10320 The General Electric Pressure Oo 2 Suppression Contairrment Analytical Model (April 1971) Supplement 1 (Yiay 1971) NEDO-10329 Loss-of-Coolant Accident and .4 3 Emergency Core Coo'ling Models for General Electric Boiling Mater Reactors (April 1971) Supplement 1 (April 1971) Addenda (Nay 1971) NEDO-10349 Analysis of Anticipated Transients 15. 8 Mithout Scram (i)arch 1971) NEDO-10466 Power Generation Control Complex Design 3.12.3. 4.2. (f)1 Criteria and Safety Evaluation (February 1972) NEDO-10505 Experience with BMH Fuel Through 4.2, 11. 1 September 197l (Nay 1972) NEDO-10527 Rod Drop Accident. Analysis for 43,154 Large Boiling Mater Reactors (March 1972) Supplement 1 (July 1972) Supplement 2 (January 1973) NEDO-10585 Behavior of Iodine in Reactor Mater 15. 6 During Plant Shutdown and Startup (August 1972) NEDO-10602 Testing of Improved Jet Pumps for 3.9 the BMR/6 Nuclear System (June 1972) NEDO-10734 A General Justification for Classi- 11. 3 fication of Effluent Treatment System Equipment as Group D (February 1973) REV 4 ]/79
SSES-PSAR Page 4 i Report Referenced in
~a@beg Title FSAR Section NEDO-10739 methods for Calculating Safe Test 6.3 Intervals andnd Allowable Repair Times for Engineered Safeguard Systems (January 1973)
N EDO-10751 Experimental and Operational 11. 3 Confirmation of Offgas System Design Parameters (January 1973) {Company Proprietary) NEDO-10801 Modeling the BMR/6 Ross-of-Coolant 1.5 Accident: Core Spray and Bottom Flooding Heat Transfer Effectiveness (March 1973) NEDO-10802 Analytical Methods of Plant 4.4, 5.2, 15.1 Transient Evaluations for General Electric Boiling Water Reactor {February 1973) NEDO-10846 BMR Core Spray Distribution (April 1.5 1973) NEDO-10899 Chloride Control in BMR Coolants 5 2 (June 1973) NEDO-10958 General Electric BMR Thermal 4.3, 4 4, 15 0 Analysis Basis (GETAB): Data, Correlation, and Design Application (Novemb'er 1973) NEDO-10958- A General Electric BMR Thermal 1.5, 15 4, 16 1 Analysis Basis -(GETAB): Data, Correlation, and Design Application (January 1977) NEDO-109 59 General Electric,BMR'Thermal 15 0 Analysis Basis .(GETAB): Data, Correlation, and Design Application (November 1973) N EDO-20231 Emergency Core Cooling Tests of 1.5 an Internally Pressurized, Zircaloy-Clad 8x8 Simulated BMR Fuel Bundle {December. 1973) r REV 1 8/'78
SSES-FSAR Page 5 TABLE 1 6-1 CONTXNUED Report Referenced in Number Title FSAR Section N ED 0-2 03 4 0 Process Computer Performance 4 3 Evaluation Accuracy (June 1974) NEDO-20360 General Electric Boiling Mater 42,154 Reactor Generic Reload Application for 8x8 Fuel (May 1975) NEDO-20360-IP General Electric Boiling Mater 4 2 Reactor Generic Reload Application for 8x8 Fuel (March 1976) NEDO-20533 The General Electric Mark XXI
- 1 5 Pressure Suppression Containment System Analytical Model (June 1974)
NEDO-20566 General Electric Company Model for 3 9, 4 3, 6.3 Loss-of-Coolant Accident Analysis in Accordance with 10 CFR 50, Appendix K (January 1976) NEDO-206Q5 Creep Collapse Analysis of BMR Fuel 4 2 and .Using Safe Collapse Model N EDO-206 06 (August 1974) NEDO-20626 Studies of BMR'esigns for 15 8" Mitigation of Anticipated Transients without Scrams (October 1974) ~ NEDO-20626-1 Studies of BMR Designs for 15 8 Mitigation of Anticipated Transients without Scrams (June 1975) NEDO-20626-2 Studies of ~ BMR Designs for 15 8 Mitigation of Anticipated Transients without Scrams (July 1975) NEDO-20631 Mechanical Property Surveillance of 5 3 Reactor Pressure Vessels for General Electric BMR/6 Plants (March 1975) NEDO-20913 Lattice Physics Methods (June 1975) 4.3 N EDO-209 22 Experience with BMR Fuel Through 4 2, 11.1 September 1974 (June 1975) NEDO-20939 'attice Physics Methods Verification 4 3 R EV 1 8/78
SSES-PSAR Page 6 TABLE 1 6-1 CONTINUED Report Referenced in Number T tie FSAR Section (August 1975) NEDO-20943 Uran ia- G ado linia Nuclear F ue 1 4.2 Physical and Material Properties (January 1977) NEDO-20944 BMR/4 and BMR/5 Fuel Design 4. 1r and (October 1976) NEDE-20944P NEDO-20946 BMR Simulator Methods Verification 4 3 (May, 1976) NEDE-20944-XP BMR/4 and BMR/5 Fuel Design 4 2 (January 1977) NEDO-20948-P BMR/6 Fuel Design (June 1976) V 4 2 NEDO-20953 Three-Dimensional Boiling Mater 15,4 Reactor Core Core Simulator (May 1976) NEDO-209 64 Generation of Void and Doppler 4 3 Reactivity Feedback for Application to BMR Plant Transient Analysis (August 1.975) ,.NEDO-.211 42 Realistic Accident Analysis for 15.4, 15 6, 15 7 General Electric Boiling Water Reactor The RELAC .Code and User's Guide to be issued (December 1977) NEDO-21143 Conservative Radiological Accident 15 4, 15 6, 15;7 Evaluation. The CpNACOl Code {March 1976) N EDO-21159 Airborne Release from BMRs for 1'1 1 Environment Impact Evaluations {March 1976) Fuel Channel Deflections 4.2
'MR N ED 0-211 74 E N EDO-21231 Banked Position Withdrawal Sequence 4 3 (September 1976)
N EDO-212 91 Group Notch Node of the RSCS,for 15 4, R EV 1 8/78
SS ES-FSA R Page 7 I~RBL ~16-1 'COHIIHUBD Report Referenced in Number Title FSAR Section Cooper (June 1976) NEDO-26453 3D BMR Core'Simulator (May 1976) 4 3 Oyster Creek Station, FSAR Amendment 10 1 5 1tSummary Memorandum on Excursion 4.3, 15 .0 Analysis Uncert'ainties," Dresden Nuclear Power Station, Unit 3,. Plant Design Analysis Report Amendment 3 Hatch Nuclear Plant, Unit 1, PSAR 15 5 Amendment 10, Appendix L Millstone Nuclear Power Station, PSAR 6 3 Amendment 14 Pilgrim Nuclear Power Station, PSAR 6 3 Amendment 14 Quad Cities Station, Units 1 and 2, ...-. 4 3 PSAR, Amendment 9 This listing to be updated for each requisition plant. B. Other Referenced Reports AE-RTL-788 Void Measurements in the Region of 44 Subcooled and I,ow Quality Boiling (April 1966) ANL-5621 Boiling. Density in Vertical 4;4 Rectangular Multichannel Sections with Natural Circulation (November 1956) A NL-6385 Power-to-Void Transfer Functions 4 4 {July 1961) AGN-TM-407 AGN-GAM, an IBM 7090 Code to 4 3 Calculate Spectra and Multigroup Constants (April 1965) ANL-7460 Reactor Development Program Progress 4 3 Report, p. 121-122 (June 1968) R EV 1 8/78
SSES-FSAR Page; 8 TABLE 1 6-1 CONTINUED Report Referenced in
~usher Title PSAR Section A NL-7527 Reactor Development Program Progress 4 3 Report, p 132 (December 1968)
BNL-5826 THERMOS-A Thermalization Transport 4~3 Code for Reactor Design (June 1961) B NM L-340 "Computer Code Abstracts, Computer 4 Code 3 HRG ~ ~~ Reactor Physics Dept., Technical Activities Quarterly Report, July, August, September, 1966 (October 15, 1966) BHR/DER 70-1 Radiological Surveillance Studies 11 1 at a Boiling Water Nuclear Power Reactor (March 1970) BMI-1163 Vapor Formation and Behavior in 4 4 Boiling Heat Transfer (February 1957) CF 59-6-47 Removal of Fission Product Gases 11. 3 (OBNL) From Reactor Off-Gas Streams by Adsorption (June 11 '959) IDO-ITR-1 05 The Response of Materlogged UO2 4 2 Fuel Rods to Power Bursts {April 1969) IN-ITR-ill The Effects of Cladding Material 4 2 and Heat Treatment on the Response of Waterlogged UO2 Fuel Rods to Power Bursts (January 1970) ST1-372-38 Kinetic Studies of Heterogeneous 4 4 Water Reactors (April 1966) TID-4500 %clap 3 A Computer Program for ~ 3 6 Reactor Blowdown Analysis 'IN-1321 (June 1970) UCRL-50451 Improving Availability and 16 3 Readiness of Field Eguipment Through Periodic Inspection, p. 10 (July 16, 1968) M ACP-6065 Melting Point of Irradiated 4 2 Uranium Dioxide (February 1965) B EV. 1 8/78
SSES-FSAR Page 9 TABLE 'I 6-1 CONTINUED Report Referenced in Number Title FSAR Section M APD-BT-. 19 A Method of Predicting Steady- 4 4 Boiling Vapor Fractions in Reactor Coolant Channels (June 1960) MAPD-TM-283 Effects of High Burnup on Zircaloy- 4 2 clad, Bulk U02 Plate Fuel Element Samples (September 1962) MAPD-TM-416 MXGLE A Program for the Solution 4 3 of the Two-Group Space-Time Dif-fusion Equations in Slab Geometry (1964) MAPD-TM-629 Irradiation Behavior of Zircaloy-Clad 4. 2 Fuel Rods Containing Dished End UO2 Pellets (July 1967) REV 1 8/78
SSZS-FS AR Design Conformance The primary containment system, which includes the drywell and suppression chamber,. is desiqned, fabricated, and erected to accommodate, without failure, the pressures and temperatures resultinq from the double-ended rupture or equivalent failure of any coolant pipe within the primary containment. The reactor buildinq encompassinq the primary containment provides secondary containment. The two containment systems and their associated safety systems are desiqned and maintained so that offsite doses, which rould result from postulated design basis accidents, remain below the quideline values stated in 10CPH100 when calculated by the methods of Regulatory Guide 1.3 (Rev. 2, 6/74) . Sections 6.2 and 15.1 have detailed information which demonstrates compliance with Criterion 16. 1.2. 2. 8 Electric Power Systems ]Criterion .17) r.r i+erion An onsite electric power system and an offsite electric power system shall be provided to permit functioning of structure., systems, and components important to safety. The safety function for each system (assuminq the other system is not functioning) shall be o provide sufficient capacity and capability to assure t ha+ (1) ..pecif ied acceptable fuel design limits and design conditions of the reactor coolant pressure boundary are not exceeded as a result of anticipated operational occurrences and (2) the core is cooled and containment integrity and other vital funrtions are maintained in the event of postula+ed accidents. The onsi te electric power supplies, including the bat teries, and tho onsi+e electric Distribution system shall have sufficient independence, redundancy, and testability to perform their safety f unction s, a ssuminq a sinqle failure. Electric power from the +ransmission network to the onsi"e electric Distribution system shall be supplied by two physically independent circuits (not necessarily on sepa ate rights of way), desiqned and located so as to minimize to the extent practical the likelihood of their simultaneous failure undo.r operating and oostul.ated accident and environmental conditions. A switchyard common to both circuits is acceptable. Each of these cirruits shall be Designed to be available in sufficient time followinq a loss of all onsite alternatinq current power supplies and the other of fsite electric power rircuit, to assu're that specified acceptable fuel desiqn limit and design conditions of. the reactor coolant pressure boundary are not exceeded. One of these circuits shal1 be desiqned to be available within a few seconds Rev. 30, 5/82 3% 1 17
SS ES-FS AR followinq a loss-of-coolant accident to assure that core cooling, containment inteqrity, and other vital safety functions are mai ntained. Provisions shall be included to minimize the probability of losinq electric power from any of the remaining supplies as a result of, or coinciden+ with, the loss of power generated by the nuclear power unit, the loss of power from the transmission network, or the loss of power from the onsite electric power supplies. Des ia n C onf ormance Two offsite power transmission systems and four onsite standby diesel qenerators with their associated battery systems are provided. Either of. the two offsite transmission power systems or. any three of the four onsite standby diesel generator systems have sufficient capability to operate safety related equipment +or cool inq the reactor core and maintaining primary containment i nteqrity and other vital functionsshutdownin the event of a postulated of the other unit. acciden+ in one unit with a safe The two independent offsite power systems supply electric power to the onsite power distribution system via the 230 kV transmission qrid. Each of the offsite power sources is supplied from a transmission line which terminates in switchyards (or Substations) not common to the other transmission line. The two t ransmission lines are on separate rights-of-.way. These two transmission circuits are physically independent and are designed to minimize the possibility of their simultaneous failure under operatinq and postulated accident and environment conditions. Hach offsitp power source can supply all Engineered Safety Feature {ESP) buses through its associated transformor.. Power is available to the ESF buses from their preferred offsite power source durinq normal operation and from the alternate off site power source if the preferred power is unavailable. Hach diesel qenerator supplies standby power to one of the four ESF buses in each unit. Loss of both offsite power sources +o an ESF bus results in automatic starting and connection of the associated diesel generator within 10 seconds. Loads are proqressively and sequentiallv added to avoid generator instabilities. There are four independent ac load groups provided to assure independence and redundancy of equipment function. These meet the safety requirements assuming a sinqle failure since any three of the four load groups have sufficient capacity +o. supply the minimum loads required to safely shut down the unit. Independent routinq of the preferred and alternate offsite power source circuits to the ESF buses are provided to meet the- single failure sa fet y reaui re ments. Rev. 30, 5/82 3. 1-18
SS ES-PS AR 3~ 4- MATER LEVEL QPLOOD)
=
DESIGN As discussed in Section 2.4 all Seismic Category I structures are secure against floodinq due to probable maximum flood (PMP} of the Susquehanna River or probable maximum precipitation {PMP) on the area surrounding the plant; Therefore, special flood protection measures are unnecessary. The Seismic Category I structures have, however, been designed. for hydrostatic loads resultinq from groundwater, as discussed in Section 3.8. The groundwater table is at elevation 665 MSL in the main plant area. A postulated break in the coolinq tower basins or of the water delivery pipes to the basin could result in a build-up of vater against the valls of either or both of the ESSM pumphouse and the turbine building. In the event of such water build-up breaching the turbine buildinq wall, water that vould not be intercepted by the floor Brains or qrilles and thus vould flow through the turbine building to the reactor building would be prevented from endangering eguipment in the latter by means of vatertight doors. Plood water buildinq up against the ESSM pumphouse vould also be prevented from enterinq the building by means of watertight doors. Impact forces and vater pressure due to flood water vill not endanqer the integrity of the ESSM pumphouse. All safety-related systems are located in the Reactor Building, Diesel Generator Building, Control Structure and the Engineered Safeguard Service Water {ESSM} Pumphouse. Sufficient physical separation betveen these buildings is provideR to prevent internal spreading of any floods from one building to another.. Redundant Engineered Safety Peatures, pumps and drives, heat exchanqers and associated pipes, valves and instrumentation in the reactor building subject to potential flooding, are housed in separate vatertiqht rooms. Seismic "ategory I level detectors trip alarms in the main control room when the water level in any room exceeds the set point. Isolation of the floor drainage lines from these rooms is provided by outside manual valves.. All other rooms in the reactor building and control structure containinq safety related equipment vhich are subject to potentia l flooding by process fluid leakage or fire protection vater are provided with at least one open floor drain. Floods in excess of the approximately 80 gpm floor drain capacity increase the vater level in the affected area and are released through the door-to-floor clearance of these rooms. Refer to Subsection 9.3.3 for a detailed description of the reactor building and control structure drainage system. 3 '4-1 Rev. 29, 3/82
SS ES-FS AR The four diesel generator sets are housed in individual water tight compartments within the diesel generator building. Ploor drain line branches from each of these compartments are equipped with check valves to prevent backflooding from the common sump. The ESSW pumphouse is divided into two redundan't compartments. Flooding from internal leakage would, therefore, only affect one of the redundant pump sets. The control and electrical panels are mounted on minimum 0 inch high concrete pads or structural supports. Operating floor openings allow drainage of any leakage to the ESSM pump suction space below or to a reserve sump space that could be emptied with a portable pump. Rev. 29, 3/82 3. 0-2
SSES- PS AR APPENDIX 3.6A PIPE BREAK OUTSIDE CONTAINMENT
SUMMARY
OP ANALYSIS AND RESULTS PART I ANALYSIS FOR SPACES OTHER THAN MAIN STEAM TUNNEL In addition to the analysis provided in Table 3.6-3, compartments containing high energy lines were analyzed to determine the peak pressures that might result'from breaks in these lines. The analysis vas done mainly to verify structural integrity. Duration of the blowdovn vas not a factor in th'e analysis since adequate vent area vas provided, and pressure peaked guickly then declined to a lower steady state value. The'tructures are adequate to withstand the peak pressures indicated by the analy sis. The valves which would be used to terminate the blowrlown are indicated. In qeneral, hovever, it is unnecessary to qualify equipment for the pipe break environment because the safeguards systems are separated into compartments which are vented directly to the atmosphere and high enerqy breaks affect only a single space. The plant can be safely shutrlovn using eguipment not affected by the hiqh enerqy line break. The followinq information for each compartment vas utilized with tha analytical techniques described in Appendix 6B of the PSAR to determine the pressures and temperatures resulting from high energy line breaks outside containment. ANALYSIS FOR HPCI PENETRATION ROOM /UNIT 1} Pipe Break Data Location: HPCI Penetration Room Line Identification/Size: DBB-114/10" Isolation Valve Designation and Location: HV E41-1P003 located in the HPCI Penetration Room Rev. 31, 7/82 3. 6A-1
SSES-PSAR Blowdown Data: t~sec}. mlXbnZ~<<3. hgBTU~lbm} 0.0 1892 1192 2 0.1 1892 1192.2 0.1 1353 1192. 2 0.2 1353 1192. 2 0.2 738 1192 2
- 0. 882 738 1192.2
- 0. 882 407 1'192. 2
- 51. 0 0 1192.2 I
Compartment Volume: 87,680 cu ft Vent Area: 67.0 sq ft Vent Coefficient: .574 L/A 0 0022 Ft- < Results: Peak Pressure: 2.12 psig Peak Temperature: 288. 4 F ANALYSIS FOR HQCI PUMP POOQ gU$ IT Pipe Break Data Location: HPCI Pump Room Line Identification/Size: DBB-114/10" HV E41-1F003 located in the HPCI Penetration Room Blovdovn Data: tgsgg} mdlbmdrecl= J 0.0 1892 . 1192.2
.088 1892 1192 2 088 1402 1192. 2
. 164 1402 ~
1192.2 164 946 1192 2
~
. 218 '46 1192 2
.218 283 1192.2 50 0 0 1192.2 Compartment Volume: 27,883 cu ft Vent Area: 60 sq ft Rev. 31, 7/82 3. 6A-2
SS ES-FS AR Vent Coefficient: .575 L/A 0 0 172Ft Results. Peak Pressure: 4.11 psig Peak Temperature: 298.6 F ANALYSIS POR RCIC PUNP ROON /UNIT li -" Break Data I'ipe
'ocation: RCIC Pump Room Line Identification/Size: DBB 109/4n Isolation Valve Designation and Location: 'V-E51-1F008 Located in the HPCI Penetration Room Blowdown Data:
tg sec) ~hB TUglbn g 0.0 286 6 1192.2
- 0. 024'.
286 6 1192. 2 024 218 5 1192 2
- 0. 042 218.5 1192. 2
- 0. 042 143 3 1192 2 0.278 143. 3 1192. 2
- 0. 278 29 l192. 2 7.6 29 1192 2
- 28. 0 0 1192. 2 Compartment Volune: 18,129 cu ft Vent Area: 46.0 sq ft Vent Coefficient: .575 L/A 0 0426 Ft Results: Peak Pressure: 0.52 psiq Peak Temperature: ~
238. 3 F ANALYSIS FOR RHR ROON A /UNIT 1} Pipe Break Data Location: RHR Roon A Line Identification/Size: OBB-115/10" Isolation Valve Designation and Location: HV E41-1F003 located in the HPCI Penetration Roon Rev. 31, 7/82 3. 6A-3
SS ES- PS AR, Blowdown Data:
~ml bmoc sec) 0.0 1892 1192.2
. 092 1892 1192. 2 092 1336 1.192. 2
.151 1336 1192. 2
.151 738 1192. 2
.261 738 1192. 2
. 261 348 1192.2 1.7 348 1 192. 2
- 52. 0 0 1192.2 Compartment Volume: 48,554 cu ft Vent Area: 85 sq ft Vent Coe fficient: .575 L/A 0 0098 Ft Results: Peak Pressure: 2.1$ psig Peak Temperature: 297.1 F ANALYSIS FOR RHR ROON B /UNIT li Pipe Break Data Location: RHR Room B Line Identification/Size: OBB-115/8>>
Isolation Valve Desiqnation and Location: HV E41-1F003 located in ! the HPCX Penetration Room Blowd own Data: tgsecg '; ~hBTU~bmg 0.0 1892 1192. 2
- 0. 023 1892 1192. 2
- 0. 023 946 '192.2
- 0. 222 946 1192. 2
- 0. 222 255 1192.2 2.6 255 1192. 2
- 53. 0 0 1192. 2 Compartment Volume: 60,000 cu ft Vent Area: 85 sq ft Rev. 31, 7/82 3. 6A-4
SS ES-PS AR Vent Coefficient: .575 L/A 0. 0076 Ft-1 Results: Peak Pressure: Peak Temperature:
- l. 33287.4 psig P
ANALYSIS FOR REACTOR MATER CLEANUP SYSTEN {RMCS) PENETRATION ROON Pipe Break Data Location: RMCS Penetration Room Line Identification/Size. DBC-101/6" Isolation Valve Designation and Location: HV G33-1F004 in RWCS Penetration Room Bio@down Data: tgsecg mal hm /~ed 0 0 3630 513
- 0. 063 3630 513
- 0. 063 2450 513
.'ll 2450 513
.11 1085 513
.843 1085 513
. 843 450 513
- 30. 0 0 ~
513 Compartment Volumes: Arch. Room No. Volume ~Cu. Ft~ I-501 5552 I-502 254 0 I-503 2540 I-504 4933 I-505 4850 Area Flow gath az> a 'Coe ffPlow icient L/A I-501 to ATN 45 0. 575 0 0426 I-501 to I-503 64 0. 711 0 0327 I-503 to I-504 64 0.682 0. 0580 I-504 to I-505 150 0.709 0 0169 I-503 to I "502 53 0 745 0. 0854 Results: Rev. 31, 7/82 3.6A-5,
SS ES-FS AR Arch. Boom-No. Peak Pressure Peak Tem n.= I-501 2 14 PSIG 211 7OF I-502 2 07 PSIG 113.9OF I-503 2 14 PSIG 154.4~F I-504 2 27 PSIG 113.3<F I-505 2. 31 PSIG 132.3OF I Note: The RHCS penetration room l-501, communicates vith the tvo RMCS Pump Rooms; I-502 and I-503 (vol. 2,540 cu ft each), the Regenerative Heat Fxchanger Room, I-504 (vol. 4,933 cu ft), and the Non-regenerative Heat Exchanger Room, I-505, (vol. 4, 850 cu ft) . A break in the RMCS penetration room results in a more severe environment than a break in any other zoom; theref ore, only results for this break are presented. Analysis for Compartment Pressurization in Unit 2 is identical to Unit 1, vith the exception of breaks in the HPCI and RCIC Rooms. These analyses are presented belov. ANALYSIS FOR RCIC'UMP ROON (UNIT 2) Pipe Break Data Location: RCIC Pump Boom Line Identification/Size: DBB-209/4" Isolation Valve Designation and Location: HV-E51-2F008 located in HPCI Penetration Room Blovdovn Data: tQsegj mg1bgggecg hgB Ta/1bmg 0 286 1192. 2
.024 286 1192. 2
.024 215 .1192. 2
.045 215 1192. 2
.045 143 1192 2
.278 143 '192 2
.278 29 2 1192.2 7.6 29. 2 1192 2 58 0 1192. 2 Compartment Volumes:
RCI C 18129 Cu. Ft-HPCI 27883 CQ Ft Rev. 31, 7/82 3 6A-6
SSZS-FS AR Tunnel 2650 Cu. Ft. Area Floe L/A F1ow Path Coeff icient ~Ft >) p RCIC to Tunnel 25 0. 677 0. 341 Tunnel to HPCX 72 0.711 0. 355 Tunnel to ATM 45 0.679 0. 319 Results: Boom Peak Pressure (PSIG3 Peak Te~m. /OFT RCXC 0.57 238. 5 HPCX 0.74 108. 1 Tunnel 0.74 220. 2 Notes: A break in the RCXC pump room results in a change in environment to'the HPCI pump zoom via connection of the tunnel to both rooms. Therefore, peak pressures are shown for all three compartments. ANALYSIS FOR HPCI PUHP HOON /UNIT 2J Pipe Break Data Location: HPCI Pump Room Line Identification/Size: DBB-214/10" Isolation Valve Designation and Location: HV-E41-2F003 located in the HPCX Penetration Room Blovdovn Data: 1892 1192. 2
.07 1892 1192. 2 07 1412 1192.2
.127 1412 1192. 2
.127 946 1192 2 223 946 1192. 2
.223 284 1192.2 500 0 1192 2 Comma rtm en t - Volumes:
HPCI 27883 CQ F t RCIC 18129 Cu. Ft. Tunnel 2650 Cu. Ft. Rev. 31, 7/82 '3.6A-6a
SSES- FS AR Area Flow L/A Plow Path C efficien+ ~Ft <g HPCI to Tunnel 72 0. 842 0. 355 Tunnel to RCIC 25 0. 626 0. 341 Tunnel to ATH 45 0.679 0.'31 9 Results: I Room- Peak, Pressure Peak Temp. g~F} HPCI 3.69 298 7 RCIC 2 98 ,143.5 Tunnel 3 07 ~ 294 7 Notes: A break in the HPCI pump room results in a change in environment to the RCIC pump room via connection of the tunnel to both, rooms. Therefore, peak pressures are shown for all three compartments. PART II LINE ANALYSIS OF HAIN STEAM TUNNEL LINE BREAKS IN THE HAIN STEAN Subcompartment differential pressure analysis were performed for the main steamline tunnel. Two break locations were chosen to render the design of each portion of the tunnel (viz. Reactor and Burbine Building -sides) conservative. They are: Case A. MSLB in the Reactor Building. (24>> DBB-103 at El. 719'-8>>, 1st elbow) Case B. HSLB in the Turbine'uilding. (24" DBB-103 at El. 719'-8>>, 2nd elbow) The pressure and temperature response of these areas to the postulated pipe breaks are predicted using the analytical model described in Appendix 6B with the changes described below. The Appendix 6B model ignores >>momentum effects" within a subcompartment. For most cases considered, .this is justified as the momentum effects are insignificant relative to the absolute pressure peaks. However, momentum effects are important to Rev. 31, 7/8 2 3.6A-6b
SSES-FSAB conservatively predicting pressures resulting from the main steam tunnel case. Therefore, for this study, the nomentum equation a aT (pu) + V. (puu) -Vp V~ V+ pg in the following is none-dimensionalized" and solved manner:
~ 2 gp A (x) a. '"(.) " ax p (.,e )
g,A()
- ~Bp x t) 1 ~SP x '0 ax A(x) Bx Mhere the F(x,t) term includes shear forces and non-one-dimensional momentum change effects. Its integral over a flow path is evaluated by means of empirically determined flow coefficients (see Appendix 6B).
Equation (1) is now integrated from midpoint to midpoint of two adjoining compartments assuming uncompressible flow, but with a uniquely determined fluid density. The density of the flow mixture is evaluated in a way which assures that, as flow approaches steady state conditions, the density and the computed mass flux approach the values obtained from the compressible steady state equations in Appendix 6B. tJsinq this assumption and inteqrating term by term, we obtain: First term: 1 fx>x 1 8 fA(x) m (x,t)] dx 1 a W(4) fx dx gu A(x aT at x g('- A(x) 1 ~dW d') E EA gc d'C Mhere the inteqral of (dx/A(x) j is evaluated sequantially for constant area seqments between X1 and X2. L l.. thus represents the length of segment i REV 2 9/78 3 6A-7
SS ES-FS AR Second term: A2 1~x 1 3 [ Ax m(xt) dx~-~Wt 2 2
'1
] J gc A(x) Bx gcp x A(x) dx A( )) dx (lb)
~W2 2 gcp Mhere the p in the above expression rema'ins to be def ined Third term:
x (1c) Xt should be noted that the above pressures are static values and to match the units of Equation (1) are, at this point, given in terms of lb /ft~. Fourth term: -)'x BP(x 0) ~V.. 2 x~ A(x) Bx A K< 2gc (ld) Mhere i=+lif M> Oand i=-1 M(0. The above equation is not really a proper integration, but just a replacement of this inteqral by the appropriate empirical correlation. The coefficient K is a properly summed coefficient for the floe path from xl to x 2 and can include .friction terms The velocity VT depends on the empirical correlation used, but is usually taken as the "throat" velocity. This is assumed to be the case, then Equation (ld) becomes:
~KA V 2 P 2 2 PAA ~W'2) (le)
) KA 2gc AT 2gc pAT Mhere AT is the junction flow area.
REV. 2 9/78 3.6A-8
SS ES- FSA R Before collectinq all the integrated terms, convert the static pressures of Equation lc into stagnation it is preferable to pressures. Pstat(i) Pstag(i) v 2gc i) ~ Pstag(i) ~
- w2gcpA.
~t)
Summinq the expressions obtained by Equations (lb) to (le) and usinq (lf) ve qet: t) 2 ('t (lg) 1 E Pl* PE* K~AW
~dW at i (~L)
Ai 2gcQAT Mhere the starred pressures imply stagnation values. Nov the flov rate of the previous time step is used to evaluate a finite-difference approximation of the time derivative:
<<(t) ~t)- 1; tl (2) at at In a given time interval, R (t-gt) is known, thus Equation (lg) is a quadratic in ve have:
a (t) . Writing it in the customary quadratric form Ki W 2 ( t) + ~A'A (~) W(t) ht gc ( i (+) w (t-Zt) + Pl* - P2* ) - 0 (3) gc and substituting the compressible flo~ equation for 'A The resultinq ratio is: Q I@ 1 P2 1/Ic P2 (Z E) ( Z PE 1 ((PE) -(PE) ) Pa R EV 2 9/78 3 6A-9
SSES-FSAR ) In the limit as ( PQP1) ~ 1, Equation 5 approaches a value of one as required and the PQP1 ratio stays below one for all other values of p2/p> and for all positive k. p is thus smaller than the arithmetic mean of the densities and smaller than the downstream density itself. This assures a conservatively minimized flow rate for a given pressure gradient. This also holds true when the inertial effects (time dependent momentum equation) are included. Table 3. 6A-l shows representative mass flux values calculated bv density and the proper compressible flow compatible density P is used. p>,As seen for all cases, the use of. p results in minimum and thus conservative flow rates. The calculational sequence can now be summarized. (l) After compartment state functions have been obtained, a first estimate of M(t) is evaluated using the compressible flow equation. (2) The estimate of M(t) is used in Equation 3b to evaluate the fluid density. (3) Utilizing the flow rate from the previous time step and the calculated p , Equation (3) is solved to obtain M(t). Daring each time step, the junction flow rate is chosen as the smaller of the flow rate resulting from the one-dimensional momentum equation or the flow rate resulting from the selected steady state compressible flow correlation. (Appendix 6B). Schematic drawings showing the nodalization of the steam tunnel for Case A and Case B are given in Figures 3 6A-1 and 3.6A-5, respectively. Blow out panel locations are shown in Figure 3.6A-2 Volumes, flow areas, flow coefficients, and L/A's for the models are presented in Tables 3.6A-2 through 3.6A-5. As indicated in Fiqure 3.6A-l, the main steam tunnel is subdivided into a total of eiqhteen volumes to model the effect of obstructions such as pipe restraints and blowout panels. For Case B, in Figure 3.6A-5, a ten volume model is used since the one-way blowout panels completely block the flow path to reactor building side, leaving diagrams for both Cases it 8unpressurized. A B The overall flow are presented in Figures 3.6A-3 and 3.6A-6 The blowdown data for the postulated double end guillotine mainsteam line break is shown in Table 3.6A-4. This blowdown is done in a way similar to ANs 176 standard (draft), as discussed below, but system friction is accounted for to reduce the calculated mass and energy releases to reasonable levels while maintaining a degree of conservatism. Other criteria are addressed as follows: Rev. 9 5/79
- 3. 6A-10
SSES-CESAR
- 1. Pull double-end break area Noody flow for steam blowdown immediately af ter pipe b rea k.
- 2. Chokinq Hoody flow occurs first at the break, then moves up to choke at flow restrictors.
- 3. Prictional loss of valves is not included.
4 Level swell (4% quality blowdown) occurs at 1 sec.
- 5. Steam isolation valves close in 5 seconds with a 0.6 second instrument and signal delay time. A linear ramp in flow area is used to model this closure.
The computational method of this double-end guillotine mainsteam line break is shown in Fiq. 3. 6A-8. In Piqure 3 6A-8, flow from the RPV to the break location is "forward flow,>> while the flow from the turbine to the break location is >>reverse flow.>> Let L> = The distance from flow restrictors to break location. L 2 = The distance from reactor pressure vessel nozzle to the f lo w re stric tors. L3 The distance from flow restrictor to the turbine crosstie. Lp = The shortest distance from the MSL crosstie back to the break location. (A) Calculation of mass and energy release rates from the forward direction. Let Ap = The cross-sectional flow area of the break, ft~. Av The throat area of the flow restrictor, f t~. p0 No-load system pressure, PSIA. Steam quality. Enthalpy of fluid, BTU/IBM Number of lines. Sonic speed for steam. Prie t iona 1 fac to r. D Diameter of the pipe system. 3 6A-11 Rev. 9 5/79
SS ES-PS AB (1) At 0 <T < L1/C sec. W. = (G A (1 T/(L1/C) ) M1 W2F W2F Where G M> = Nood y specific f lovr ate (LBN/sec+f te) based on P = >050 PSIA and h = 1190.0 BTU/IBN. 0 This ramp-dovn in flow rate simulates the increasing system resistance downstream of the decompression wave
+r nn 4.
(2)At L1/C < T < 2* (1.1
- L1) sec(Time for choking at flow restrictor) 0.9*C W2F GM Where GM2 = Noody specific flow rate based on p = 1050 psia (3) At
~)
and h = l.190.0 BTU/IBN with 2 0
* (1.1
- L )
Where GM3 = Noody specific
< T < 1.0 sec (Time for level swell) flow rate based on p = 1050 psia and h = 1190 BTU/IBN vith (B) Calculation of mass and energy release rates from the reverse direction.
L4 (1) At 0 < T < C W1R (GMj
- A W2R (1 T/L4/C) )
This ramp-dovn in flov rate simulates the increasing system resistance downstream of the decompression wave front. (2) At L4/c < T < 2 (L> + L4 sec (lib((h f6> choking at the fice xestx'icterus) C W2R
=
GM2R
- A
- N Where GM2R = Noody specific flow rate based on h = 119p BTU/TBB with ( (LB + Lh) p
( ) 2 * (L~+L ) < T ( L.pp set (Time for level svell) C 3 6A-1 2 Rev. 9 5/79
SS ES-PS AR W3R W3 (A LINE) + W (B LINE) + W ( C LZNF)
= A [G 3R (A) +G (B) +G (C)]
Where G MgR (A), GER (B) and G M~ (C} are the Moody specific klow rates for lines A, 5, C based on Po = 1050 PSIA and H = 1190 BTU/IBM with L for each line. (C) Calculation of mass and energy release rates from the swell phenomenon. (1) At l. 0 < T <4.35 sec. {Time for choking at the valve) I 0 yl t W S
=WS (A)+WS )+WS (C)+WS
= A [GMA (A) + GMS (B) + GMS (C) + GMS (D) ]
Where Ghg {A) ~ GM2 (B), G Mz (C), GM2 (D) are the Moody specific flow rates for lines A, B, C, D based on h =572 BTU/IBM (4'A guality) and L 2/D for each line. (2) At T = 5.6 sec. (Time for valve completely closed) W S
= 0.0 LBM/sec (D) Calculation of the total mass and energy release rates.
The total flov rate is obtained by adding up the forward flov and reverse flow at each time sequence by superpositioning of the two curves (forward and reverse). Then after 1.0 second, the total flow rate vill be just the flow rate calculated from svell on section (C). The pressure transients of this analysis for Cases A and B are plotted in Figures 3.6A-4 and 3.6A-7. It can be seen that the maximum pressure for Case A in the Reactor Building is 22.9 PSIA and for Case B in the Turbine Building is 37.1 PSIA. The peak temperature for Case A is 300. OeP and for Case B is 325.0oP. The following essential equipment is located with the steam tunnels on Susquehanna SES: Main Steam Isolation Valves {MSIV's) and Piping Peedwater Check Valves and Piping HPCI Piping RCIC Pipinq Leak Detection Instrumentation Pipe breaks in the remaining portion of the main steam piping between the reactor building and the turbine building will not
- 3. 6A-13 Rev. 9 5/79
SS ES-PS AR impact essential equipment since breaks in these areas are completely vented to the turbine building. Materflooding in either the turbine building or reactor building portion of the tunnel will drain to the turbine building without damage to the structure. All of the terms in the coefficients of Equation 3 can be evaluated except for the as yet undefined fluid density, p . As stated in the assumptions,. p'ill be evaluated in such a vay that, under steady state conditions, Equation (3) and the compressible flov equations of Appendix 6B vill yield identical results for R(t). Under steady state conditions M(t) = M (t At) and Equation (3) reduces to: K 2 W -Ap* 0 2gcp+ (3a) vhich yields W K
~ggcAT Ap*
(3b) vhere the W~ can be obtained from the steady state compressible flow equations in Appendix 6B. Under steady state conditions, the above value of p 'which is used in the momentum equation has a straightforward definition it is the density vhich has to be used in the steady state incompressible flow equation in order to reproduce correct steady state compressible flov rates. To achieve this, the density includes an implied correction factor which compensates for the enerqy required in compressible flow to accelerate the expanding fluid. Because of this correction, p vill, in fact be smaller than the downstream density,p2 ~ calculated by the isentropic expansion relationship. This can be shown by dividing Equation (3b) by P2 1/ p2 pl Pl (4)-, 1
' ~ V 3 6A-1 0 Rev. 9 5/79
SSBS-PSAR GB BWR fuel assembly desiqn bases and analytical methods includinq those applicable to the faulted conditions, are contained in References 3.9-4 and 3.9-5. Reference 3.9-5 is vritten primarily for BWR/6 plants; hovever, the methodology is applicable to BQR/4 plants. 3.9. 1.4~11 pefueligg Egujpment 1 Refueling and servicing equipment that is important to safety is classified as essential equipment per the requirements of 10 CPR 50, Appendix A. This equipment and other equipment whose failure would degrade an essential component is defined in Section 9.1 and is classified as Seismic Category X. These components are subjected to an elastic dynamic finite element analysis to generate loadinqs. This analysis utilizes appropriate, seismic floor response spectra and combines loads at frequencies up to 33 Hz for seismic and up to 60 .Hz for the hydrodynamic loads in three directions. Imposed stresses are generated and combined for normal, upset, and faulted conditions. Stresses are compared, depending on the specific safety class of the equipment, to Industrial Codes, ASME, ANSI or Industr ial Standards,'ISC, allovables. The calculated stresses a nd allowable limits for the faulted loads for, the fuel preparation machine are provided in Table 3.9-2 (s) . The refueling platf orm has also been examined; seismic hydrodynamic events. it can withstand the faulted loads due to 3.9.1.4. 12 Seismic Cateaory I- Items Other than NSSS Por statically applied loads, the stress allowables of Appendix P of the ASNE Code, Section IXI, Winter 1972 were used for code components. Por noncode components, 'allowables vere based on tests or accepted standards consistent .with those in Appendix P of the code. I Dynamic loads for components loaded in the elastic range were calculated using dynamic load factors, time history analysis, or any other method that assumes elastic behavior of the component. The limits of the elastic range are defined in Paragraph 1323 of Appendix F for the code components. The local yielding due to stress concentration is assumed not to affect the validity of the assumptions of elastic behavior. The stress allovables of Appendix P for elastically analyzed components were used for code components. Por noncode components, allowables vere based on Re v. 31, 7/82 3 9-25
SSES-PSAR tests or accepted material standards consistent with those in Appendix F for elastically analyzed components. The methods used in evaluating the pipe break effects are discussed in Section 3.6. 3 9 2 DYNAHIC TESTING=AND ANALYSIS 3.9.2.1a Preoperational Vibration and Dynamic Effects Tempting on gSSQ pgpggg The test program is divided into three phases: preoperational
~
vibration, startup vibration, and operational transients. 3.9.2 1a.1 ~ Vibration Preooerational
~ ~ ~ W Testina The purpose of the preoperational vibration test phase is to verify that operating vibrations in the recirculation piping are acceptable. This phase of the test uses visual observation.
3.9 2.1a 2 Sma'll Attached Pioina There is no small attached piping in the NSSS scope of supply. 3 a. 9.2.1a
=== ~3 St KXtu 2 VibRKtion The purpose of this phase of the program is to verify that the main steam and recirculation piping vibration are within acceptable limits. Because of limited access due to high radiation levels, no visual observation is made during this phase of the test. Remote measurements shall be made during the following steady state conditions:
(a) Hain steam flow at 25% of rated; {b) Hain steam flow at 50$ of rated; (c) Hain steam flow at 75% of rated; (d) Hain steam flow at 100'%f rated. Rev. 31, 7/82 3 9-26
SSES-PS AR 3~9 7. QEggRgPCQS
- 3. 9-1 "Design and Performance of G.E. BMR Jet Pumps,>> General Electric Company, Atomic Power Equipment Department, AP ED-5460 i Jul y 1968
- 3. 9-2 Moen, H.H., "Testing of Improved Jet Pumps for the BMR/6 Nuclear System," General Electric Company, Atomic Power Equipment Department, NED0-10602, June 1972.
- 3. 9-3 General Electric Company, "Analytical Model for Loss-of-Coolant Analysis in Accordance with 10 CPR 50, Appendix K,>> Proprietary Document, General Electric Company, NEDE-20566
- 3. 9-4 >>BQR Puel Channel Mechanical Design and Deflection,"
NEDE-21354-P, September, 1976. 3.9-5 >>BHR/6 Puel Assembly Evaluation of Combined Safe Shutdown Earthquake (SSE) and Loss-of-Coolant Accident (LOCA) Loadings," NEDE-21175-P, November, 1976. 1
- 3. 9-6 Seismic Analysis o f Pipinq Systems, BP-TOP-1, Bechtel Power Corporation, San Francisco, California, Rev. 2, January,'975.
3 9-7 "Assessment of Reactor Internals Vibration in BMR/4 and BMR/5 Plants>>, NEDE-24057-P (Class III) and NEDO-24057 (Class I), Noveiher, 1977. 3 9-8 >>Punctional Capability Criteria for Essential Mark Piping>> ~ NFD0-21985, 78 NED'l74 (Class I), September, II 1978 Rev 31, 7/82 3 9-97
SS ES- FS AR TABLE 3-9-2.INDEX T ABLP. CONTENTS. II
- 3. 9-2 LOAD CONBINATION AND ACCEPTANCE CRITERIA FOR ASNE CODE CLASS 1i 2, "AND 3 PIPING AND COMPONENTS 3 9-2a REACTOR PRESSURE VESSEL AND SHROUD SUPPORT ASSEMBLY (i) Vessel Support Skirt
{ii) Shroud Support (i ii) RPV Feedwater Nozzle (i v) CRD Penetration CRD Housing (v) CRD Penetration Stub Tube 3 9-2b REACTOR INTERN ALS 8 ASSOCIATED EQUIPMENT (i) Top Guide - Highest Stressed Beam (ii) Core Plate (Ligament in Top Plate) (iii) Vessel Head Spray Nozzle 3-9-2c REACTOR WATER CLEANUP (REGENERATIVE 6 NON-REGENERATIVE) HEAT EXCHANGERS
\
3 9-2d ASME CODE CLASS 1 HAIN STEAN PIPING AND PIPE MOUNTED EQUIPMENT
- 3. 9-2e ASNE CODE CLASS 1 RECIRCULATION PIPING AND PIPE MOUNTED EQUIPMENT 3 9-2t NOT USED 3 9-2q MAIN STEAN SAFETY/RELIEF VALVES 3 9-2h STEAN ISOLATION VALVE
'AIN 3 9-2i R ECIRCULATION PUNP
- 3. 9-21 R EACTOR RECIRCULATION S YSTEN GATE VALVES 3 9-2k CLASS III SAFETY .RELIEF VALVE DISCHARGE PIPING
- 3. 9-21 STANDBY LIQUID CONTROL PUMP
- 3. 9-2 m STANDBY LIQUID CONTROL TANK
- 3. 9-2n ECCS PUNPS
{i) RHR Pumps (ii) Core Spray Pumps 3 9-2o RESIDUAL HEAT RENOVAL (RHR) HEAT EXCHANGER Rev. 31, 7/82
SSES-FSAR of this portion of the system is specifically exempted from the requirement for volumetric inspection by'paraqraph IRB-1220(a) of Section XI of the ASME Boiler and Pressure Vessel Code (Summer 1975 Addenda) . Regulatory Guide 1.97 INSTRUMENTATION FOR LIGHT HATER COOLED NUCLEA R POSER P LA NTS TO ASSESS PLANT CONDITIONS DURING A ND FOLLOW'K NG AN ACCIDENT
/Decem her 1975)
The accident monitoring instrumentation was designed prior to this Regulatory Guide beinq issued. The instrumentation for accident monitorinq is not specifically identified on the con.rol panels and has not been evaluated aqainst Regulatory Guide 1.97, Revision l." Safety related display instrumentation and seismic qualification will be addressed followinq issue and project resolution of Beg.. Guide 1.97 (Rev. 2) . Peaulatorv Guide 1.98 ASSUMPTIONS USED F OR EVALUAgXNG T HE POTENTI AL R ADIOLOGICAL CONSEQJJENCES OF A RADIOACTIVE OFFG AS SYSTEM PAIL UR E IN A BOILING MATER RFACTOR
/March 1976)
Subject to the clarifications or exceptions indicated below, the assumptions of. Regulatory Guide 1.98 are followed in the analyses of the o ff gas system failure in Subsection 15. 7. 1. (1)
Reference:
Position C. 4. a. Dose conversion factors are taken from the most recent data available. The average beta and qamma enerqies used are given in Section 15. 8. -{2)
Reference:
Position C.4.a. External whole-body gamma doses and beta-skin doses are presented separately, inasmuch as the dose from beta radiation to the whole body is negligible. The t.otal dose to the skin is the sum of. the beta-skin dose and whole-body dose. Regulatory Guide 1.99 EFFECTS OF RESIDUAL ELEMENTS ON PRF,DICTED RADIATION DAMAGE TO REACTOR VESSEL MATERIALS
/Revision 1 Ao".il 1977)
GF. is responds.nq to this guide under the Appendix G proqram Fracture Toughness Requirements. Rev. 32, 12/82 3~1337
SS ES-PS AR Regulatory Guide 1.100 SEISMIC'UALXFICAT.ION OF ELECTRIC EQUIPMENT POR NUCLEAR POMER PLANTS
/larch 1976}
I The implementation paragraph'of this regulatory guide states that
~
the requirements of the position statements will 'only he applied to plants that received construction permits after November 16, 1976. The Construction Permit for Susquehanna SES was issued in November 1973 and therefore the guidelines of this regulatory guide have not been utilized in- the design of this nurlear power station. Seismic qualification of the safety related electric equipment {non-NSSS scope nf supply) has been conducted in accordance with t.he TFFF. Standard 344-1971. Section 3.10 describes t he complete qualifiration methods and procedures that have been utilized. The safety-related electric equipment {NSSS scope of supply) meets IFEE 323-1971 and IEEE 344-1971. Regulatogv Chide 1. 101 - FNFRGENCY PLANNING FOR NUCLEAR PONEB PLANTS Nithd awn September 24 ~ 1980. ~ Regulatory Guide 1. 102 - PLOOD PROTECTION POR NUCLEAR POMER PLANTS (Revision 1, September 1976} The present design of the Susquehanna SES complies with the provisions of this regulatory quide. /equi.a+or@ Guide 1. 103 POSTTE NSIONED PRESTRESSZ NG SYSTENS POR CONCRETE REACTOR V ESS ELS A ND CONTAI NNENTS ggevision l~ October 1976} Not Applicable. Regii1atory ('uide 1.104 OVERHEAD CRANE HANDLING SYSTEMS POR NUCLEAR POWER PL ANTS QPehruary 1976} Subject to the clarif ications and exceptions indicated below, the safety related overhead rrane handling systems of this station comply with the provisions of this regulatory guide. {1)
Reference:
Position C. 1.b (2). The nil-ductility transition temperature for the structural steel associated with the cranes was not determined as suggested by this position. Position Rev. 32, 12/82 3 13-3 8
SSES-PSAR 5.3.1.4.1.3 Regulatory Guide 1.43, (5/73) Control of Stainless Steel Meld Cladding of Low-Alloy Steel ~Com onents Reactor pressure vessel specifications require that all low alloy steel be produced to fine grain practice. The requirements of this regulatory guide are not applicable to BMR vessels. 5.3.1.4.1.4 Regulatory Guide 1.44, (5/73) Control of the Use of Sensitized Stainless Steel Controls to avoid severe sensitization are discussed in Subsection 5. 2. 3. 4. l. l. 5.3.1.4.1. 5 Regulatory Guide 1. 50 (5/73), Control of Preheat Te~merature for Meld in@ Low-All~oSteel preheat controls are discussed in Subsection 5.2.3.3.2.1. 5.3.1 4.1.6 Regulatory Guide 1.71, (12/73) Melder
~
Qualification f~oAreas of Limited Accessibility
~
Qualification for areas of limited accessibility is discussed in Subsection 5. 2. 3. 3. 2. 3. 5-3-1.4.1.7 Regulatory Guide 1.99, (Rev. 1) Effects of Residual Elements on Predicted Radiation Damage to Reacto~r ressure Vessel Materials Predictions for changes in transition temperature and upper shelf energy were made in accordance with the requirements of Regulatory Guide l. 99. Rev. 13, ll/79 5~3 3
SSES-PSAR 5 3 1 5 Practure Toughness 5 3.1.5 l Compliance with lOCPR50 Appendix G A major condition necessary for full compliance to Appendix G is satisfaction of the requirements of the Summer 1972 Addenda to Section III. This is not possible with components which were purchased to earlier Code requirements. Por the extent of the compliance, see Tables 5. 3-1a and 5.3-2a. Perritic material complying with 10 CFR 50, Appendix G, must have both drop weight tests and Charpy V-notch (CVN) tests with the CVN specimens oriented transverse to the principal material working direction to establish the RTNDT The CVN tests must he evaluated against both an absorbed energy and lateral expansion criteria. The maximum acceptable RT DT must be determined in accordance with the analytical procedures,of ASNE Code Section XII, Appendix G. Appendix G of 10 CFR 50 requires a minimum of 75 ft-lb upper shelf CVN energy for beltline material. j:t also requires at least 45 ft-lb CVN energy and 25 mils lateral expansion for bolting material at the lower of the preload or lowest service temperature. By comparison, material, for the Susquehanna SES reactor vessels was qualified by either drop weight tests or longitudinally oriented CVN tests (both not required), confirming that the material nil-ductility transition temperature (NDTT) is at least 60oF below the lowest service temperature. When,the CVN test was applied, a 30 ft-lb energy level was used in defining the NDTT. There was no upper shelf CVN energy requirement on the beltline material. The bolting material was qualified to a 30 ft-lb energy requirement at 60oP below the minimum preload temperature'. Prom the previous comparison it can be seen that the fracture toughness testing performed on the SSES reactor vessel material cannot be shown to comply with 10 CFR 50, Appendix G. However, to determine operating limits in accordance with 10 CPR 50, Appendix G, estimates of the beltline material RTNDT and the highest RTNnT of all other material were made, as explained in Subsection 5.3. 1.5 1 2 The method for developing these operating limits is also described therein. On the basis of the last paragraph on page 19013 of the July 17, 1973, Federal Register, the following is considered an appropriate method of complaince Rev. 13, ll/79 5.3-4
SSES-FSAR - 5 3 1.5 1.1 Intent of Proposed A~roach The intent of the proposed special method of compliance with Appendix G for this vessel is to provide operating limitations on pressure and temperature based on fracture toughness. These operating limits assure that a margin of safety against a nonductile failure of this vessel is nearly the same as that for a vessel built to the Summer 1972 Addenda. The specific temperature limits for operation vhen the core is critical are based on a proposed modification to 10 CFR 50, Appendix G, Paragraph IV, A.2.C. The proposed modification and the'ustification for Repor t, EDO-21778- A. N it are given in GE Licensing Topical 5 3.1.5.1 2 O~eratinq Limits Based on Fracture Toughness Operating limits which define minimum reactor vessel metal temperatures vs reactor pressure during normal heatup and cooldown and, during in-service hydrostatic testing, were established using the methods of Appendix G of Section III Vessel Code, 1971 Edition, including the of the ASIDE Boiler and Pressure summer 1972 Addenda. The results- are shown in Figure 5.3-4a for Unit 1 and 5.3-4b for Unit 2. All the vessel shell and head areas remote .from discontinuties plus the feedwater nozzles were evaluated, and the operating limit curves are based on the limiting location. The boltup limits for the flange and adjacent shell region are based on a minimum metal temperature of RTNDT + 60O. The maximum through-wall temperature gradient from continuous heating or cooling at 100oF per hour vas considered. The safety factors applied were as specified in ASIDE Code, Appendix G, and GE Licensing Topical Report, N ED0-21778-A.- For the purpose of setting these operating limits, the reference temperature, RT NDT, is determined from the toughness test data taken in accordance vith reguirements of the Code to vhich this vessel is designed and manufactured This toughness test data, Charpy V-notch (CVN) and/or drop- veight nil-ductility transition temperature (NDT) is analyzed to permit compliance vith the intent of 10 CFR 50, Appendix G. Because all toughness testing needed for strict compliance with Appendix G was not required at the time of vessel procurement, some toughness results are not available. For example, longitudinal CVN's, instead of transverse, were tested, usually at a single test temperature of
+10oF or +40~F, for absorbed energy. Also, at the time either CVN or NDT testing was permitted; therefore, in many cases both Rev. 13, ll/79 5. 3-5
SSES-PSAR tests were not performed as is currently required. To substitute for this absence of certain data, toughness property correlations were derived for the vessel materials in order to operate upon the available data to give a conservative estimate of RQDT, compliant with the intent of Appendix G criteria. These toughness correlations vary, depending upon the specific material analyzed, and were derived from the results of WRC Bulletin 217, "Properties of Heavy Section Nuclear Reactor Steels", and from toughness data from the Susquehanna SES vessels and other reactors. In the case of vessel plate material (SA-533 Grade B, Class 1), the predicted limiting toughness property is either NDT or transverse CVN 50 ft-lb temperature minus 60<P. CVN and NDT are available for all the beltline plates. Where NDT results are missing, NDT is estimated as the longitudinal CVN 35 ft-lb transition temperature. The transverse CVN 50 ft-lb transition temperature is estimated from longitudinal CVN data in the following manner. The lowest longitudinal CVN ft-lb value is adjusted to derive a longitudinal CVN 50 ft-lb transition temperature by adding 2oF per ft-lb to the test temperature. the actual data equal or exceed 50 ft-lb, the test temperature is If derived by interpolation. Once the longitudinal 50 ft-lb temperature is derived, an additional 30>P is added to account for orientation effects and to estimate the transverse CVN 50 ft-lb temperature minus 60oF, estimated in the preceding manner. For forgings (SA-508 Class 2), the predicted limiting property is the same as for vessel plates. CVN and NDT values are available for the vessel flange, closure head flange,,and feedwater nozzle materials for Susquehanna SES. RTNpT is estimated in the same way as for vessel plates. For the vessel veld metal, the predicted limiting property is the CVN 50 ft-lb transition temperature minus 600P, as the NDT values are -50<F or lower for these materials. This temperature is derived in the same way as for the vessel plate material, except the 30eF addition for orientation effects is omitted since there is no principal working direction. When NDT values are available, they are also considered and the RTDT is taken as the higher of NDT or the 50 f t-lb temperature minus 60OP. When NDT is not available, the RT NDT shall not be less than -50OF, since lower values are not supported by the correlation data. Por vessel weld heat affected zone (HAZ) material, the RTMpq is assumed the same as for the base material as ASNE Code well procedure qualification test requirements, and post weld heat treatment indicates this assumption is valid. Closure bolting material (SA-540 Grade B24) toughness test requirements for Units 1 and 2 were for 30 ft-lb at 60>P below the bolt-up temperature. Current Code requirements are for 45 Rev. 13, ll/79 5. 3-6
SSES-FSAR ft-lb and 25 mils lateral expansion (HLE) at the preload or lowest service temperature, including bolt-up. Therefore, since CVN values as low as 40 ft-lb (with 25 mils lateral expansion) exist at the 10eP test temperature for Unit 1 closure bolts, 60eP is added to the test temperature in order to derive the bolt-up temperature of 70eP. All Unit 2 closure stud materials meet current requirements at 100P. Using the above general approach, an initial RTNDT of +18eP was l established for the core beltline region for Unit and +30oP for Unit 2. The effect of the main closure discontinuity was considered by adding 600P to the RTN~T to establish the minimum temperature for boltup and pressurization. The minimum bolt-up temperature of +704F for Units 1 and 2, which is shown on Figures 5-3.4a and 5.3-4b, is based on an initial RTNDT of- +10eF for the closure flange forgings. The effect of the feedwater nozzle discontinuities was considered by adjusting the results of a BMR/6 reactor discontinuity analysis to the reactor. The adjustment was made by increasing the minimum temperatures required by the difference between the Susuehanna SES and BMB/6 feedwater nozzle forging RTNDT 's.= The feedwater nozzle adjustment was based on an RTNDT of 16oP for Unit and an RTNDT of -10eP for Unit 2. 1 The reactor vessel closure studs for Unit 1 have a minimum Charpy impact energy of 40 ft-lbs and a 25-mil lateral expansion at 10eP. The lowest service temperature for the closure studs is 70oP for Unit 1. For Unit 2, the closure studs have a minimum Charpy impact energy of 48 ft-lb and a 27-mil laterial expansion at 10eP; therefore, the lowest service temperature for the Unit 2 closure studs is '+10eP. 5.3.1.5.1.3 Operating Limits During Heatup, Cooldown and Core Operation The fracture toughness analysis was done for the normal heatup or cooldown rate of 100oP/hour. The temperature gradients and thermal stress effects corresponding to this rate were included The results of the analyses are a set of operating limits for non-nuclear heatup or cooldown shown as curves labeled B on Figures 5.3-4a and 5.3-4b. Curves labeled C on these figures apply whenever the core is critical. The basis for the C Curves is described in GE BQR Licensing Topical Report NEDO-21778-A Rev. 13, ll/79 5. 3-7,
SSES-FSAR 5.3.1.5 1 4 Temperature Limits for Preoperational System Hydrostatic Tests and ISI Hydrostatic or Leak Pressure Tests Based on 10 CFR 50, Appendix G, IV, A.2.d, which allows a reduced safety factor for tests prior to fuel loading, the preoperational system hydrostatic test at 1563 psig may be performed at a minimum temperature of 1170F for Unit 1 and 129eP for Unit 2 which is established by the intermediate shell plate RTNDT of 20 F for Unit 1 and the core beltline plate RTNDT of 30eF for Unit 2. The fracture toughness analysis for in-service inspection or leak pressure tests resulted in the curves labeled A shown in Figures 5.3-4a and 5.3-4b. The curves labeled "core beltline" are based on an initial RTND of +18eP for Unit 1 and +30eP for Unit 2. The predicted shVZt in the RTNpY from Pigure 5 ~ 3<c {based on the neutron fluence at 1/4 of the vessel wall thickness) must be added to the beltline curve to account for the effect of fast neu tron s. 5 3. 1. 5. 1.5 Temperature Limits for Boltup A minimum temperature of 70> for Unit 1 and of 100 for Unit 2 is required for closure studs. A sufficient number of studs may be tensioned at 700P to seal the closure flange 0-rings for the purpose of raising reactor water level above the closure flanges in order to assist in warming them. The flanges and adjacent shell are required to be warmed to a minimum temperature of 70 F before they are stressed by the f ull intended bolt preload. The fully preloaded bolt-up limits are shown on Figure 5.3-4a for Unit 1 and Figure 5.3-4b for Unit 2. 5 3.1.5. 1 6 Reactor Vessel Anneali~n In-place annealing of the reactor vessel because of radiation embrittlement is unnecessary because the predicted end of life value of adjusted reference temperature will not exceed 2000F, (see 10 CPR 50, Appendix G, Paragraph IV.C) Rev. 13, ll/79 5. 3-8
TABLE 5. 3-2a APPENDIX G HATRIX FOR SUSQUEHANNA SES UNZF 2 Comply Appendix G Yes/No. Alternate Actions Pa r. No. To~le 0 N A Og QpaagBts Z~ II Introduction; Definitions IIZ A Compliance Mith ASHE Code, Yes See Subsection 5.3.1.5.1.2 for discussion. Section NB-2300 IIZ B 1 Location 8 Orientation of Yes See III.A ~ above. Impact Test Spec ZIZ B 2 Haterials Used to Prepare Test No Compliance except for CVN orientation and CVN upper Specimens shelf. III B 3 Calibration of Temp. Inst. and No. Paragraph NB-2360 of the ASHE BSPV code, Section IV, Charpy Test Hachines vas not in existence at the time of purchase of the Susquehanna SES Unit 2 reactor pressure vessel. However, the requirements of the 1971 edition of the ASHE BSPV Section III "ode, Summer 1971 addenda, vere met. For the discussions of the GE interpretations of compliance and NRC acceptance see References 1 and 2. The temperature instruments and Charpy Test Hachines cali-bration data are retained until the next recalibration. This is in accordance vith Reg. Guide 1.88 Rer. 2, GE Alternative Position 1.88, and ANSI N45. 2.9, 1974. Therefore, the instrument calibration data for Susquehanna SES Unit 2 vould not be currently available. ZII B Qualification of Testing No No vritten procedures vere in existence as required by Personnel the Regulation; however, the individuals vere qualified by on-the-gob training and past experien"e. For the discussion of the GE interpretation of compliance and NRC acceptance see References 1 anil 2. IIZ B 5 Test Results Recording and Yes See References 1 and 2. Certification IIZC1 Test Conditions See III.A, III.B.2, above. ZIZ C 2 Haterials Used to Prepare Test Yes Compliance on base metal and veld metal tests. Test Specimens for Reactor Vessel weld not made on same heat of base plate, necessarily. Beltline IV A 1 Acceptance Standard of Haterials IV.A.2.a Calculated Stress Intensity Yes Factor IV A 2 b Requirements for Nozzles, Flanges Noi Plus 60~F vas added to the RTNDT for the reactor and Shell Region Near Geometric vessel flanges. For feedvater, nozzles the results of Discontinui ties the BWR/6 analysis vere ad)usted to Susquehanna Unit 2 RT~> conditions. Rev. 13, 11/79
e TABLE 5.3-2a (continued) Page 2 Comply Appendix G Yes/No Alternate Actions Par. No T~oic 0 N A Or Comments IVA2c RPV Netal Teaperature Requirement Regulation change in process (See LTR NEDO-21778-A). When Core is Critical IV A 2 Ninimum Permissible Temp. During Yes Hydro Test IV A.3 Naterials for Piping, Pumps Hain steamline piping is in compliance. See and Valves Subsection 5.2.3.3.1 for discussions on pumps and valves. IV A 4 Naterials for Bolting and Yes Current toughness requirements for closure head studs Other Fasteners are met at 104F. IV B Ninimum Upper Shelf Energy For No upper shelf tests ran. However, recommend RPV Beltline acceptance based upon lowest longitudinal CVN's for plates at +10oF of 45 ft-lb (50% shear) for heat C2421-3 (0.10% Cu), 50 ft-lb (50% shear) for- heat C2929-1 (0.13% Cu), and 39 ft-lb (40% shear) for heat C2433-2 (0 10% Cu). Lowest CVN's for welds are 22, 30 ~ 3)., 43, 55 ft-lb (no % .shear records) at -20oF with 0. 06% Cu. The scatter in energy data at -20oF indicates transition behavior and the probability that upper shelf is in ercess of 50 ft-lb (for 100% shear) . End-of-life upper shelf values (100% shear) are predicted to be in ezcess of 50 ft-lb, based upon preceding data and Regulatory Guide 1.99. IV~ C Requirement for Annealing N/A When RT 200oF Requirements for Naterial See Surveillance Program App H V B Conditions for Continued Yes See Sections 5.3 1.5.1.1 ~ 5.3.1.5.1.. 2, 5.3.1.5.1.3, 5.3.1.5.1.4, Operation 5. 3.1.5.1.6 ~ 5. 3.1.6 and Table 5.3-2b V C Alternative Satisfied If V.B Cannot Be V D Requirement For RPV Thermal N/A Annealing Net If V.C Cannot Be V E Reporting Requirement For N/A V.C and V.D Referen"es
- 1. Letter (NRC)
NFN-414-77 dated October
'. 17 G. Sherwood
'977.
(GE) to Edson G. Case Rev. 13, 11/79
TABLE 5.3-2a (continued) Page 3 Comply Appendix G Yes/No Alternate Actions ~ra so T~oic Or I A Or Coaaents
- 2. Letter, Robert B..Hinogue (KRC) to G. G. Shervood (GE) dated Pebruary 10, 1978.
Rev. 13, 11/79
700 GENERAL ELECTRIC SURVEILLANCE PROGRAM 650 TEST RESULTS Q'NPS BASE METAL DNPS WELD METAL DNPS HAZ O BIG ROCK BASE METAL 550 BIG ROCK -WELD METAL BIG ROCK HAZ (] HUMBOLDT HAZ 500 (Im HUMBOLDT WELD METAL IL 0 [) HUMBOLDT BASE METAL I-I- 450 Ill CC D I-K lU lU I-z 0 350 I-V) z CC I- 300 8 UPPER LIMITFOR 550 F GE BWR 0 O OPERATING EXPERIENCE z UJ 250 Q z xO 150 o 0+ e e an 0 50 101 10 IP18 1019 IP20 102'NTEGRATED NEUTRON DOSAGE (> I MeVI (ct), nvt SUSQUEHANNA STEAM ELECTRIC STATION UNITS 1 AND 2 FINAL SAFETY ANALYSIS REPORT CHANGE IN CHAIRPY V TRANSITION TEMPERATURE VERSUS NEUTRON EXPOSURE FIGURE 5. 3-5
0 SS ES-FS AB inst umentation and control systems and no discussion is provided. b) Non-NSSS Refer to Subsection 3.11.2b.2 and Section 3 13. 7,1.?,6,9 Conformance to Qequlatory Guide 1.47 $ 5/73} NSSS The system of bypass indication is designed to satisfy the requirement of 'IEEE 279-1971 paraqraph 4.13 and Regulatory Guide 1. 47 and is discussed f or each sa f et v- related system under Sections 7. 2, 7. 3, 7. 4, and 7.6. The desiqn of the bypass indication system allows te .ting durihq normal operation and 'is used to sunDlement adminis+rative procedures by providing indications of safety systems status. H The bypass indication system is designed and installed in a manner which precludes the possibility of adverse affects on the plant. safety system. The bypass indication system is electrically isolated from the protection circuits such that the failure or bypass of a protective inunction is not a credible consequence of failures in the bypass indication system and the bypass indication system cannot reduce the independence between redundant safety systems. h) Non-NSSS Refer to individual systems in Section 7. 3 and discussion in Section 7.5
- 7. 1.2.6. 0 Conformance to Regulatory Guide 1.53 f6/7 3l a a) NSSS The safety-related system designs conform to the single failure criterion. The analysis portions of Sections 7.2, 7.3, 7.4 and 7.6 provide further d iscu ssion.
h) Non-NSSS Refer to Section 3.13 7.1.2.6.11 Conformance to Regualtory Guide 1.62 $ 10/73) a) NSSS Manual initiation of the protective action is provided at the system .level in the Reactor Protection Svs+em, (primary) Containment and Reactor Vessel Tsolation Control System and Hmerqency Core Coolinq Rev. 32, 12/82 7. 1-45
SSES-FS AR System.".. The analy is portions of Sections 7.2 and 7.3 provide f urther discussion. h) Non-NSSS Refer to Section 3.13. 7.0 1.2. e ~ 6.0 12 ConFormance to Regula tory Guide 1 63 (10/73) a.) NSSS Ro..qulatory Guide 1. 63 applies to elect ical penetration assemblies which are not part of NSSS scope. h.) Non-NSSS Refer to Section 3. 13.
- 7. 1.2.6.13 Conformance to Regulatory Guide j.68 $ 11/73}
Ref er to Section 3. 13.
- 7. 1.2. 6. 14 Conformance to Regulatory Guide 1.70 QRev. 2}
The format and content of Chapter 7 conform to the requirements of Requlatory Guide 1.70. Ref er to Sect.ion 3.13. 7.1.2.6.16 Conformance to Regggagogy Ggide 1.75 $ 1/75} a) NSSS Regulatory Guide 1.75 is not applicable to Susquehanna SES: however, degree of compliance to separation criteria of IEEE 384 is discussed in Subsection 7.1.2.5.8. b) Non-NSSS Refer to Section 3.13 and Subsection 8.1.6.1, Paraqraph n.
- 7. 1 g 2.6 g
~ 17 Conformance to Regulatory Guide 1.80 (6/74) a) NSSS Requlatory Guide 1.80 applies to the testing of instrument air systems which are not part of the NSSS scope o Rev. 32, 12/82 7. 1-46
SS ES- FS AR b) Non-~SSS Refer to Section 3. 13. 7.1.2.6. 18 Conformagcp to Regulatory Guide 1.89 $ 11/74) a) NSSS See the Susquehanna SES Environmental Equipment Qualification Program. b) Non->! SSS Refer to Section 3.13.
'I
- 7. 1.2. 6. 19 Conformance to Regulatory Guide 1. 96 $ 5g75}
Main Steamline Tsolation Valve Leakage Control System is designed +o the requirements of Regulatory Guide 1.96. Further discu.ssion is provided in Subsection 7.3.2a.3. 7.1.2.7 Technical Design Bases The technical desiqn bases for RPS are in Subsection 7.2. 1, tor engineered -.a fety features .in Subsection 7.3.1, for systems required for safe shutdown in Subsection 7.4.1, and for other systems req>>ired for safety in Subsection 7.6.1. 7.1.2.8 Safety System Settings The safety system setpoints are listed in the Technical Specifications. The settings are determined based on operating experience and conservative analyses. The settinqs are high eno>>qh <<o preclude inadvertant initiation of the safety action, hut low enouqh to assure that significant margin is maintained between the actual settinq and the limitinq safety system settings. Tnstrument drift, setability and repeatability are considered in the setpoint determination (soe Subsections 7.1.2a.4 and 7.1.2b.4). The margin between the limiting safety system settings and the actual safety limits include consideration of the maximum credible transient in the process beinq measured. The periodic test frequency for each variable is determined from <<xperimental data on setpoint Grift and from quantitative reliability requirements for each system and its components. Rev. 32, l2/82 7. 1-47
SSES-PS AR equipped for automatic depressurization are identical. Ten additional safety/relief valves providing only the SRV function are discussed in Subsection 7.7.1.12. 7.3.1.1a.1.4.2 Eguipmept Design The control system consists of drywell pressure and reactor water level sensors arranqed in trip systems that control two solenoid-operated pilot air valves )one for each ADS system) for each safety relief valve. Each of these two air valves controls pneumatic pressure for safety relief valves actuation. (A third solenoid-operated pilot air valve with each safety relief valve is used for the Relief Valve function. See Subsection 7.7.1.12 for details of Relief Valve control.) An accumulator is included with the control equipment to store pneumatic energy for safetv/relief valve operation. The accumulator is sized to provide air for five actuations of the ADS piston type pneumatic actuator via the solenoid valves, following failure of the pneumatic supply to the accumulator. Cables from the sensors lead to the control structure where the loqic arrangements are formed in cabinets. The electrical control circuitry is powered by dc from the plant batteries. The power supplies for the redundant control circuits are selected and arranged to maintain trippinq ability in the event of an electrical power circuit failure. Electrical elements in the contxol system energized to cause openinq of the safety/relief valve. 7.3 1.1a.1.4.3 Initiating Circuits The pressure and level switches used to initiate one ADS logic are separated from those used to initiate the other logic on the same ADS valve. Reactor vessel low water level is detected by six switches that measure differential pressure. Primary containment hiqh pressure is detected by four pressure switches, which are located outside the primary containment and inside the reactor buildinq. The level instruments are piped individually so that an instrument pipeline break will not inadvertently initiate auto blowdown. The primary containment high pressure signals are arranged to seal into the control circuitry; they must be mapually reset to clear. A timer is used in each ADS logic. The time delay -setting before actuation of the ADS is long enouqh that the, HPCI system has time to operate, yet not so long that the LPCI and CS systems are unable to adequately cool the fuel if the HPCI system fails to start. An alarm in the main control room is annunciated when either of the timers is timing. Resetting the ADS initiating signals recycles the timers. R EV 30, 5/82 7&3 1 3
SS ES- FS AR 7.3.1 1a.1.4.4 Logic and Sequencing Three initiation siqnals are used for the ADS. namely, reactor vessel low water level, drywell hiqh pressure, and RHR and/or CS pumps runninq. All signals must be present to cause the safety/relief valves to open, as shown in Pigure 7.3-5. Reactor vessel low water level indicates that the fuel is in danger of becoming uncovered. The second (lower) low water level initiates the ADS. Primary containment high pressure indicates a breach in the RCPB inside the drywell. A permissive signal indicating LPCI or CS pump discharge pressure is also required. Discharge pressure on any one of the RHR pumps or either pair of the CS pumps (ABC) or (BGD) is sufficient to give the permissive signal, which permits automatic depressurization when the LPCI and CS systems are operable. After receipt of the initiation signals and after a delay provided by timers, each of the pilot qas solenoid valves is energized. This allows pneumatic pressure from the accumulator to act on the qas cylinder operator. The gas cylinder operator holds the relief valve open. Lights in the main control room indicate when the solenoi d-operated pilot valves are ener gized to open a safety/relief valve. Manual reset circuits are provided for the ADS initiation signals. By manually resettinq the initiation signal the delay timers are recycled. The operator can use the reset push buttons to delay or prevent automatic opening of the relief valves if such delay or prevention is prudent. Control switches are available in the main control room for each safety/relief valve associated with the ADS. The OPEN position is for manual safety/relief valve operation. Two ADS loqics trains are provided as shown in Figure 7.3-8. Division I sensors for low reactor water level and high drywell pressure initiate ADS A (logics A 6 C), and Division II sensors initia te ADS B (loqics B 6 D) . One o f the two solenoid-operated pilot air valves associated with each safety relief valves is controlled by ADS A and the other is controlled by ADS B. The reactor vessel low ~ater level initiation setting for the ADS is selected to depressurize the reactor vessel in time to allow adequate coolinq of the fuel by the LPCI system or CS system followinq a LOCA in which the HPCI system fails to perform its function adequately. The primary containment high pressure setting is selected as low as possible without inducing spurious initiation of the automatic depressurization system. This provides timely depressurization of the reactor vessel fails it if the HPCI system fails to start, or after successfully starts followinq a LOCA. R EV. 30, 5/82 7. 3-14
SS ES- FS AR 7 3.1.1h.8.1.5 Supporting Systems The ESSW pumphouse HVAC system described in Subsection 9.4.8 is a supportinq system to the emergency service water system. 7.3.1.1h.8.1.6 ESW Instrumentation Not Required for Safety Non-safety related instrumentation in the control room includes: a) ESW pump A/C discharge header temperature (loop A) b) ESW pump B/D discharqe header temperature (loop B) c) Diesel qenerator A cooler outlet temperature d) Diesel qenerator B cooler outlet temperature e) Diesel generator C cooler outlet temperature f) Diesel qenerator D cooler outlet temperature q) ESW loop A (B) flow (recording) Refer to Section 7.5 for instrument ranges, accuracy, and panel j.ocation for the above mentioned instruments. Control room annunciators are not required for safety, but alert the operator of abnormal process conditions. The following alarms are in the main control room: a) Spray pond low level b) ESSW structure flooded c) ESW loop low flow d) Diese 1 generator coolers hiqh outlet temperature e) Diesel qenerator rooms flooded 7.3.1.1b.8.2 RHR Service Water System Instrumentation and Controls The description, the design basis and the safety evaluation of the RHR service water system are in Subsection 9.2.6. REV. 30, 5/82 7 3-89
SS ES-PS AR The controls and instrumentation for the RHR service water system are designed to provide adequate information to the control room operator for control and monitorinq of the system during system operatinq modes. Capability f or test and calibration is provided as descr ibed in Subsection 7. 3. 2b. 2-4. 10. 7.3.1.1b.8.2.1 Iqitiagjon Circuity The RHR service water system can be manually initiated from either the main control room or the remote shutdown panel.
- 7. 3. 1. 1b. 8. 2,2 Logic~ Bypasses~ Interlocks~ and Seguencing The BflR service water system control logics are designed using electromechanical relays and control switch signals to actuate the equipment.
7.3. 1. 1h.8.2 2. 1 Loaic Power Source The BHB service water system loqics are powered from two independent divisionalized 125 V dc Class 1E power sources. Refer to Section 8.3 for description. 7.3. 1 1h.8.2.2 2 Pumo Control Loaic For documentation of the loqic, refer to electrical schematic diagram E-150 which was submitted under separate cover. Each BHBSR pump can be started from the ma in control room, or one can be started from the unit remote shutdown panel (1B/2A) and the other (1A/2B) from the unit switchgear. In order to start any BHBSM pump the followinq conditions must be satisfied: a) Power supply bus voltage is available b) Control switch is turned to pump run position Any of the followinq conditions trip the circuit breaker to the pump motor: a) Manual stop by operator in main control room or at the remote shutdown panel (or local circuit breaker control switch at the switchqear) BEV. 30, 5/82 7. 3-90
SSES-PSAR e) RHR service water radiation monitorinq (refer to Section
- 11. 5) f) Spray pond temperature q) Computer inputs for process monitoring h) Annunciator system All instrument data and ranqes for the RHR service water system are listed in Section 7.5.
7.3.1. 1b.8 3 Containment Instrument Gas System Instrumentation and Control The containment instrument qas system is. described in Subsection 9.3.1 5 and qives the desiqn basis, system operation, and safety evaluation. The two redundant sets of high pressure nitrogen storage bottles are designed as an ESF auxiliary supporting system to provide the necessary compressed qas for the operation of the main steam relief valves for auto depressurization (ADS) . Containment isolation of the instrument qas system is described in Subsection 7 3.1. 1b. 1.. Capability for testing is provided when testing containment isolation and further described in Subsection 7. 3. 2b. 2-0. 10.
- 7. 3. 1. 1b. 8. 3. 1 Initiative@ Logic and Inter locks A pressure sensinq transmitter is located in piping headers ASB leading to the ADS relief valves.
A signal from an electronic switch automatically opens the isolation valve of the nitrogen storage bottles if the normal supply pressure is not available from the gas compressors. A signal from containment isolation also initiates the automatic opening of the nitrogen storaqe isolation valve. The manual control of the outboard isolation valves allows the operator, after determining that adequate supply pressure is available from the compressors, to open the normal supply line to the ADS relief valves. This operation will isolate the instrument qas storage bottles. However, low instrument gas header pressure will automatically override this interlock to ensure the necessary qas supply. REV 30, 5/82 7. 3-93
SS ES-PS AB Refer to electrical schematic diagram E-172 which was submitted under separate cover. The loqic power supply for containment isolation valves is divisionalized from a 125 V dc Class 1E bus. The instrument panel supply is provided by a 120 V ac Class 1E source to 120 V ac/24 V dc power supply. 7 3. 1,1b.8. 3 2 Bgpasseg~ Interlocks and Sequencing The system is not designed with bypass capability. Sequencing is not applicable for this system. This system is not interlocked with other systems. 7 3.1.1h.8.3 3 Redundancy Instrumentation and controls are provided on a one-to-one basis with the mechanical equipment. 7 3.1.1h.8.3.4 Containment Instrument Gas Instrumentation Not Requj,ged for Safety The instrumentation application discussed in Subsection 9.3.1.5.5 describes the monitorinq instruments and controls for*the gas compressors and its controls. The monitorinq instruments in the auxiliary support system are not safety-related. Each train of qas bottles has a low header pressure alarm in the main control room. The isolation valve position is indicated by status lights on the main control room panel'. Refer to Table 7.5-7 for listing of instrumentation for the containment instrument qas system. 7.3 1.1b.8.4 ~ Standby Power System Descriptions of the standby power system and supporting system can be found in the following: a) Refer to Subsection 8. 3. 1 for description of the diesel generators. Refer to Section 7.6.1b 3 for NSSS to non-VASSS diesel initiation signal. BEV 30 '/82 7. 3- 94
Division 1 Pump Permissive CS RHR RHR CS RHR RHR PUMP PUMP PUMP PUMP PUMP PUMP A A C C A C AND START ADS Rev. 1,8~ ll/80 SUSQUEHANNA STEAM ELECTRIC STATION UNITS 1 AND 2 FINAL SAFETY ANALYSIS REPORT INITIATION LOGIC ADS > CS > RHR (SHEET 2) FIGURE 7~3
~
SSES-PS AH Tndicatinq Lamps (1) Storaqe- tank heaters AGB status 7.4.1.2.5.3 Set points ~ The SLCS has set points for the various instruments as follovs: The injection valve position switches are adjusted to indicate the valve is fully open.
'k, (2) Loss of- continuity activates the annunciator below the trickle current that is observed when both primers of an explosive valve are new.
The h iqh a nd low sta ndb y liquid .temperature s ~itch is set to activate the annunciator at temperatures of 1100 P and 70~ P, respectively. (4) The hiqh and lov standby liquid storage tank level switch is set to activate the annunciator when the l.ovel is approximately 94% and 89'%f the storage tank capacity respectively. (5) The thermostatic controller is set to turn on the operatinq heater vhen the standby liquid temperature drops to 75~P and to turn off the heater at 85~P. 7.4.1.3 RHHS/Reactor Shutdown Coolinq Node-Tnstrumentation hand Controls 7.4. 1.3. 1 System Identification
- 7. 4.1. 3. 1. 1 punrtion The shutdown 'oolinq mode of the RHR System (including the reactor vessel head spray) used during a normal reactor shutdovn anR cooldovn is the non-safety portion of the RHRS The shutdovn cooling mode utilizes most of the safety classified portions of the RHRS.
The initial phase of a normal HCPB cooldown is accomplished by routing steam from the reactor vessel to the main condenser vhich serves as the heat sink. Hev. 30, 5/82 7. 4-15
SS ES- FS AR V The Reactor Shutdovn Cooling System consists of a set of pumps, valves, heat exchanqers, and instrumentation designed to provide decay heat removal capability for the core. The system snecif ically accomplishes tlie folloving: (1) The reactor shutdown cooling system is 'capable of nrovtdinq coolinq for the reactor during shutdovn operation after the vessel pressure is reduced to approximately 135 psig. (2) 'The system is capable-of cooling the reactor vater to a temperature at, vhich reac+or refuelinq and servicing can be accomplished. The system is capable of diverting'art. of 'he shutdown flow to "a nozzle in the reactor vessel head to condense the steam generated from the hot walls of the ves.,el while it is being flooded. The system can accomplish its design objectives by a preferred means hy directly extracting reactor vessel vater from the vessel via the rerirulation loop B and routing it to a heat exchanger and bark to the vessel, or by an alternate means by indirectly ex+ractinq the water via relief valve discharge lines to the s>>ppres..ion pool and routinq pool water to the heat exchanger and back to the vessel.
- 7. 4. 1. 3. 1. 2 -
Classif ication Electrical components for the Reactor Shutdown Cooling Node of the Residual Heat Removal System are classified as Safety Class 2 and Seismic Cateqory X. 7.4.1. 3. 2 Power Sources This system utilizes standby pover sources, since the RHRS has safety modes of operation (e. g., LPCX) connect'ed to= this ! equipment.
- 7. 4. 1. 3. 3 Fa>>igment De."ign
- 7. 4. 1. 3. 3. 1 general
\
The reactor water is cooled by taking suction f rom one of the recirculation loops; the water is pumped through the system heat Bev. 30, 5/82 7. 4-16
SS ES- PS.AB 7-5 SAFETY RELATED DISPTAY INSTRUNENTATION gSRDXL
~
Safety Related Display Instrumentation (SRDI) required for safe functioninq,of the plant duzinq normal operating and. accident ronditions is incorporated in a control zoom complex named the Advanced Control Room (ACR). It is necessary to consider the ACR as a vhole to verify conformance to the requirements. The ACR is a complex of ma]or components, provided vith the NSSS, ~ for monitor'inq and controllinq tvo units and providinq safety functions. The entire complex consists .of the Power Generation Control Comple(x (PGCC) in the upper relay room at the 754 ft 0 in. level .and the lower relay room at the 698 ft 0 in. level, the plant computer system at the 698 ft O,in. level and the plant-operator interface at the 729 ft 0 in. level. a) PGCC, The PGCC provides support and interconnections to'he systems panels of the upper and lover relay rooms and computer room of the ACR complexe The plant-
'he o'perator interface noted belov is not mounted on PGCC, hovever, all" other principles of the PGCC concept, eg, separation, are used.
b) Plant-operator Interface Nalor romponents are in the main control zoom arranged 1 as shown on Figure 7.5-1. and include the folloving: Unit OPerating Benchboard Panel (C651/812-P680) - houses controls, hardvired displays, the control rod position display and process displays vhich are computer qenerated from the plant computer system described belov and in Section 7.7. The combination of displays on this panel and panel (C652/H12-P678), Standby, Information Panel ~ are arranqed by system and are used, for start up, normal operation, and shut down'., See Section 7.7 for a description of the Display Control System (DCS). s Standby Information Panel (C652/H12-P678) houses hardvired indicators and recorders required to start up, run, and shut down the plant. :It is a hardwired backup to .the DCS. See below and Section 7.7 for.DCS description. Beactor Core Cooling System Benchboard (0601/H12-P601) houses hardvired 'indica'tors, recorders, manual controls,' and. annunciators for ESF systems including containment atmosphere systems. R EU. 30, 5/82 7.. 5-1
SSES-FSAR Unit Services Benchboard (C668/812-P870) - houses
'hardvired i'ndicators, recorders, annunciators and controls for unit BOP system's functions vhich do not require., the operator's immediate attention during normal operation of the power plant. Functions on this panel have. been determined to be long time response functions.
Plant Operatinq (Common Plant} Benrhboard (C 653/812-P853) - houses hardvired indicators, recorders, controls and annunciators for systems common to both units. Manual controls for the diesel generators are located here. It also houses tvo CRTs connected to the plant computer system. Unit Monitoring Console {C684/C92-P628) - provides the unit operator with sit down surveillance of the unit operating benchboard. and access to DCS and Performance Ionitoring System CRT displays vith the use of a selection .keyboard. Pla nt Monitorinq Console (C683/C92-P627) - provides sit down surveillance of both units and keyboard access to computer functions of both units. There is also computer qenerated trend recording of variables from either unit. Panels vhich support the primary plant-operator interface are mounted in back rows of the main control room and,on PGCC floor modules on floors above and belov the main control room. The annunciator system is a hardwired system which provides the operator vith the alarm information required for unit operation, startup, and shutdown. This system is independent of the plant computer system, is not part of the SRDI, and is not Class 1E. " c) Plant Computer System The Plant Commuter System is divided into the Display
.Control System {DCS) and the Performance Monitoring Systems {PMS). The DCS is the system primarily used for monitoring unit operation by generating graphic displays to optimize operator surveillance. The PNS is a supporting system capable of displays, NSSS and BOP calculations, historical recording, data logging and off-line capabilities. The PMS and DCS are. not part of the SRDI and are not Class 1E.
The DCS makes use of redundant computers vhich are both updated vith current information. Either computer may be automatically or manually svitched into operation thus maximizing availability. BEV. 30~ 5/82 7. 5-2
e SSES-FSAR l.,c )
~
7.5.-1b.7..1. .System Descgi~jon ih k The primary control method, is'dministrative control which is exercised; by. the unit control room operator; hovever, these administrative controls are supplemented by an automated Bypass System. (BIS) .: Restricted access to va rious in-plant ',Indication areas is also used to supplement the administrative control. The BIS indicators annunciate, on .the Reacto'r Core Cooling System benchboard in the control'o'om, automatically', at the system level, indicates the bypass or deliberately induced inoperability ) of. a safety related system. The BIS is provided with the capability 'for manual initiation of each system-level indicator.'.'his manual-entry- method is used to cover system components that 'have not been provided with automatic BIS input capability. 'Phe Bypass Tndication System for'on-NSSS,Systems
~
consists of the f ollowinq: a) me indicator lanp boxes each consistinc'of nxd array of lights and. located in the, control room on the Reactor i Core Coolinq System benchb'oard. Each: window, dual lamps and an integral pushbutton for lamp provided'ith test, wi.ll indicate a system-level bypass. b) Tvo annunciator windovs, located above the lamp box assemblies, will alert the operator that a system-level bypass has occurred.. c) The'ndication of" the bypass status of components, systems, channels, and/or. divisions is provided on a backrow- panel'n the main control room'. 'This panel contains the hardware logic required to translate the combination of component bypasses that constitute system
'bypasses.
A manual control, switch for each safety system enables the operator tn indica'te a system s inoperability vhenever a component vhich is not included in the automatic indication system is deliberately bypassed. The BIS and its logic can, be tested by depressing test pushbuttons. The follovinq systems provide inputs to the Bypass Indication System: Emergency. service vater system "Diesel generator control system REV. 30, 5/82 7. 5-11
SS ES-PS AR Diesel generator output system Diesel generator auxiliary system Control 'room habitability system Standby gas treatment system Battery room exhaust system RHR service water system Remote shutdown panel Containment instrument gas system Containment hydrogen recombiner system Containment isolation system Drywell ventilation svstem Reactor building emergency switchgear and motor control center cooling Table 7.5-8 identifies the system and components of the automatic Bypass Tndicat'ion'ystem. 7.5.2a Analysis of-NSSS Safety-/elated Displays 7.5.P a. l C'ene~al The safety-related display instrumentation provides adequate information to allow the reactor operator to perform the necessary manual safety function. f All protective actions required under accident conditions for the NSSS equipment are automatic, redundant, and decisive such that immediate reactor operator information or intervention is unnecessary. The ACR design improves the availability of the plant by providinq the operator with more readily accessible information and control of the various plant operational parameters. This is accomplished by the logical organization of functional plant svstem indicato s, displavs, controls arid- a computer display system+ A complete description- and analysis of design criteria applicable to the hard-wired indicators, disp'1.ays and controls for the various safety-related svstems are described elsewhere in Chapter 7 with the systems they serve. Redundancy and independence or diversity are provided in all of those information systems:which are used as a basis for operator-controlled safeguards action. A complete failure of the Display Control System which serves as an active part of the operator/plant interface does not degrade
+he quantity or guality of necessary information presented by
. hard-wired devices needed to determine the status or action of plant safety systems.
- 7. 5-12
SS ES-PS AR 7.5.2h.5 Analysis of the Bypass Indication System The Bypass Indication System (BIS) indicates on panel (C601/H12-P601) that any non-NSSS ESP or ESF supporting system is inoperable. That is indication o inoperability at a system ,level. Indication of component inoperability within the non-NSSS ESP systems is provided on panel C694. Both panels are located in the'operator interface ring of panels. Table 7.5-8-lists the systems,and components included in the system. manual capability for testing operability of each indication is provided. The system design maintains the divisionalized structure of the ESF and signals to the BIS are mechanically and electrically isolated from the associated ESP system. Regulatory Guide 1.47 and Branch Technical Position EICSB 21 are complied with in the design of BIS. REV. 30, 5/82 7. 5-23
SSES- FSAR Table 7.5-7 SAPETY RELATED DISPLAY INST RVNENTATION CONTAINNENT INSTRVNENT GAS SYSTEN No. of Type of Panel Pover Parameter Neasured Channels Range Accuracy Readout Location No. IE Bus RPS ESF AS PPD Remarks Instrument Gas 0-180 t 2% Ind CR C601 no Pressure to Nain Psig Steam Relief Valve Instrument Gas Supply 1 0-100 a 2% Ind CR C601 no Pressure Psig Instrument Gas LT CR C601 yes Bottles Isol Vlv Status Instrument Gas Suction 2 LT CR C601 yes IB/OB Isol Vlv Status Instrument Gas Contain- 9 LT CR C601 yes ment IB/OB Isol Vlv Status Note: PAN = Post Accident Nonitoring; RSP = Remote Shutdovn Panel; RPS = Reactor Protection System; ESF = Engineered Safety Peature; AS = Auxiliary Support; PPD = Plant Process Display
SS ES-PS AR pressure switches actuating on low pressure. Additionally, differential pressure of the common steamline (Piqures 5. 4-13, 6.3-1a and 6.3-1b) is monitored by" differential pressure indicating switches to detect HPCI line break. Annunciation is provided in the main control room. These monitoring systems are described in Subsections 7.6.1a.4.3.9.3 and 7.6.1a.4. 3.9.4. 7.6.1a.4.3.6 Reactor Matey Clean-Up System Leak Detection See Subsection 7. 3. 1. 1a. 2. 4. 1. 9.
- 7. 6. 1a.4.3. 7 Safegygpelief Vague Leak Detection 7.6 1a.4.3.7.1 Subsystem Iden tification Normally, the safety/relief valves are in the shut tight condition and are all at about the same temperature. Steam passage throuqh the valve= will elevate the sensed temperature at the exhaust, 'causing an ~'abnormal" temperature reading on the recorder. Switch contacts on the recorder, adjusted to actuate at a predetermined set point, close to complete an annunciator circuit. Safety valve operation usually occurs only after elief valve actuation. Leakaqe from a valve is usually characterized by a temperature increase on a single input. As discussed in Subsection 18. 1. 24. 3, each of the sixteen safety/relief valves are provided with a safety grade accoustic monitoring system to detect flow through the valve.
7.6.1a.4.3.7.2 Safety/Relief Valve Discharge Line Temgegatug~ Nonitorinq 7.6.1a.4.3.7.2.1 Desggiptj,on A temperature element (sensor) is placed in the discharge pipe of each of the sixteen (16} safety/relief valves for remote indication of leakage. The outputs of the temperature elements are sequentially sampled and recorded by one common temperature recorder. Each temeprature element .is compared against a set point valve which if exceeded will be annunciated by one common anunciator. Thus, when the annunciator sounds, it is possible to ascertain -which specific valve (s) may be leaking by observing the recorder print-out. Rev. 31, 7/82 7.6-15
SS ES- FS AR
- 7. 6. 1a.~ 4.3.
~ m 7. 2 ~ 2 ' Loaic a nd Seauenc a inaa No action is initiated by the safety/relief valve temperature monitoring circuit.
7.6.1a.4.3 7.2,3 BIpasgeg and Ipterlocks There are no bypasses or int'erlocks associated vith this subsystem. 7.6. 1a.4.3.7.2.4 Redundancy and Diversity No redundancy or diversity is required for this system. 7,6 1a,4.3,8 Reactor Vessel Head Leak Deflection
- 7. 6. 1a. 4. 3. 8. 1 ~
Subsystem Ident'.'fication A pressure betveen the inner and outer head seal ring will be sensed by a pressure switch. If the inner seal leaks, the pressure indicatinq svitch vill monitor the pressure. The plant vill continue to operate vith the outer seal as a backup and the inner seal can be repaired at the next outage when vill If the head is removed. both the inner and outer head seals leak, the leak be detected by an increase in drywell temperature and pressure. 7.6 1a.4.3.8,2 Head Sea/ Igtegpity Pressure monitoring
- 7. 6. 1a. 4. 3. 8. g. 1 Circuit prescription t
A pressure indicating switch will monitor the pressure betveen the inner and outer head seals. Rev. 31 '/82 7 6-16
SSES-FS AR Each system provides a continuous, isolated signal to the remote shutdown panel {RSP) which does not require any transfer action in the Control Room. Two indicators are provided at each RSP and are divisionalized. The Primary Containment and suppression pool temperature elements and temperature indicators will be qualified. to operate following a DBA ~ I 7.6.1b. 1.2. 3 Power Sources f The safety related instrumentation is powered from divisionalized power sources. I Division Class IE bus (120 V ac) powers Loop A, Division II Class IE bus (120 V ac) powers Loop B.
- 7. 6. 1b. 1. 2. 4 Eguipment Design 7.6.1b.1.2.4.1 Eguipme))t Design-Containment Temperature Four dual element RTDs per redundant system are located in the primary containment to sense the temperature at the followinq eleva tions:
a) Reactor pressure vessel head h) Upper platf orm c) Lower platform d) Drywell (below reactor pressure vessel).. Two redundant temperature elements monitor the suppression chamber air space temperature. The selected location for the temperature sensors helps the operator to define the area of the heat source within the primary containment. The siqnal from the RTD elements is amplified by electronic temperature transmitters to drive meters, recorder channels, and alarm switches in the control room. Two redundant indicators, for the primary containment are located in the main control room. The initiating contacts for the high speed start of the drywell cooling fans (refer to system description in Section 9.4) are derived from the two redundant Rev. 31 ~ 7/82 7 6-41
SS ES- PS AR temperature sensinq elements located in th'e service area of the fans. If high temperature is detected the electronic switches will initiate the lov speed operation of the dryvell cooling fans. Electronic signal converters vith full electrical input-output isolation are placed betveen safety related instrumentation and the input channels to the recorders. Tvo redundant multipoint recorders for the primary containment pool temperature monitoring provide a permanent history of all BTD measurements to the system operator in the control room. Each temperature sensing circuit is equipped with alarm svitches and initiate one control room alarm per redundant channel. One temperature indicator for the primary containment is located on the remote shutdown panel. Refer to Subsection 7.4.1.4 for system description. Instrument ranqes are defined in Section 7.5. 7.6.1b.1.2.4,2 Eguipment. Design-Suppression Pool Temperature The suppression pool temperature is monitored by tvo redundant systems, each of which performes as described belov. Eight RTD~s per redundant system are located in the suppression pool approximately six inches below the minimum pool water level. These sensors are located around the pool in order to provide a good spatial distribution of pool temperature. Refer to Table 7 6-9 for the exact location of these sensors. The siqnals from the sensors are processed by an electronic unit located on a main control room back panel. This electronic unit converts the RTD siqnals into deqrees Fahrenheit and computes the average of the eight temperatures. If one of the RTD's fails, an error alarm is qenerated, and the failed RTD may be removed from the calculation of the average by operator a'ction. The average value is displayed by digital indicators located both on the electronic unit, the main control board, and a vertical meter located on the RSP. A keyboard allovs the operator to display any individual temperature input. A high temperature alarm is generated by comparing the average temperature to several internally stored setpoints. The alarm condition is displayed by status lights located both on the electronic unit and on the main control board. Electrically isolated ouptuts interface vith an annunciator located on'the main control board. Rev. 31, 7/82 7 6-42
SSES-PShR TIIPQP 7~6-5 KPE5 sXsgg)) Xgrpsc>> XBXR Z95GXXQ)I- TBXR RQXEX EEKK EHXQE hPRH dovnscale 2% to full scale Rod block, annunciator vhite light display APRll upscale Setpoint varied vith flov, Rod block, annunciator (high) slope adjustable, intercepts anber light display separately adjustable ~hPRN upscale 2% to full scale Scraa, annunciator, red fhigh-high) light display aPRE Calibrate svitch or too Scraa, rod block, inoperative fev inputs annunciator, red light display hPRh Bypass manual Svitch %hite light See plant Technical Specifications for setpoints. R EV 30, 5/82
SS ES- FSAB eva luation of core thermal limits with subsequent modif ication to
+ he LPRN ATS based on the new reactor operating level. Execution of these rapid computations does not exceed 3 minutes and yields ATS values that are conservative with respect to the more accurate periodic power distribution calculation, which requires approximately 10 minutes to execute. This range of surveillance and the rapidity with which the computer responds to reactor chanqes permit more rapid power maneuverinq with the assurance +hat +hermal operatinq limits will not be exceeded.
Flux level and position Bate from the traversing in-core probe (TIP) equipment are read into the computer. The computer revaluates the data and determines gain adjustment factors by which +he LPRN amplifier qains can be altered to compensate for exposure-induced sensitivity loss. The LPRN amplifier gains are not to be ohvsically altered except immediately prior to a whole core calibration usinq the TIP system. The gain adjustment factor "omputations help to indicate to the operator when such a calibration procedure is necessary. Using the. power distribution data, a distribution of fuel exposur~ increments from the time of previous power dist"ibution calculation is determined and is used to update the distribution o f cumulative fuel exposure. Each fuel bundle is identified hy batch anB location, and its exposure is stored for each of the axial seqments used in the power distribution calculation These data are printed out on operator demand. Exposure increments are determined periodically for each quarter-Lenq+h section of each control rod. The corresponding cumulative exposure totals are periodically updated and printed out on operator demand. the oxno. ure increment of each local power range monitor is determined periodically and is used to upda+e both the cumulative ion chamber exposures and the correction factors for exposure-dependent LPHN sensitivity loss. These data are printed out on operator demand. The NSSS computer system provides on-line capability to determine monthly anB on-demand isotopic composition for each one-quarter-lenqth section of each fuel bundle in the core. This evaluation consists of computinq the weight of one neptunium, three uranium, and five plutonium isotopes as well as the total uranium and total plutonium content. The isotopic composition is calculated for each one-quarter length of each fuel bundle and summed accordinqly by bundles and batches. The method of analysis consists of relatinq the computed fuel exposure and average void fraction for the fuel to computer stored isotopic characteristics applicable to the specific fuel t.ype. P ev. 32, 12/8 2 7. 7-61
SSES-FSAR
- 7. 7. 1.7. 5. 2 Reactor Ooerator Information Aajor components are arranqed as shown in Figure 7.7-13.
Functional d scription and operational arranqement is as follows: Unit. Qpegating Benchboard QH12-P680} (Panel C651) houses control., annunciators and displays, including the control rod
~
oosition display. The primary process displays are computer generated CRT f ormats from the DCS and P5S computers. All variables in the DCS displays that are required for unit operation, startup and shutdown are displayed on hardwired indicators on either the Unit Operatinq Benchboa'rd or the Standby Information Panel. These variables in both CRT and hardwired displays qenerally orqinate from the same sour"e. Standby Tnformation Panel gH12-P678} (C652) - houses hardwired indicators and recorders required to startup, run, and shutdown the Plant without the use of the Display Control System. It is a bardwired backup to the DCS. Reactor Core Cooling System BB gH12-p601} (C601) - houses hardwired indicators, recorders, annunciators and controls for unit BOP system~s'unctions which do not require the operator's immediate attention during normal operation of the power plant. Functions on this panel have been determined to be long tim response functions. Common Plant Benchboard gH12-P853} (C653) >> houses hardwired indicators, recorders annunciators and controls for systems which are common to Units 1 and 2 It also houses two CRT's connected to the Performance Monitorinq System (PHS). Jjnit. Monitoring Console gC92-P628} ("680) - provides the unit operator sit down surveillance of the Unit Operatinq Benchboard and access to DCS and PHS CRT displays with the use of a ..election keyboard. Plant Monitoring Console QC92-f626} (C683) - provides sit. down urveill.ance of both units and keyboard access to computer functions of both units. There is also computer generated trend recordinq of variables from either unit. The annunciator system is a hardwired system which provides the operator with the alarm information required for unit operation, st;artup, and shutdown. This system is independent of the Plant "omputer System although the computer system does provide redundant and auxiliary alarm information as AID's through the DCS and the alarm status summary CRT display from the PNS. The Display Control System collects unit process information and presents it on nine of the ten video displays (CRTs) on the Unit Rev. 32, 12/82 7 7-62
SSES-FSAR a 0 Any averaqe power ranqe monitor {APRM) upscale rod block alarm. The purpose of t'his rod hlock function is to avoid conditions that would require reactor protection system action if allowed to proceed. APBM upscale rod block alarm setting is selected to The initiate a rod block before the APRM high neutron flux scram settinq i s reached. h Any APBN inoperative alarm. This assures that no control rod is withdrawn unless the average power range neutron monitorinq channels are either in service or
.".or rectly bypassed.
Either recirculation flow converter upscale or inoperative alarm. This assures that no control rod is withdrawn unless the recirculation flow converters, which are necessary for the proper operation of the RPMs, are operable. Re" irculation flow convertor comparator alarm or inoperative. This assures that no control rod is withdrawn unless the difference between the outputs of t'.he f1ow converters is within limits and the comparator is in'ervice. ei Scram discharqe volume high water level. This assures that no control rod is withdrawn unless enough capacity is available in the scram discharge volume to accommodate a 'scram. The setting is selected to initiate a rod hlock earlier than the scram that is initiated on scram discharge volume high water level. Scram discharge volume hiqh water level scram trio bypassed. This as..ures that no control rod is withdrawn while the scram discharge volume high water level scram function is out of service. The rod worth minimizer (HWM) function of the process computer can initiate a rod insert block, a rod withdrawal block, and a rod select block. The purpose of this function is to reinforce procedural controls that limit the reactivity worth of- control rods under lover powe conditions. The rod block trip settings are based on the allowable control rod worth limits established for the design basis rod drop accident Adherence to prescrihed control rod patterns is the normal method by which this reactivity restriction is observed. Additional information on the rod worth minimizer function is available in Subsection 7.7 1.2.8 Rev. 32, 12/82 7 7-21
SSFS-FSAR
- h. Rod po ition information system .malfunction. This as ures that no "ontrol rod can be withdrawn unless the rod position information system is in service.
Rod movement timer malf unction during withdrawal. This assures no control rod can be withdrawn unless the timer is in service. Th Rod Sequence Control System initiates rod blocks, whenever out of sequence rods are selected. The RSCS is required to he in operation bel.ow 20% rated power to prevent the operator from establishinq control rod pattern., that are not consistent with a prestored rod sequence.
- k. Hither rod block monitor (RBM) upscale ala m. This function is provided to stop the erroneous withdrawal of a control "od so that local fuel damage does not result. Although local fuel damage poses no siqnificant threat in terms of radioactive material released from the nuclear system, the trip setting is selected so that no local fuel damage results from a single control rod withdrawal -error during power range oper'ation.
Either RBN inoperative alarto. This assures that no control rod is withdrawn unless the RBM channels are in service or correctly bypassed. (3) With the mode switch in the RUN position, any of the followinq conditions initiates a rod block.
'a ~ Any APRM downscale alarm. This assures that no control rod will he withdrawn during power range operation unless the averaqe power range neutron monitoring channels are operatinq correctly or are correctly bypassed. All unbypassed APRNs must be on scale during reactor operations in the RUN mode.
- b. Fither RBN downscale alarm. This assures that no control rod is withdrawn during power range operation unless the RBN channels are operating correctly or are correctly bypassed. Unbvpassed RBMs must be on scale during reactor operations in the RUN mode.
(4) With the mode switch in the STARTUP or REFUEL position, any of the followinq conditions initiates a rod block: a ~ Any source range monitor (SR"I) detector not fully inserted into the core when the SRN count level is below the retract oermit level and any IRM ra nge switch on either of the two lowest ranges. This assures that Rev. 32, 12/82 7& 7 22'
SSES- FSAR The interlocks from the refuelinq equipment to the Reactor i1anual "ontrol System actuate circuitry that provides a control roil block. The rod block prevents the operator from withdrawing any control "ods.
- 7. 7. 1. 10. 3. 6 Separation The refuelinq interlocks are not desiqned to nor required to meet the IEPE 279-1971 criteria for Nuclear Power Plant Protection Systems. However, a single interlock failure will not cause an accident. Befuelinq interlocks and are used in con)un'tion with wdmistra+ion controls during planned refueling operations.
- 7. 7. 1. 10. 3~7 Tesfgbililg Complete functional testinq of all refueling interlocks before
~ny refuelinq outage will positively indicate that the interlocks operate in the situations for which they were designed. The interlocks can be subjected "to valid operational tests by loading each hoist with a dummy fuel assembly, positioninq the refueling platform, and withdrawinq control rods. Mhere redundancy is provided in the logic circuitry, tests are performed automatically, on a periodic basis, to assure that each redundant logic element can independently perform its function.
- 7. 7. 1. 10. 4 Fnvironmenta1 onsiQegations equipment. (refuelina) will be subjected to the conditions listed in Table 3.11-1 during normal operation. The refuelinq interlocks are not required to operate under the conditions listed in Table 3. 11-3.
Refuelinq components are capable of surviving desiqn basis event" such as earthquakes, accidents, and anticipated operational occurrences without consequential damage, but are not required to he functional durinq or after the event without repair. 7;7. 1. 10. 5 Opera t ional Considerations 7.7. 1. 10. 5. 1 General Information The refuelinq interlocks system is required only during refueling opera tions. R ev. 32, 12/82 7w7 7 1
SS ES- PS AR 7.7 1.10.5.2 Q~agfog Appgatog Infogmatxgn In the refuelinq mode, the control room operator has an indicator liqht for "Select Permissive" whenever all control rods are fully inserted. He can compare. this indication with control rod position data from the computer as well as control rod in-out status on the full core status display. Furthermore, whenever a control rod withdrawal block situation occurs, the operator receives annunciation and computer logs of the 'rod block. He can compare these outputs with the status of the variable providing the rod block condition. Both channels of the control'od withdrawal interlocks must aqree that permissive conditions exist in order to move control rods; otherwise, a control rod withdrawal block is placed into effect. Failure of one channel may initiate a rod withdrawal block, and will not prevent application of a valid control rod withdrawal block from the remaininq operable channel. Core flux activity monitorinq is provided during refuelina by the SPA's and/or dunkinq chambers which are specified and controlled in Technical Specification 3/4 9. I'.n terms of refueling platform interlocks'he platform operator has analog type readout indicators for the pla'tform x-y position relative to the reactor core. The position of the grapple is shown on a digital indicator immediately below the platform position indicators. Analog load cel3. indications of hoist loads are given for each hoist by locallv mounted indicators. Individual push button and rotary control swit"hes are provided .for local control of the platform and its hoists The platform operator can immediately determine whether the platform and hoists are responding to his local instructions, and can, in conjunction with the control room operator, verify proper operation of each of the three categories of interlocks listed previously. 7.7.1.10.5 3 Set Points There are no safety set points associated with this system. 8 ev. 32, 12/82 7&7 72
Page 1 SSES - FSAR TABLE 8.1-2 AFFILIATED AND NON"CLASS lE CIRCUITS THAT CONNECT TO CLASS lE POWER SUPPLIES CIRCUIT METHOD OF 23 NUMBER NON CLASS lE LOAD CLASS lE POWER SUPPLY ISOLATION (Ref.FSAR 8.1.6.ln.5) Control Structure HVAC Chiller Control Structure Room Div.I Engineered HSV i Condenser Water Safeguard MCC OP170A 'ump OB136 Control Structure Control Structure HSV HVAC Chiller Room Div.II Engineered Condenser Water Safeguard MCC Pump OP170B OB146 Drywell Area Reactor Area Unit Cooler Div.I Engineered IV411A Safeguard MCC 1B236 Drywell Area Reactor Area Unit Cooler Div.II Engineered IV411B Safeguard MCC 1B246 Drywell Area Reactor Area Unit Cooler Div.I Engineered IV412A Safeguard MCC 1B236'rywell Area Reactor Area Unit Cooler Div.II Engineered IV412B Safeguard MCC 1B246 Drywell Area Reactor Area Unit Cooler Div.I Engineered IV413A Safeguard MCC 1B236 Drywell Area Reactor Area Unit Cooler Div. II Engineered IV413B Safeguard MCC 1B246 Drywell Area Reactor Area Unit Cooler Div.I Engineered IV417A Safeguard MCC 1B236 Rev. 23, 6/Sl
Page 2 ~ 5 CIRCUIT METHOD OF 23 NUMBER NON CLASS lE IOAD CLASS 1E POWER SUPPLY ISOLATION (Ref.'FSAR 8.1.6.1n.5) 10 Drywell Area Reactor Area 3. Unit Cooler Div.II Engineered LV417B Safeguard MCC lB246 Drywell Area Reactor Area Unit Cooler Div.I Engineered 2V411A Safeguard MCC 2B236 12 . Drywell Area Reactor Area Unit Cooler Div.II Engineered 2V411B Safeguard MCC 2B246 13 Drywell Area Reactor Area Unit Cooler Div.I Engineered 2V412A Safeguard MCC 2B236 14 Drywell Area Reactor Area Unit Cooler Div.II Engineered 2V412B Safeguard MCC 2B246 15 Drywell Area Reactor Area Unit Cooler Div.I Engineered 2V413A Safeguard MCC 2B236 16 Drywell Area Reactor Area Unit Cooler Div.II Engineered 2V413B Safeguard MCC 2B246 17 Drywell Area Reactor Area Unit Cooler Div.I Engineered 2V417A Safeguard MCC 2B236 18 Drywell Area Reactor Area Unit Cooler Div.II Engineered 2V417B Safeguard MCC 2B246 19 Instrument Air Channel B/Div II Compressor Engineered
'A'K107A Safeguard Load Center lB220 Rev. 23, 6/81
Page 3 CIRCUIT METHOD OF NUMBER NON CLASS lE LOAD CLASS lE POWER SUPPLY ISOLATION (Ref;FSAR 8.1.6.ln.5) 20 Instrument Air Channel D/Div II ii Compressor Engineered
'B'K107B Safeguard I,oad Center 1B240 21 Instrument Air Reactor Bldg.
Dryer Panel Div.II Engineered Safeguard MCC
'AB'C142A 1B247 22 Instrument Air Reactor Bldg.
Dryer Panel Div.II Engineered
'B'C142B Safeguard MCC 1B226 23 Instrument Gas Reactor Bldg.
Compressor Div.I Engineered
'A'K205A Safeguard MCC 1B217 24 Instrument Gas Reactor Bldg.
Compressor Div.I Engineered
'B'K205B Safeguard MCC 1B236 25 Instrument Air Channel A/Div.I Compressor Engineered
'A'K107A Safeguard Load Center 2B210 26 Instrument Air Channel C/Div. I Compressor Engineered
'B'K107B Safeguard Load Center 2B230 27 Instrument Air Reactor Bldg.
Dryer Panel Div.I Engineered
'A'C142A Safeguard MCC 2B237 28 Instrument Air Reactor Bldg.
Dryer Panel Div.I Engineered
'B'C142B Safeguard MCC 2B216 29 Instrument Gas Reactor Bldg.
Compressor Div.I Engineered
'A'K205A Safeguard MCC 2B217 Rev. 23, 6/81
Page 4 CIRCUIT METHOD OF 23 NUMBER NON CLASS lE LOAD CLASS lE POWER SUPPLY ISOLATION (Ref.FSAR 8.1.6.ln.5) 30 Instrument Gas Reactor Bldg. 1l. Compressor Div.I Engineered
'B'K205B Safeguard MCC 2B236 31 Turbine Area 480V Channel A/Div. I MCC 1B116 Engineered Safeguard Load Center 1B210 32 Turbine Area 480V Channel B/Div. II MCC 1B126 Engineered Safeguard I,oad Center 1B220 33 Auto Transfer Switch Reactor Area Div.I Engineered I
1ATS21B Safeguard MCC 1B216 Auto Transfer Switch Reactor Area lATS218 Div.I Engineered Safeguard MCC 1B236 35 Auto Transfer Switch Reactor Area 1ATS228 Div.II Engineered Safeguard MCC 1B226 36 Auto Transfer Switch Reactor Area 1ATS228 Div.II Engineered Safeguard MCC 1B246 37 Computer Power Div. I 250V DC 1.V Supply inverter Ioad Center 1D656 1D652 23 38 Vital Power Div. II 250V DC l.V Supply inverter Load Center 1D666 1D662 Computer Power Reactor Area Supply inverter Div. I Engineered 1D656 Safeguard MCC 1B236 Rev. 23, 6/81
Page 5 CIRCUIT METHOD OF 23 NUMBER NON CLASS lE IOAD CLASS lE POWER SUPPLY ISOLATION (Ref.FSAR 8.1.6.ln.5) 40 Vital Power Reactor Area Supply inverter Div.II Engineered 1D666 Safeguard MCC 1B246 41 250V DC Turbine Div.I 250V DC Building control Ioad Center center A 1D652 1D155 42 250V DC Turbine Div.II 250 V DC Building control Load Center center B 1D662 1D165 23 125V DC Channel A/Div. I Distribution 125V DC Panel Ioad Center 1D615 1D612 44 125V DC Channel B/Div. IZ Distribution 125V DC Panel I,oad Center 1D625 1D622 45 125V DC Channel C Distribution 125V DC Panel Load Center 1D635 1D632 46 125V DC Channel D Distribution 125V DC Panel Ioad Center 1D645 1D642 47 480/277V Reactor Area Essential Div.I Engineered Lighting Safeguard MCC Panel 1B217 1EP07 48 480/277V Reactor Area Essential Div.II Engineered Lighting Panel Safeguard MCC 1EP08 lB227 ~ 49 480/277V Essential Lighting Panel Reactor Area Div. II Engineered Safeguard MCC 23 1EP03 1B226 Rev. 23, 6/81
Page 6 CIRCUIT 23 METHOD OF NUMBER NON CLASS lE IOAD lE POWER SUPPLY ISOLATION (Ref.FSAR 50'1 480/277V Essential 'LASS Lighting Panel Reactor Area Div.II Engineered Safeguard MCC 8.1.6.ln.5) 1EP04 1B246 Turbine Area 480V "'Channel A/Div. I Engineered MCC 2B116 Safeguard Load center 2B210 52 Turbine Area 480V Channel B/Div.II Engineered MCC 2B126 Safeguard Load Center q2B220 53 Auto transfer switch Reactor Area 2ATS218 'iv.I Engineered Safeguard MCC 2B216 54 Auto transfer switch Reactor Area 2ATS218 Div.I Engineered Safeguard MCC 2B236 55 Auto transfer switch Reactor Area 2ATS228 Div.II Engineered Safeguard MCC 2B226'eactor 56, Auto transfer switch Area 2ATS228 Div.II Engineered Safeguard MCC 2B246 57 Computer Power Div.I 250V DC 23 supply inverter Load Center 2D6>6 2D652 58 Vital Power Div.II 250V .DC supply inverter Ioad Center 2D666 2D662 59 Computer Power Reactor Area supply inverter Div.I Engineered 2D656 Safeguard MCC 2B236 ~ Vital Power Reactor Area Div.II Engineered supply inverter 2D666 Safeguard MCC 2B246 Rev. 23, '6/Sl
Table 8.1-2 (cont.) Page 6 CIRCUIT METHOD OF NUMBER NON CLASS lE LOAD CLASS 1E POWER SUPPLY ISOLATION (Ref.FSAR 8.1.6.ln.5) 50 480/277V Essential Reactor Area Div. II Engineered iii Lighting Panel Safeguard MCC lEP04 1B246 51 Turbine Area 480V Channel A/Div. I Engineered MCC 2B116 Safeguard Load Center 2B210 52 Turbine Area 480V Channel B/Div. II Engineered MCC 2B126 Safeguard Load Center 2B220 53 Auto transfer switch Reactor Area 2ATS218 Div. I Engineered Safeguard MCC 2B216 54 Auto transfer switch Reactor Area 2ATS218 Div. I Engineered Safeguard MCC 2B236 55 Auto transfer switch Reactor Area 2ATS228 Div. II Engineered Safeguard MCC 2B226 56 Auto transfer switch Reactor Area 2ATS228 Div. II Engineered Safeguard MCC 2B246 5.7 Computer Power Div. I 250V DC supply inverter Load Center 2D656 2D652 58 Vital Power Div. II 250V DC iv supply inverter Load Center 2D666 2D662 59 Computer Power Reactor Area supply inverter Div. I Engineered 2D656 Safeguard MCC 2B236 60 Vital Power Reactor Area supply inverter Div. II Engineered 2D666 Safeguard MCC 2B246 Rev. 30, 5/82
Page 7 METHOD OF 23 NON CLASS lE IOAD CLASS lE POWER SUPPLY ISOLATION ref.RSAR 8.1.6eln.5) 61 250V DC Turbine Div. I 250V DC 111 Building Control Load Center Center A 2D652 2D155 62 250V DC Turbine Div.II 250V DC Building Control Ioad 'Center Center B 2D662 2D165 63 125V DC Channel A/Div.I Distribution Panel 125V DC 23 2D615 Ioad Center 2D612 64 125V DC Channel B/Div.II Distribution Panel 125V DC 2D625 Load Center 2D622 65 125V DC Channel C Distribution Panel 125V DC 2D635 Load Center 2D632 66 125V DC Channel D Distribution Panel 125V DC 2D645 Load Center 2D642 67 480/277V Reactor Area Essential Div.I Engineered Lighting Panel Safeguard MCC 2EP07 2B217 68 480/277V Reactor Area Essential Div.II Engineered Lighting Panel Safeguard MCC 2EP08 2B227 69 ,480/277V Reactor Area Essential Div.II Engineered Lighting Panel Safeguard MCC 2EP03 2B226 70 480/277V Reactor Area Essential Div.II Engineered Lighting Panel Safeguard MCC 2EP04 2B246 Rev. 23, 6/Sl
Page 8 CIRCUIT METHOD OF N ABER NON CLASS 1E LOAD CLASS 1E POWER SUPPLY ISOLATION (Ref.FSAR 8.1.6.1n.5) 71 480/277V Essential Control structure H&V Room iii Lighting Panel Eng. Div.I Safeguard MCC OEP01 OB136 72 480V/277V Control structure Essential H&V Room Lighting Panel Eng. Div.II Safeguard MCC OEP02 OB146 73 '80V/277V Control structure Essential H&V Room Lighting Panel Eng. Div.II Safeguard MCC 1EP05 OB146 74 Reactor Bldg. Channel A/Div.I Chiller compressor Emergency auxiliary 1K206A Switchgear 1A201 75 Control Rod Drive Channel A/Div.I iv Water pump Emergency auxiliary 1P132A Switchgear 1A201 76 Turbine Bldg. Channel A/Div. I Chiller compressor Emergency auxiliary 1K102A Switchgear lA201 77 Reactor Bldg. Channel B/Div.II iv Chiller compressor Emergency auxiliary 1K206B Switchgear 1A202 78 Main condenser Channel B/Div.II iv Mechanical vacuum Emergency auxiliary pump 1P105 Switchgear lA202 79 Turbine Bldg. Channel B/Div.II Chiller compressor Emergency auxiliary 1K102B Switchgear lA202 80 Control Rod Drive Channel D/Div.II Water pump Emergency auxiliary 1P132B Switchgear 1A204 81 Control Structure Control Structure H&V Passenger Elevator Room Div.I Engineered ODS108 Safeguard MCC OB136 Engr. Safeguard Div.I Engr. Safeguard Service Water Pumphouse Service Water Pump OLP16 house MCC OB517 Rev. 29, 3/82
4
~,
Tgg3T~~ 8. 1-2 Page 9 CIRCUIT MFTHOD OF NUMBER NON CLASS lE LOAD CLASS 1E POWER SUPPLY ISOLATION (Ref.FSAR 8.1.6.1n.5) 83 Engr. Safeguard Div.I Engr. Safeguard Service Water Pumphouse Service Water Pumphouse Distribution Panel MCC OPP509A OB517 84 Engr. Safeguard, Div.II Engr. Safeguard Service Water Pumphouse Service Water Pumphouse Distribution Panel MCC OPP511 OB527 85 Spray Pond Piping Div.I Engr. Safeguard Drain Pump Service Water Pumphouse OP513A MCC OB517 86 Spray Pond Piping Div.II Engr. Safeguard Drain Pump Service Water Pumphouse OP513B MCC 1 OB527 87 Reactor Bldg. Closed Reactor Area Cooling Water Pump Div. I Engineered 1P210A Safeguard MCC 1B216 88 Reactor Bldg. Closed Reactor Area iv Cooling Water Pump Div.I Engineered 1P210B Safeguard MCC 1B237 89 Reactor Bldg. Equip. Rm. Reactor Area H&V Supply Fan Div. II Engineered IV232 Safeguard MCC 1B227 90 Reactor Bldg. Equip. Rm. Reactor Area iv H&V Supply Fan Div. II Engineered 2V232 Safeguard MCC 2B227 91, Reactor Bldg. Reactor Area Service Elevator Div. II Engineered 1DS204 Safeguard MCC 1B246 92 Process Radiation Div. I 24VDC iv Monitoring Cabinet Distribution Panel 1C604 1D672 93 Process Radiation Div. II 24VDC iv Monitoring Cabinet Distribution Panel 1C604 ID682 Rev. 32, l2/82
Page 10 CIRCUIT METHOD OF NUMBER NON CLASS lE LOAD CLASS 1E POWER SUPPLY (Ref. JSOLATEON FSAR 8.1.6.ln.5) 94 Control Rod Drive Channel A/Div. I iv Water Pump Emergency Auxiliary 2P132A Switchgear 2A201 95 Turbine Bldg. Channel A/Div. I iv Chiller Compressor Emergency Auxiliary 2K102A Switchgear 2A201 96 Reactor Bldg. Channel B/Div. II Chiller Compressor Emergency Auxiliary 2K206B Switchgear 2A202 97 Main Condenser Channel C/Div. I iv Mechanical Vacuum Emergency Auxiliary Pump 2P105 Switchgear 2A203 98 Turbine Bldg. Channel C/Div. I Chiller Compressor Emergency Auxiliary 2K206A Switchgear 2A203 99 Control Rod Drive Channel D/Div. II iv Water Pump Emergency Auxiliary 2P132B Switchgear 2A204 100 Turbine Bldg. Channel D/Div. II Chiller Compressor Emergency Auxiliary 2K102B Switchgear 2A204 101 Reactor Bldg. Closed Reactor Area Cooling Water Pump Div. II Engineered 2P210A Safeguard MCC 2B247 102 Reactor Bldg. Closed Reactor Area Cooling Water Pump Div. II Engineered 2P210B Safeguard MCC 2B226 103 104 105 Process Radiation Div. I 24VDC Monitoring Cabinet Distribution Panel 2C604 2D672 Rev. 29, 3/82
SSES FSAR TABLE 8.1-2 Page ll CIRCUIT METHOD OF NON CLASS 1E LOAD CLASS 1E POWER SUPPLY ISOLATION (Ref.FSAR 8.1.6.1n.5) 106 Process Radiation Div. II 24VDC iV Monitoring Cabinet Distribution Panel 2C604 2D682 107 Containment Vacuum Div. I 120V Inst. Relief Valve PSV-15704Al AC 1Y216 PNL 108 PSV-15704B1 iV 109 PSV-15704C1 iV 110 PSV-15704D1 iv ill PSV-15704E1 112 PSV-15704A2 Div. II 120V Inst. ,iv AClY226 PNL 113 PSV-15704B2 iv 114 PSV-15704C2 iV 115 PSV-15704D2 iV 116 PSV-15704E2 iv 117 PSV-25704A1 Div. I 120V Inst. iV AC 2Y216 PNL 118 PSV-25704Bl iV 119 PSV-25704C1 iV 120 PSV-25704D1 iV 121 PSV-25704E1 e x22 123 PSV-25704A2 PSV-25704B2 Div. II 120V AC 2Y226 PNL Inst. 1V 1V iV 124 PSV-25704C2 iv 125 PSV-25704D2 1V 126 PSV-25704E2 1V 127 Reactor Protection Reactor Area i,v System Transformer 2X201A Div. II Engineered Safeguard MCC 1B227 128 Reactor Protection Reactor Area System Transformer 2X201A Div. II Engineered Safeguard MCC 2B227 129 ES Transformer Diesel Generator Rm. Cooling Fans Ch. A Engineered and Control Safeguard MCC OX201 OB516 130 ES Transformer Diesel Generator Rm. Cooling Fans Ch. B Engineered and Control Safeguard MCC OX203 OB526 131 ES Transformer Diesel Generator Rm. iV Cooling Fans Ch. C Engineered and Control Safeguard MCC ~ ZS2 OX201 ES Transformer Cooling Fans OB536 Diesel Generator Ch. D Engineered Rm. and Control Safeguard MCC OX203 OB546 Rev. 27, 10/81
TABLE 8.1-2 Page 12 CIRCUIT METHOD OF NUMBER NON CLASS 1E LOAD CLASS 1E POWER SUPPLY ISOLATION (Ref.FSAR 8.1.6.1n.5) 133 HPCI Vacuum Tank Div. II 250VDC Motor iv Condensate Drain Pump Control Center 1P215 1D264 134 HPCI Barometric Div. II 250VDC Motor iv Condensate Vacuum Pump Control Center 1P216 1D264 135 RCIC Barometric Div. I 250VDC Motor iv Condensate Vacuum Pump Control Center 1P219 1D254 136 RCIC Vacuum Tank Div. I 250VDC Condensate Drain Pump Motor Control Center 1P220 1D254 137 SLC Storage Tank Channel C 480V iv Electric Heater Motor Control Center
'A'E219 1B236 138 SLC Storage Tank Channel C 480V iv Electric Heater Motor Control Center 1B236
'B'E220 139 HPCI Vacuum Tank Div. II 250 VDC iv Condensate Drain Pump Motor Control Center 2P215 2D264 140 HPCI Barometric Div. II 250VDC iv Condensate Vacuum Pump Motor Control Center 2P216 wD264 141 RCIC Barometric Div. I 250VDC iv Condensate Vacuum Pump Motor Control Center 2P219 2D254 142 RCIC Vacuum Tank Div. I 250VDC iv Condensate Drain Pump Motor Control Center 2P220 2D254 143 SLC Storage Tank Channel C 480V iv Electric Heater Motor Control Center
'A'E219 2B236 144 SLC Storage Tank Channel C 480V Electric Heater Motor Control Center
'B'E220 2B236
SSBS-PSlLR 8~~SITJ PORBR SYSTBJ
~8 ~ 'I DRSCRIPTIQN ~8 2.1 1- TnanSsissien SYstes t
The bulk pover transmission system of PPSL operates a 230 KV and 500 KV. Unit 81 of the Susguehanna Steam Electric Station supplies pover to the 230 KV system through a 230 KV svitchyard and Unit 02 supplies pover to the 500 KV system through a separate 500 KV switchyard. The offsite power system for the plant is supplied through the 230 KV portion of the bulk 'power system. Pigure 8.2-1 shows the Susquehanna 230 KV and 500 KV svitchyards and the transmission lines associated with each yard and in the vicinity of.,the plant. The figure shows the line arrangement with both units in operation. The tvo svitchyards are physically separate and are tied together by a 230 KV yard tie line with a 230-500 KV transformer in the 500 KV yard. Tvo independent offsite power sources are supplied to the Susquehanna plant. One source is established by tapping the Montour-Mountain 230 KV line north of the plant and constructing 1300 ft. of 230 KV line on painted steel pole structures to startup transformer 510. The Montour-Mountain line shares double circuit steel pole structures vith the Stanton-Susquehanna 82 230 KV line in the vicinity of the plant. The double circuit line extends to a point 1.5 miles east of the transformer 010 tap at vhich point the two circuits split as shovn in Pigure 8.2-1. The Montour-Mountain line extends 16.8 miles north on double circuit lattice towers vith the Stanton-Susquehanna 41 230 KV line and terminates in the Mountain Substation. The Stanton-Susquehanna 42 circuit extends southward on double circuit towers vith the Stanton-Susquehanna 41 circuit and terminates in the Susquehanna 230 RV Switchyard. f To the vest of the tap into the Susquehanna plant the Montour-J Mountain 230 KV circuit extends 1500 feet on double circuit steel pole structures at which point the Stanton-Susquehanna 02 circuit separates and extends northward to Stanton Substation. The Montour-Mountain 230 KV circuit then joins the Montour-Susquehanna 230 KV circuit on double circuit steel lattice towers and extends 29. 0 miles to the Mon tour S witchyar d. The total distance to Mountain Substation from the tap into the plant is 18.7 miles. The distance from Montour to the tap is 29.7 miles. Several lines feed the Montour Switchyard and Mountain Substation, as can be readily seen in Figure 8. 2-3. These lines Rev. 28, 1/82 8 2-1
offer a multitude of possible supplies for the tap into Susquehanna startup transformer 810. contour Switchyard is supplied directly by generation fram the contour Steam Electric Station. Other generating stations are indirectly linked by the bulk pover grid system. The conductors for the transfarmer 410 tap and the Hontour-tlountain line are 1590 kcmil 45/7 ACSR and are supported by single string insulator assemblies. Maximum conductor tension is limited to 16,000 pounds on steel pole line sections and 21,900 pounds on. lattice tower sections under maximum anticipated loading conditions. The second offsite power source is supplied at 230 KV from the yard tie circuit between the Susquehanna 500 kV and 230 kV Substations south of the Susquehanna Steam Electric Statian. The source is provided by a single 400 ft. span tap from the 230 KV yard tie circuit to startup transformer 020. The yard tie line consists of 230 KV double circuit tubular steel pole structures supporting tvo parallel circuits of 1590 kcmil 45/7 ACSB conductors on single string insulator assemblies. The circuits are tied together ta form a tvo conductor per phase sinqle circuit line. The 400 ft. tap to transformer 420 consists of one 1590 kcmil 45/7 ACSB conductor per phase. The distance from the tap point west to the 500 KV yard is 1500 ft. The distance from the tap point east to the 230 KV yard is 1.6 miles. Maximum conductor tension is limited to 16,000 pounds in the yard tie line under maximum loadinq conditions. The second offsite power supply is furnished by the multiple sources throughout the bulk power grid system through the 230 KV and 500 KV lines emanating from the Susguehanna 230 KV and 500 KV switchyards. See Figure 8. 2-3. All transmission lines meet or exceed design requirements set forth by the National Electric Safety Code. One or two overhead ground vires are employed on the transmission lines above the phase conductors to provide adeguate lightning flashover pratection. All lines meet the Army Corps of Engineers requirements for clearance over flood levels. All bulk power transmission lines are desiqned to withstand 100 mph hurricane wind loads on bare canductors. The Montour-Mountain 230 KV line is crossed by the Stanton-Susquehanna 42 230 KV line. No transmission lines cross over the Susquehanna 500 KV to 230 KV yard tie line or the two tap lines supplying transformers $ 10 and 820. No single disturbance in the bulk power grid system vill cause complete loss of offsite power ta the Susquehanna SES. This is a basic system desiqn criteria.
- 8. 2-2
SSES-PSAR 8.2.~1 - Transmisgion Interconnection. PP6L is a member of the Pennsylvania, New Jersey, and )maryland Interconnection which permits economical exchanges of power with neiqhborinq utilities and provides emergency assistance. Direct bulk power ties're between PPSL and Philadelphia Electric, Luzerne Electric Division of UGI, Netropolitan Edison, Pennsylvania Electric, Jersey Central Power and Light, Public Service Electric and Gas, and Baltimore Gas and Electric Companies., 8 2.1.3 Switchggrds
- 8. 2 1.3. 1 Startup Trans~fo mers 010 and 020 The contour-Mountain 230 KV line and the 23'0 KV yard tie line supply power to startup transformers $ 10 and 420, respectively, through motor operated air break switches. High speed positive ground switches are installed between the motor operated air break s~itches (NOABs) and the startup transformers. The startup transformers and low side bus connections are discussed in Section 8.3.1 The startup transformer yards are physically separated from each other, the Unit tl and 42 main transformer yards and the 230 KV and 500 KV switchyards as can be seen on figure 8.2-1. 1590 kcmil 45/7 ACSR conductors connect the air switches to the startup transformers. 13.8 KV cables are installed in underqround conduit between the startup transformers and the turbine building. Non-segregated phase bus ducts establish the tie to the 13.8 KY startup buses within the turbine building. See Piqure 8.2-4 .for a one line diagram of the offsite power system.
Line relay protection for the contour-Mountain 230 KV line and the 230 KV yard tie circuit is provided by two independent directional comparison carrier blocking pilot relaying and two zone directional distance backup systems which ensure adequate line protection in the event of a malf unction. These relaying schemes detect faults on the transmission line and isolate the power sources to the transformers by tripping the power circuit breakers (PCBs) at the line terminals. Breaker failure relaying, applied at each line terminal, detects a failure to trip or failure to interrupt condition at the line terminal and trips all associated PCBs necessary to isolate the line. Power to the line relayinq facilities is supplied from the local switchyard power sourcese Startup transformers N10 and 020 are protected by high speed percentage differential, sudden pressure and overcurrent Rev. 28, 1/82 8 2-3
SSES-PSAB relaying. Direct transfer trip facilities are utilized as the primary relayinq scheme to open the PCBs at the transmission line remote terminals in the event of transformer trouble. Backup protection is provided by the high speed ground switch'n the 230 KV side of the startup transformer This switch is closed to place a positive fault on the 230 KV transmission line which vill be detected by the remote line'terminal relaying systems if the primary direct transfer trip scheme fails to function correctly. The motor operated air switch automatically opens after the 230 KV system is de-energized to isolate the startup transformer from the transmission system and permit reclosing of the transmission-line terminal PCBs. A time delay undervoltage relay monitors the 13e8 KV startup bus voltaqe. On loss of offsite power the relay trips the startup bus incoming feeder breaker and initiates transfer of the bus loads to the other startup transformer through closure of the startup bus tie breaker. The time delay undervoltage relay also prevents unnecessary automatic trip of the incoming feeder breaker for short duration disturbances on the transmission line. Pover to transformer 010 and 820 svitchgear, motor operated air break switches, and hiqh speed qround switches is supplied from the station 125 V DC power supplies. 8 2.1.3 2 88Hqneg888a IJHLQ 81 230 HV Hain rransf orner Leads Overhead 1590 kcmil 45/7 ACSR conductors, bundled two per phase, tie the Unit $ 1 main stepup transformers, through a high voltage Disconnect switch-Synchronizing PCB-Disconnect switch arrangement, to the 230 KV svitchyard. The synchronizing breaker and disconnect svitch arrangement is provided at the Susquehanna SES site to improve reliability in synchronization and flexibility of operatinq Unit 1. Steel pole structures support the strain bus and the 2.2 mile 230 KV tie with'ingle string insulator assemblies. The tie line is capable of transmitting the .full 1280 tlVA output of the Unit 81 generator. Belay protection between the Unit 8 transformer and the 1 synchronizing breaker is provided by high speed percentage differential relays which trip Unit 41 and the synchronizing breaker by the unit master trip lockout relays. A second protection scheme is provided by the Unit 41 overall differential relaying vhich also detects fault conditions between Unit 41 transformer and the synchronizinq breaker. Tvo directional comparison carr'ier blocking pilot and tvo zone directional distance backup relaying systems provide fault protection between the 230 KV synchronizing PCB and the Susquehanna 230 KV Svitchyard. Breaker failure protection relaying is applied at
'ev.
28, 1/82 8 2-4
SS ES- PS AH each terminal to detect a failure to trip or failure to interrupt condition and to electrically isolate the faulty component. Control power to the synchronizing power circuit breaker and power to the onsite relaying equipment are provided by the plant 125 V DC power supplies. Switchboard
- 8. 2. 1 3. 3 S~uguehanna 230 KV The 230 KV switchyard is an outdoor steel structure, comprised of 6 bay positions containinq 14-230 KV power circuit breakers arranged in a breaker and one half scheme. Terminating positions are provided for seven lines, one generator lead, and a yard tie to the 500 KV switchyard. The switchyard breakers can be operated by remote supervisory control from the PPSL System Operatinq Offices.
Service power to the 230 KV switchyard is provided by a local 12 KV distribution line with a backup diesel generator in the 230 KV switchyard. An automatic throwover scheme is employed in the event of one source failure. Line protection eguipment power is. provided by a sinqle 125 V DC switchyard service battery equipped with two full capacity chargers. 8.2.1.3.4 Susquehanna Unit <<2 500 KU Main 7~ns f~ome~ Lead s Unit <<2 generator output is connected to the 500 KV switchyard by a 1400 f t. overhead 500 KV,. transmission line. 2493 kcmil 54/37 ACAR conductors bundled two per phase are supported by V-string insulator assemblies on steel pole H-frame structures. The tie ,is capable of transmittinq the full 1280 NVA generator output of Unit $2 to the 500 KV swi tchyard. Relay protection for the connection between the Unit <<2 transformer and the Susquehanna 500 KV switchyard is provided by high speed bus differential relays which trip Unit <<2 and the three 500 KV switchyard generator breakers by the master trip lockout relays for a fault in the connection. An overall differential protection scheme provides a second system to trip Unit <<2 and the three PCBs connected to the generator in the 500 KV switrhyard for a fault on the transformer leads. Breaker failure protection is applied at each terminal to detect a failure to trip or failure to interrupt condition and to electrically isolate the faulty component. Rev. 28, 1/82 8. 2-5
SSES-FS AR ~8..1. 3. 5~Su SuehanSa 500 KV Saatc~h~a8 The 500 KV switchyard is an outdoor steel structure, comprised of three bays containinq five 500 KV power circuit breakers arranged in a. modified ring bus configuration. The switchyard provides for ultimate future expansion to 5 bays in a breaker and one half scheme. Terminating positions are provided for two lines, one 500 KV generator lead circuit and a circuit to a bank of three single phase 500-230 KV autotransformers. Manual operation of the 500 KV qenerator lead synchronizing circuit breakers is by the plant control room operator. The remaining PCBs can be operated by PPSL's remote supervisory control or'by the plant super visory control. Service power to the 500 KV switchyard is provided by two sources: one f rom the qeneratinq station, and the second f rom the tertiary winding of the yard tie autotransformers with an automatic .low voltaqe throwover scheme in the event of one source failure. Line protection equipment is powered by a single 125 V DC switchyard service battery equipped with two full capacity battery chargers. 8.2 1.3.6 -Nontour and Mop@tain 230=.kV Swit~ch ards Figure 8.2-5 shows a one line diaqram of the off-site power system for Startup Transformer tl0. The Montour Switchyard is an outdoor steel structure comprised of four bay positions containinq 11-230 kV power circuit breakers arranged in a breaker and one half scheme. Two generating leads from the Nontour Steam Electric Station and five transmission lines are terminated in the yard. The switchyard breakers can be operated by remote control from the PPGL System Operating o ffices. The Nountain Switchyard is owned and operated by UGI Corporation, Luzerne Electric'ivision. Et is an outdoor steel structure with two bay positions each containinq, one 230 kV PCB. The two PCBs are arranged hack to hack between the Montour-Mountain and Mountain-Lackawanna Lines. Between the two PCBs is a normally open NOAH to the Susquehanna-Stanton 41 line. The PCBs and NOAB can be operated by remote supervisory control from the UGX Corporation System operator8s office. PCB and NOAH status is monitored by PPSL's System Operatinq offices. Rev. 28, 1/82 8 2-6
SS ES-FS M
~81~4 Of fsj,te~ower S~sem Monitoring PPSI,~s transmission lines are patrolled approximately three times throughout a year to ensure that the physical and electrical integrity of the transmission line supports, hardware, insulators, and conductors is maintained for safe and reliable conti nui ty of service.
The periodi" transmission line patrol is conducted by helicopter. Less frequent foot patrols and selective structure inspections ar'e performed depending on the age of the line. Monitoring of the Unit 01 and Unit N2 offsite power sources. in the plant control room is via a hardwired mimic bus arrangement which shows startup transformers 010 and 120, the transformer 410 and 420 motor operated air break switches, the 13. 8 K V start- up buses, the 13,8 KV bus,feeder breakers, and the 13.8 KV bus tie breaker. Annunciation signals abnormal tripping to the control room operator. Control and status indication are provided for the 230 KV HOAB switches and the 13.8 KV breakers. Potential indication for the PPSL grid and 13.8 KV bus and status indication of the 230 KV high speed ground switches are provided. lh A cathode ray tube (CRT) display is provided by the plant computer system which provides the operator with additional information about the offsite power sources. The display is a mimic bus arrangement, similar to the hardwired mimic bus, and includes the status of the PCBs at the remote terminals of the transformer 010 and 620 supply lines. Monitoring of the Unit 81 main generator output leads to the 230 KV switchyard is provided in the control room. A hardwired mimic bus arrangement provides control and status indication of the synchronizing PCB. ,Potential indication and monitoring of current, watts, vars, watt hours and voltage are provided. Annunciation signals an abnormal change in status of the synchronizing PCB. The computer CRT display system provides the operator with the status of all PCB's in the 230 KV switchyard and the synchronizing PCB via input from PPGL's supervisory control system. Annunciation accompanies a failure of the supervisory system. Manual control of the 230 KV switchyard is by a supervisory system from selected PPSL System, Operating facilities. Monitoring of the Unit $ 2 main generator output leads and the 500 KV switchyard is provided in the control room via a mimic bus arrangement. PCB open-close status indication and control are provided for all PCBs in the 500 KV switchyard. Except for the main generator synchronizing breakers which are hardwired directly to the control room along with potential indication, all 500 KV PCB control and status indication in the control room is Rev. 28, 1/82 8. 2-7
SS ES- FS AR provided throuqh a supervisoriy system. Digital displays monitox output current, watts, vags, watt hours, and voltage. Annunciation accompanies uncommanded PCB status changes, loss of potential, transformer trouble, fire protection system actuation, carrier equipment failux'e, and fault recorder failure. Control of the 500 KV switchyard fault recorder and tap change control on the 500-230 KV transformer are made available to the operator. Similar information is provided to the control room operator via the computer CRT mimic bus arrangement display through the supervisory system. Primary control of the 500 KV switchyard is. via the System Operatinq supervisory control system except for the main generator synchronizing breakers which can be controlled only by the plant operator. Preoperational and initial startup testing of all apparatus, equipment, relaying, and. PCBs is conducted at transformers %10 and 420 and the 500 KV and 230 KV switchyards to ensure compliance with design criteria and standards. PCB protective relay testing, maintenance, and calibration in the 230 KV and 500 KV switchyards, Montour switchyard and at transformers 010 and N20 will be conducted approxi'mately once every two years. PCB protective relay testing, maintenance and calibration at Mountain switchyard is performed approximately every year.
- 8. 2 1.5- I+ustly Stagda~ds The requirements, cxiteria and recommended practices set forth in the followinq. documents are implemented in the design of the transmission system:
National Electric Safety Code, 7th Addition. PJM Interconnection Protective Relaying Philosophy and Design Standards
,C MAAC Group Reliability Principles and Standards for Planninq Bulk Power Electric Supply System of ISAAC Group, July 18, 1968 (Appendix 8.2A)
D In. general, high. voltaqe circuit breakers are manufactured and tested in accordance with the latest recommendations and rules of the ANSI, XEEE, NEMA, and AEIC. Pennsylvania Power 8 Xight Company Substation and Relay and Control Engineering Instruction Manuals, Engineering and Construction Standards, Operatinq Principles and Practices; Relay and Control Pacilities 3/3/76 and soUn< engineering principles. The design criteria include consider-ation of aesthetics, reliability, economics, and safety. Rev. 28, 1/82 8. 2-8
SS ES-PS AR ~8,g. A~na L~gs 8.$ .~2. ~Gi~dvailabil j ty The offsite power sources provide adequate capacity and capability to start and operate sa fety related equipment. In addition, the sources provide both redundancy and electrical and physical independence such that no single event is likely to cause a simultaneous outage of both sources in such a way that neither can be returned to service in time ta prevent fuel design limits and design canditions of the reactor coolant pressure boundary from beinq exceeded. Each of the circuits from the off-site transmission netvork to the safety related distribution buses has the capacity and capability to supply the assigned loads during normal and abnormal operating conditions, accident conditions and plant shutdown conditions. The PPCL bulk power system is planned in, accordance vith established PPCL bulk power planning criteria. These criteria are based an the Reliability Principles and Standards of the Mid-Atlantic Area Council (MAAC). MAAC is a regianal reliability council of the Rational Electric Reliability Council {HERC). MAAC is camprised of the electric utility companies of the Pennsylvania-Hew Jersey-Maryland {PJM) Interconnection, of which PPCL is a member. The primary objective of MAAC is to augment reliability throuqh a continuing review of all planning in connection with additions or revisions to generating plant or bulk power transmission facilities. The PPCL bulk power system is designed to meet the MAAC Reliability,Principles and Standards, which are included in Appendix 8.2A. Digital power flov and transient stability studies vere conducted to demonstrate that bulk pover system is in compliance with the MAAC reliability criteria. The diqital power flow studies included an evaluation of all practical single contingencies, includinq double circuit tower line, outage conditions and several abnormal system disturbance conditions. Based on historical operatinq data for the PPCL transmission network, the annual forced outage rate per 100 circuit miles for 500 KV and 230 KV lines is 0.46 and 6.04 outages, respectively. The number of permanent faults per year per 100 circuit miles for 500 KV and 230 KV lines is 0. 23 and 1 79 respectively. The duration of the individual autaqes varies greatly (from 3 minutes to in excess of 8 hours) depending on the cause of the outage. The major causes of forced outaqes and permanent faults are lightninq 'and weather related phenomena, tree contacts, equipment failure or malfunction, and emergency maintenance. Rev. 28, 1/82 8 2-9
SSBS-PS AR
- 8. 2.2. 2 Stability Analysis Transient stability studies vere conducted using a digital computer program. These studies show that for various 230 KV and 500 KV bus and line faults, system stability and satisfactory recovery voltaqes are maintained resulting in uninterrupted supply to the offsite pover system. Specifically, the system is stable for any three phase fault cleared in normal clearing time and for any single phase to ground fault with delayed clearing.
The system is also stable for any three phase fault applied to the 500 KV and 230 KV transmission associated with the Susquehanna plant and cleared with delay. transient stability case list is included in Table 8.2- 1. A The loss of either Susquehanna Unit 41 or Unit l2 represents the loss of the largest single supply to the network. For the loss of either Susquehanna unit, grid stability and the integrity of supply to the offsite pover system are maintained: Grid stability and the integrity of supply to the offsite pover system are also maintained for the loss of any other single generating unit in the netvork. Supply to at least one of the offsite pover sources is also maintained for the following abnormal disturba nces:
- 1. The sudden .loss of all lines emanatinq f rom the Susquehanna 230 KV Svitchyard,
- 2. The sudden loss of all lines emanating from the Susquehanna 500 KV Switchyard.
Mo single occurrence is likely to cause a simultaneou s outage of ! all offsite sources during operating, accident, or ad verse environmental conditions. Hhile the loss of all offs ite power is improbable'uch an event vould not prevent the safe shutdown of the station because the onsite batteries and standby diesel qenerators are able to supply the necessary pover to systems required for safe shutdown. Rev. 28, 1/82 8. 2-10
SSZS-CESAR T$ B$g 8. 2-1 1982 50% OP SUHBER PEAK LOAD SUSQUEHANNA UNIT el 6 02 STABILITY CASE LIST CASE DESCRY ~XONE RESULT 3 phase fault at Susquehanna 500 KV on the Stable Sunbury 500 KV line. Fault cleared in normal 3.5 cycle clearing time. 3 phase fault at Susquehanna 500 KV on Stable the Sunbury 500 KV line with one breaker pole stuck at Sunbury. Clear Susquehanna in 3. 5 cycles. Clear remote terminal in 7. 5 cycles. 3 phase fault at Susquehanna 500 KV on Stable Hescosville 500 KV line with one Susquehanna 500/230 KV transformer breaker pole stuck. Clear remote terminal in 3.5 cycles. Clear Susquehanna in 7. 5 cycles. 3 phase fault at. Susquehanna 500 KV on Stable Sunbury 500 KV line with one Susquehanna 500/230 KV breaker pole stuck. Clear remote terminal in 3.5 cycles. Clear Susquehanna in 7.5 cycles. Phase-ground fault at Susquehanna Stable 500 KV on Sunbury 500 KV line wit,h Susquehanna 500/230 KV breaker stuck. Clear remote terminal in 3.5 cycles. Clear Susquehanna in 12.0 cycles. 3 phase fault at Susquehanna 230 KV Stable on the Susquehanna 500/230 KV transformer. Fault cleared in normal 4.0 cycle clearinq time. 3 phase fault at Montour 230 KV on Stable Susquehanna 230 KV line. Fault cleared in normal 4.0 cycle clearing time. (Reclosed after 10 seconds). 3 phase fault at Susquehanna 230 KV Stable on Montour line with stuck west bus breaker. Clear remote terminal in 4.0 cycles, clear Susquehanna in 8. 0 cycles (lose Stanton-Susquehanna $ 2 230 KV line). 3 phase fault at Susquehanna 230 KV Stable on Jenkins line with stuck Rev. 28, 1/82
SSBS-FSAR
~A~B$~82-1 ggg~tin ueQ CASE ~DSgBXPTION RESULT east bus breaker. Clear remote terminal in 6.0 cycles, clear Susquehanna in 8.0 cycles.
10 3 phase fault at Susquehanna 230 KV Stable on the 500/230 KV transformer vith one pole stuck on vest bus breaker. Clear tvo poles in'4.0 cycles, clear fault in 8.0 cycles (lose Stanton-Susquehanna $ 2 230 KV line) . 3 phase fault at Susquehanna 230 KV Stable on Harvood line vith stuck tie breaker pole. Clear tvo poles in 4.0 cycles. Clear stuck pole in 8.0 cycles (lose Sunbury-Susquehanna 230 KV line) . 12 3 phase fault at Susquehanna 230 KV Stable on E. Palmerton line vith one pole stuck on vest bus breaker. Clear tvo poles in 4.0 cycles. Clear stuck pole in 8.0 cycles (lose Stanton-Susquehanna 42 230 KV line). 13 Phase-ground fault at Susquehanna 500 KV on Stable Mescosville 500 KV line vith Susquehanna 500/230 KV breaker stuck. Clear remote terminal in 3.5 cycles. Clear Susquehanna in 12. 0 cycles. 14 Susquehanna-Mescosville 500 KV and Stable Susguehanna-Harvood (E. Palmerton) Double Circuit 230 KV crossing failure (3 phase fault on all circuits). Trip Susquehanna Unit 81 in 12 cycles. Clear Susquehanna-Rescosville 500 KV line in 3. 5 cycles. Clear Susquehanna-Harwood and Susquehanna-E. Palmerton 230 KV lines in 4.0 cycles. 15 3 phase fault near E. Palmerton on Stable all lines in E. Palmerton-Harvood R/N corridor. Clear Susguebanna-Qescosville 500 KV line in 3.5 cycles. Clear E. Palmerton-Susquehanna and Harvood
-Siegfried 230 KV lines in 4.0 cycles.
Rev. 28, i/82
C SSES-FSAR
~Tg~ 8 g-1~Cont~u~eg CASE ~E~SIPT~I R EXULT 16 3 phase fault near Susquehanna oa Stable both lines in Sunbury-Susquehanna R/M corridor. Clear Sunbury-Susquehanna 500 KV line in 3.5 cycles. Clear Sunbury-Susquehanna 230 KV line in 4.0 cycles.
17 3 phase fault near Susquehanna 500 KV S table at Sunbury 230 KV line crossing. Trip Susquehanna-Vescosville 500 KV, Sunbury-Susquehanna 500 KV ~ and Unit 02 in 3.5 cycles. Trip Sunbury-Susquehanna 230 KV in 4.0 cycles. 18 3 phase fault at Susquehanna 230 KV Stable on Harvood (Z. Palmerton) Double Circuit. Trip Harvood and E. Palmerton breakers in 4.0 cycles. 3 phase fa ult at Colum bia-Fr ack ville Stable 230 KV line crossing. Trip Sunbury-Susquehanna 500 KV line in 3.5 cycles. Trip Columbia-Prackville and Sunbury-Susquehanna 230 KV, lines in 6.0 cycles. 20 3 phase fault on 230 KV side of Unit f1 ,Stable main transformer. Trip Unit 01 main f'r t ra ns mer. Trip U ni t 41 and overtrip Unit 02 in 4. 0 cycles floss of entire station) . 21 3 phase fault at Susquehanna 230 KV on Stable Unit 01 qenerator leads vith a stuck vest bus breaker. Trip Unit 41 a nd Sta n ton 42 line in 12. 0 cycles. Rev. 28, 1/82
SSES-FS AR 8 3 ON-SITE POWER SYSTEMS 8 3. 1 - AC POWFR SYSTEMS 8.3.1.1 T)escription The on-site ac power systems are divided into Class IE and non-Class IF. systems. Fiqure 8.3-1 shows the single line of. both systems with the Class IE system identified by a dotted line enclosure. The on-. ite ac power systems consist of main generators, main step-un transformers, unit auxiliary transforme s, and diesel qenerators. The distribution, system has nominal ratings of 13.8 kV, 4.16 kV, 480 V, and 208/120 V. The off-site ac power system supplies power to plant systems through tvo start-up transf ormers. 8.3.1.2 Non-Class 'IF. ac System The non-Class TE portion of the on-site power systems Provides ac pover for non-nuclear safety related loads. A limited number of nonsafety related loads are important to the power generating equipment inteqrity and are fed from the Class IF. distribution system through the isolation system as discussed in Subsection
- 8. 1.6.1 (n) .
The non-Class XF. ac pover system distributes power at 13.8 kV,
- 4. 16 kV, 480 V, and 208/120 V voltaae levels. These distribution levels are grouped into tvo sym'metrical distribution systems emanating from the 13.8 kV buses.
All non self.-activated switchgears receive cont ol pover from the 125 Vdc control'over sources. The 125 Vdc control power sources for the non.-Class tE 13.8 kV and 4 kV switchqear breakers. and 480 V load center breakers are shown in Tables 8.3-17 and 8.3-18 respectively. Rev. 29, 3/82 8. 3-1
SS ES- FS AR
- 8. 3. 1. 2. 1 Operation The unit auxiliary transformer supplies all the non-'Class IE unit auxiliary loads except unit HVAC and Units and 2 common loads, 1
which are fed by the two startup transformers as shown on Piqures
- 8. 3-1 a nd 8. 3-2.
The unit auxiliary~transformer primary is connected to the main generator isolated phase bus duct tap (24 kV) while the secondary of the transformer is connected'to two 13.8 kV unit auxiliary buses through a nonsegregated phase bus. Durinq plant startup, shutdown, and post shutdown, power is supplied from the off-site power sources through the two startup transformers. In addition, capability is provided to transfer . the unit auxiliary buses to the startup power source to maintain continuity'of power at the unit'auxiliary, distribution system. Tn addition to the loadinq conditions mentioned in the above paragraph, the 13.8 kV .tartup buses also supply the preferred power supplies to the Class IE load groups through their respective 13.2 kV - 4.16 kV engineered safeguard transformers as discussed in Subsection 8.3.1. 3 {Figure 8.3-1) . The auxiliary bus feeder breakers from the unit auxiliary transformers and the startup tie bus section are interlocked to prevent supplying power to the startup bus from the unit auxiliary transformer.
- 13. 0 k V tie bus is provided for the two'tartup buses. A separate (not in switchqear line-up) bus tie breaker is located in the t ie bus. Xn the even t of a loss o f. star tup power supply to the 13. 8 kV startup bus, an alarm is initiated and, a time delay undervoltaqe relay initiates the tripping of the 13.8 kV incoming breaker and the rlosinq of the tie breaker. resultinq in a slow transfer'. However, this transfer is prevented is if either tie auxiliarv 13.8 kV bus beinq fed from the undervoltage hus section. This condition is sensed by th~ closure of. two {2) auxiliary>>h" contacts in series, one from each nf the unit auxiliary bus to tie-hus circuit breakers- connected to a common tie bus section. manual'nitiation of the ..ie breaker i. also provided. However, the use of. this manual control, is administrativel'y limited as an overriding means only. Under automatic operatinq conditions of the tie breaker, auxiliary switch>>b>> contacts of the startup transformer incoming breakers are also utilized as a permissive to close the ti,e breaker to prevent tyinq of. the two startun transformers.
At the 4 kV ESF power distribution suhsystem a three-way transfer system is provided to enable the ESP loads to connect to either of the two off-site power sources or to 'the standby diesel Rev. 29, 3/82 8. 3-2
SS ES-PS AR generators. Hach ESP bus i. normally connected to a preferred source which is one of two ES transformers connected respectively to the t.wo startup buses. During loss of one off-site powe source, that is, upstream of the startup bus, the startup hus undervoltaqe relay will trip the feeder breaker to the ES transformer, causinq a transfer at the 4kV ESP bus. If power loss ocrurs between the 13kV star+up bus and the 4kV ESP bus, a 4kV transfer will occur. The. 4kV ESP bus transfer is initiated by the bus undervoltaqe relay, which trips the normal incoming breaker and subsequently closes the alternate inroming breaker. This is practically a Read bus transfer. If both off-site power sources'are unavailable, the diesel generator breaker closes as soon as the diesel qenerator power is available. The above transfer mechanism allows only one source breaker to he rlosed at any one time and to ensure this, breaker auxiliary switch rontacts are used for interlocking. A manual live bus trans.fer is possible through a synchronizing device in which case an alternate source breaker is first closed and is followed by an automatic tripping of the preferred supply breaker. In t.his case the duration of the tie is merely a few cycles. Furthermore, the diesel generator can be tied with any one of the two off-site sources for an indefinite time under test condition but this does not. in any way cause the two off site power systems to be tied together. >he plant security load center is double ended, each end being supplied from one of. the 13 kV start-up buses through a stepdown transformer and is provided with a normally open tie breaker. Each hus is supplied from its own start-up source. Should one source be lost the undervoltage relay at the transformer secondary trips the bus incominq breaker. The bus undervoltage relay then initiates rlosure of the tie breaker provided the incominq hreaker has successfully tripped. Upon return of the failed source the incominq hreaker will not automatically close and can only be manually closed after the tie breaker has been trippeR. In all of the foreqoinq tie or transfer systems'here is no way that the two off-site power systems can be tied together at the on-site buses assuminq loss of one off.-site source. The 13.8 kV switchqear provide power for large auxiliary loads and 480 V 1'oad centers. The 13.8 kV switchgear feed douhle-ended 480 V load centers. A manual tie breaker is provided for each set of load centers to intertie the two load centers in the event of .failure of one load center transformer. Load centers qenerall y supply power to 480 V loads large than 100 hp and power for their respective motor control centers. The motor control renters supply 480 V loads smaller than 100 hp while 480 V, 480/277 V, 208/120 V panels provide miscellaneous loads such as unit. heaters, space heaters, lighting systems, etc. Rev. 29, 3/82 8. 3-3
SS ES-FS AR
- 8. 3. 1. 2. 2 Non-Class IE Pguipment Capacities Refer to.Figure 8.3-1 for interconnections of the following equipment. Physical locations of each of the following equipment can he found in Section 1.2.
. a)'nit Auxiliary Transformer 33/44/55 MVA, 34~ OA/FA/FOA, 550C
'37/49.3/61. 6 NVA, QA/FA/FOAL 650C 23.0-13.8 kV Grd. Y/7.96 kV Z = 9.0% 8 33 MVA b) Startup Transformer 45/60/75 225/129.9 -- 3',
MVA OA/FOA/FOAi 13.8/7.97 kV 650C Z = 15 0% 8 45 MVA LTC s 15% in 15/16% steps c) Engineered Safequard Tran former
- 10. 5/13. 12 NVA, 3(f, OA/FA, 55 C 11 76/14.7 MVA, OA/FA ~ 65~C 13.2-4.16 kV Grd. Y/2.4 kV Z = 6.8% I 10.5 MVA d) Un it Auxiliary 13. 8 kV Switchgear Buses 2000 A continuous rating, 750 MVA bracinq Xncominq breakers 2000 A continuous rating, 750 MVA 3'lass 28,000 A sym, interruptinq rating Feeder breakers 1200 A continuous rating, 750 MVA 3d Class 28,000 A sym interruptinq rating e) Startup 13.8 kV Switchqear Ruses 3000 A continuous rating, 750 MVA bracing Incoming breakers 3000 A continuous rating, 750 NVA 3g Class 28,000 A sym interrup inq'ating Rev. 29, 3/82 8. 3-4
SS ES- PS AR Tie breaker 3000 A continuous rating, 750 NVA 3'lass 28,000 A sym interrupting rating Feeder breakers 1200 A continuous rating, 750 NVA 3'lass 28,000 A sym interrupting rating f) 4. 16 k V Switchgear Buses 1200 A continuous rating, 250 HVA bracing Xncoming breakers 1200 A continuous rating, 250 NVA 3p Class 29,000 A sym interrupting rating Feeder breakers 1200 A continuous rating, 250 MVA 3'lass 2 9, 000 A sym interrupting rating g) 480 V J,oad Centers Transformers 1500/2000 kVA, 3', AA/FA, 13 200-4 80 V Grd. Y/277 V Control structure, 1000/1333 kVA, 3', AA/FA, Administration, 13200 480 V G d. y/?77 V
, Security and machine shop transformers only Buses 3000 A continuous; 65,000 A bracing (1500/2000 k VA) 1600 A continuous; 50,000 A bracing (1000/1500 k VA)
Tncoming breakers 3000 A continuous, 65,000 A sym interrupting rating (1500/2000 k VA) 1600 A continuous, 50,000 A sym interrupting rating (1000/1500 k VA) Feeder breakers 600 A continuous, 30,000 A sym interrupting rat ing Tie breakers 1600 A continuous, 50 000 A sym interrupting rating Rev. 29, 3/82 8. 3-5
SS ES-PS AR h) 480 V Motor Control Centers Horizontal bus {main) 600 A continuous; 42,000 A bracing Vertical bus ~ 400 A continuous; 42,000 A br Breakers {Molded Case) acing'5,000 150 A frame A symmetrical inter'ruptinq rating 250 A frame 22,000 A symmetrical interrup"inq rating i) 480 V Distribution Panel Bus 225 A ratinq, 14,000 A bracing Branch breakers 100 A frame, 14,000 A interrupting rating 208/120 V ac Instrument ac Distribution Panels Main breaker 225 A continuous {molded case) 22,000 A-sym interrupting rating Buses 225 A continuous Branch breakers 100 A frame size (mol d ed case) 10,000 A sym interruptinq rating 8.3.1.3 Class IF, ac Power System The Class .ZP, ac portion of the on-site power system is shown on Figure 8. 3-1. The Clas., IF. ac system distributes power at 4.16 kV, 480 V ~ and 208/120 V to the safety related loads. The safety related loads are divided into four load groups per generating unit and are tabulated in Table 8.3 Fach load group has its own distribution system and power supplies. The 4.16 kV bus of each Class IF. load group channel is provided with connections to two off-site power sources designated as preferred and alternate power supplies. Diesel generators are provided as a standby power supply in the event of total loss of Rev. 29, 3/82 8. 3-6
SSES-FS AB the preferred and alternate power supplies. Standby power supply is discussed in Subsection 8.3. 1.4. Preferred and alternate power supplies up to the 4. 16 kV buses of the Class IF, power system are considered as non-Class IE. All non self,-activated switchqears receive control power from the 125 Vdc control power sources. The 125 Vdc control power sources for +he Class 1F. 4.16 kV switchgear breakers and 480 V load center breakers are shown in Tables 8. 3-19 and 0.3-20 respect ively. In order to achieve adequate separation between channelized load qroun and divisionalized load qroup, two 125 Vdc control power supplies are provided for each 4.16 kV swi.tchqear (refer to Table
- 8. 3-1 9) .
8.3.1.3. 1 Power Supply Peeders Each Class IE 4.16 kV switchqear of a load group channel is provided with a preferred and an alternate (off-site) power supply feeder and one standby diesel qenerator feeder. Each bus is normally energized bv the preferred power supply. If the preferred power source is not -available at the 4.16 kV bus, automatic transfer is made to the alternate power source as described in Subsection 8.3.1.3.6. Tf both preferred and alterna+e power feeders become de-enerqized, +he safety-related loads on each bus are picked up automatically by the standby diesel qenerator assigned to that bus as described in Subsection
- 8. 3.1.4.
- 8. 3. 1. 3. 2 Power Feeder Cables Power feeder cables for the 4. 16 kV system are aluminum conductor, and are rated 5 kV, 900C conductor temperature with high temperaturp Kerite insulation. The cables are provided with an overall flame resistant Kerite jacket covering. For the 480 V system, cables of size 44/0 AMG and larger are aluminum conductor; cables less than 44/0, AMG are copper conductor. Both types of cables are rated 600 V, 900C conductor temperature with ethylene-propylene insulation with a flame-resistant hypalon jacket covering. The conductors are sized to carry the maximum available short circuit current fox'he time required for the circuit breaker to clear the fault. All Clas, IF. cables have been desiqned for operation as discussed in Section 3.11.
The 4.16 kV switchgear, D.C. load centers, and T).C. Contxol centers are equipped with aluminum buses and silver-plated bolted l Rev. 29, 3/82 8. 3-7
SSES-FS AR connections. The 480 V load centers and motor control centers are equipped with copper/aluminum busses and the bolted connections are also silver-plated. All circuit breaker terminals are copper. For power cable terminations, Burndy compression aluminum. terminals (HYLOG) are used. These terminals are of seamless tubular construction, tin-plated to resist corrosion, and factory filled with oxide inhibiting compound penetrox A. Compression adapters MAC ADAPT MPT series or equivalent are used for equipment/vendor supplied components havinq mechanical luqs which cannot be converted to accept a Burndy compression luq due to physical or practical limitations. A non-oxidizing lubricant such as D50H47 or equivalent will be applied on all contact surfaces at bolted joints to avoid damaqing the silver-plated contact surfaces.
- 8. 3. 1.3. 3 Bus Arrangements The Class IE ac system is divided into four load qroup channels per unit (load qroup Channels A, B, C, and D) . Power supplies for each load group are discussed in Subsection 8.3.1.3. 1. All Class IE ac loads are divided among the four -load groups s'o that any combination of three out of four load groups has the capability of supplying the minimum required safety loads.
The distribution system of each load group consists of one 4. 16 kV bus, one 480 V load center, four or five motor control centers, and several low voltage di.,tribution panels. The bus arrangements are shown on Fiqure 8. 3-1, 8.3-3, 8.3-4, 8.3-7 and
- 8. 3-8.
- 8. 3.1.3. 4 ~ Loads Suo2lied from Fach Bus Table 8.3-1 provides a listing of all the loads supplied from each Class IF., bus.
- 8. 3.1.3.5- Class IF, Isolated Swing Bus Two redundant 480 V swing buses are provided for each unit for the RHR injection valve motor operators, recirculation loop bypass valve motor operators, and recirculation discharge valve motor operators. The single line of the swing bus is shown on Fiqure 8.3-9.
A Class IE 480 V load center of one load group channel supplies the preferred power to the swing bus through the electrical isolation of a moto -generator (M-G) set. The alternate power is Rev. 29, 3/82 8. 3-8
SS ES-FS AR supplied directly from another redundant Class .XF, 480 V load center. The M-G set, is. used for elect ically isolating tvo redundant load groups. Faults at the swing bus cannot be propagated onto more than one load group. The svinq buses are Class IF, motor control center constructions. An automatic transfer svitch is provided for transferring the sving bus from the preferred to the alternate pover source upon reduction or loss of voltage at the swing bus. Tf the undervoltage is caused by a fault at the swing bus, the transfer will be prevented even svinq bus vill be if the alternate power is available. The retransferred back to preferred power vhen the voltage is restored within acceptable limits. The svinq bus and transfer switch are designed so that. for a loss of off-site power 'and any single failure, the minimum required ECCS flov to meet 10CPR50 Appendix I criteria is always available. The follovi,nq is a common mode-common cause failure analysis (CMCCFA) for the automatic transfer svitches: Figure 8.3-13 depicts a simplified single line diagram for the sving bus system to facilitate the analysis. Table 8.3-24 provides a step-by-step CRCCFA of the auto transfer svitch'by postulating the various major common causative factors {events) . Normal conservatism in desiqn and manufacturing margins, mandatory requirements of QA/OC procedures, Tnitial Test program, Preoperationa 1 Tests, applicable administrative procedures and maintenance proqrams as well as operator actions contribute to minimize the, susceptibility of the auto transfer svitch to the various common causat ive factors as analyzed in Table 8.3-24. This analysis demonstrates that the transfer switch, as a component of the swinq bus system design, will not degrade "he independence and separation betveen the redundant. Class XF. channels (load center channels A aRd C or B and D) . The test, program (Section 14.2 and Technical Specification 314.8) for the 480V svinq bus system (Figure 8.3-13) consists of: a) Periodic. inspection of virinq, insulation, and connections etc.. to assess the continuity of the components and system. b) Periodic testing to verif y the operability and f unctional performance of individual components in the system. c) Periodic testing of operational sequence and operability of the system as a whole. Rev. 29, 3/82 8. 3-9
SS ES-PSAR 8.3.1.3. 6 Manual and Automatic Interconnections Betveen Buses~ Buses and Loads and Ruses and Supplies
~
No provision exists for automatically or manually connecting one Class IP, load group to the redundant Class XE load qroup or for automatically transferrinq loads between load qroups except the svinq buses's discussed in. Subsection 8.3.1.3. 5. For each load group. one 4.16 kV feeder circuit breaker is provided for the normal incominq'preferred power source, and another 4. 16 kV feeder circuit breaker is connected to the alternate power source {see Subsection 8.3.1.3. 1) . The normal preferred pover source to each bus is electrically interlocked with the alternate power source such that the bus can be connected to a single power source at any one time. In the event. of loss of preferred power to the load group, undexvoltage relays {le. s than or equal to 15 percent voltage) on the 4.16 kV switchqear will initiate an automatic transfer to the alternate pover source "if available. In the event of losing both preferred 'and alternate pover supplies, the load grouo will be povered from the standby die el generator. Restoration of power Crom standby pover to the preferred source of offsite pover is manually initiated in the control room on panel OC653. eben the stnadby power source is in synchronism with the offsite pover source, the preferred offsite source incoming breaker is closed. Upon closing of this preferred source breaker ~ the standby source breaker vill automatically trip. This tripping is initiated by the preferred offsito source breaker auxiliary switch contact interlock. A similar procedure is used to restore pover from standby to the alternate offsite power.
- 8. 3.1.3.7 Interconnections Between Safety Related and Nonsafety Related Buses, Nonsafety Related Loads~ and Safety Related Buses Discussion of interconnections betweon safety related and non-safety related buses, nonsafety related loads, and safety related buses is prese nted in Subsections 3. 12. 2 and 8. 1. 6. 1.
Rev. 29, 3/82 8. 3-10
SS ES-FS AR 8.3.1.3. 8 Redundant Bus Separation The engineered safety features switchgear, load centers, and motor control centers for the redundant Class IE load groups are located in separate Seismic Category I rooms in the reactor building to ensure electrical and physical separation. Electrical equipment separation is discussed in Subsection 3.12.2 and Subsection 8. 1.6.1. Equipment layout d" awnings can be found in Section 1.2.
- 8. 3.1.3. 9 Class XE Equipment Capacities a) 4.16 kV Svitchqear Buses 1200 A continuous ratinq, 250 NVA bracing Incominq breakers 1200 A continuous rating, 250 NVA 3'lass 29,000 A sym interrupting cating Feeder breakers 1200 A continuous ratinq, 250 NVA 3gf Class 29,000 A sym interruptinq rating b) 480 V Load Centers Transformers (Unit 1) 750/1000 kVA 3P, AA/FA, 13800>>480 V Qrrl. Y/277 V Transf ormer (Unit 2) 750 kVA, 3P, AAi 13800-480 V Gr d. Y/277 V Buses 1200 A continuous, 30,000 A bracing Breakers 600 A frame size, 30,000 A sym interruptinq rating c) 480 V Notor Control Centers Buses Horizontal (main) 600 A continuous, 42,000 A bracing Vertical 400 A continuous, 42,000 A bracing Rev. 29, 3/82 8 ~ 3- 11
SS ES- FS AR Breakers (molded case) 150 A frame 25,000 A sym interrupting
".. ating 250 A frame 22,000 A, gym interrupt ing rating d) Automatic transfer 480 V, 3', 4 00 A sw itch continuous 31,000 A sym vithstand capability e) 208/120 V ac Instrument ac Distribution Panel.,
Buses 225 A continuous 10,.000 A sym in terrupting rating Branch breakers 100 A frame size (molded case) 10,000 A sym interrupting rating
- 8. 3. 1.3. 10 Automatic Loading and Load Shedding If preferred off-site pover is available to the Class bus follovinq 1E 4.16 kV a LOCA signal, the required ES> loads will start as shown in Tables 8.3-1 and 8.3-1b.
Tn the event of loss of preferred and alternate off-site power supplies, the Class 1E 4.16 kV buses vill shed all loads except the 480 V load centers and connect the standby diesel generator to the Class 1E bus. The loadinq sequence is shovn on Table 8.3-1.
- However, than 15%)
ifat a theslowClass bus transfer {bus voltage on trans fer is less 1E 4.16 kV bus is initiated to the alternate off-site pove as a result of a loss of preferred off-site pover, all loads are shed except the 480 V Road centers. Then the required and 8.3-1b. ESP loads vill start as shown on Tables 8.3-1 Emergency loads are also sequenced vith off-site power because of the power system limitation (..ransformer capability). .Load sequencinq is designed to minimize system disturbance. Tables 8.3-1 and 8.3-1b shov the anticipated starting time of all FBF loails. Both Unit 1 anil Unit 2 buses for a uiven diesel generator are normally supplied by the same off-site power supply. An individual timing unit is Provided for each of the Rev. 29, 3/82 8. 3-12
SS ES-FS AR ESF loads vith automatic start function. Failure to stax't on one Load vill not affect the startinq initiation of other loads. The loadinq sequence for a simultaneous LOCA in one, unit and a false LOCA in the other unit is shown in Table 8.3-1b., A false LOCA signal as used in this section refers to a non-mechanistic failure resultinq in a LOCA signal in one reactox'nit when a Y.OCA has not occurred in that, unit. The load startinq transient on the diesel qenerators is reduced i f the Unit 1, and Unit 2 load sequences do not start simultaneously. Tf off-site power is available, the LOCA signal in one unit and false LOCA sianal in the other vill shed 2 RHH motors and 2 coxe spray motors of each unit and sequentially start 2'RffR and 2 core spray motors as shown. in Table 8.3-1h. This is done in order not to exceed the loading limitations of the ES Transformers and to provide at least the minimum core cooling requirements of both uni+s. Under the modified core cooling arrangement, 2 HHR pumps {one in each loop) and 2 core spray pumps {both in the same loop) will satisfy the minimum coolinq requirements of each unit. Approixmately ten minutes after the above event the opera to will be able to determine which is the false-LOCA unit and shutdown non-essential loads in the non-LOCA unit. 1n case off-site power is not available, the loadinq is the same as discussed above, but the sequencing is slightly altered as shovn in Table 8;3- 16. Under all conditions discussed in Subsections 8.3.1.3.10.1 and
- 8. 3.1.3. 10.2,'afety functions are met within the time limits shown in Table 6. 3-1.
- 8. 3.1,3. 11 Saf ety pela"..e.d Equipment Ident ification Subsec,ion 8. 3.1. 11.3 provides information xegarding the physical identification of. Class XH equipment.
8.3.1.3.12 Xnstrumentation and Control Systems for the Applicable Power Systems with the Assigned Power Supply Tdentified The dc power supplies for the control of the redundant Class XE equipment are physically and elect" ically separate and independent. Refer to" Subsection 8.3.2 for a detailed discussion of the dc system. Rev. 29, 3/82 .8. 3-13
SS ZS-PS AR 8.3.1.3.13 Electric Circuit Protection Systems Protective relay schemes and direct-acting trip devices on primarv and backup circuit breakers are provided throughout the on-site power system in order to: I a) Isolate faulted equipment and/or circuits Crom unfaulted equipment and/or circuits b) Prevent damage to equipment c) Px ot.ect personnel d) minimize system disturbances e) Maintain continuity of the power supply Major types of protection measures employed include the fol lo wi nq: a) Bus Differential Relaying A bus differential relay is provided foreach Class IE
- 4. 16 kV bus. This relay provides high speed disconnecting of bus supply breakers to prevent propaqation of internal bus .fault to another bus.
b) Overcurrent Relaying Bach Clas., IE 4.16 kV bus feeder circuit breaker is equipped with thxee extremely invexse-time overcurrent relays to sense and to protect the bus from an overcurrent condition. The standby diesel qenerator feeder circuit, breaker to the 4.16 kV bus is equipped with three voltage restrained overcurrent relays and one inverse-time ground fault relay for feeder circuit protection. Each 4.16 kV motor feeder circuit breaker has three overcurrent relays, each with one lonq time and one instantaneous element for ovexload, .locked rotox, and short-circuit protection. Each breaker is also equipped with an instantaneous ground current relay. Each Class IE 4.16 kV supply circuit breaker to a 480 V load center transformer i protected by three overcurrent relays with lonq-time and instantaneous elements. An instantaneous, overcurrent ground sensor relay provides sensitive ground fault protection. Rev. 29, 3/82 8. 3-14
SS ES-'PS AR c) Under/Overvoltaqe Relaying Hach 4.16 kV Class IF. bus is equipped with undervoltaqe relays for diesel generator starting and undervoltage annunciation. Each 4kV bus is provided with degraded grid voltage protection. Hach 480 V Class ZE .load center bus is equipped with under/overvoltaqe relays for annunciation. d) Diesel Generator Differential Relaying Each diesel generator is equipped with differential relayinq protection. This circuitry provides high speed disconnection to prevent severe damage in case of diesel qenerator internal faults. e) 480 V Load Center Protection Hach load center circuit breaker is equipped with integral, solid-state, dual magnetic, ad ju., table, direct-action trip devices providing inverse-time overcurrent protection. Motor feeders are equipped with lonq-time overcurrent and instantaneous short-circuit protection. f) 480 V Rotor Control Center Protection Molded-case circuit breakers provide inverse-time overcurrent and/or instantaneous short circuit protection for all connected loads. For motor circuits, the molded-case circuit breakers are equipped wi+h an adjustable instantaneous magnetic trip function only. Notor thermal overload protection is provided by the heater element trip unit in each phase of the motor feeder circuit. The molded-case breakers for nonmotor
.feeder circuits provide thermal inverse-time overcurrent protection and instantaneous short circuit protection. The thermal overload trip units for safety related motor-operated valves are normally bypassed except during maintenance tests.
The circuit protection system is desiqned so that fault isolation is secur ed with a minimum circuit interruption. The combination of. devices and settings applied affords the selectivity necessary to isolate a faulted area quickly with a minimum of disturbance
+o the rest of the system.< The protective devices ere preoperationally tested in accordance with +he requi ements of Chapter 14. After the plant is in operation, periodic tests will be performed, to verify the protective device calibration, set points, and correct operation in accordance with the requirements
-o f Chapter 16. Rev. 29, 3/82 8. 3-15
SS ES- FS AR B. 3. 1. 3. 14 . Testing of the ac System During Power Operation All Class IP, circuit breakers 'and motor starters, except for the electric equipment associated with Class ZE loads identified in Subsection 8.3.1.3.15, are testable during reactor operation. Durinq periodic Class IP, system tests, subsystems of tho ESP system such as safety in)ection, containment spray, and containment isolation are actuated, thereby causing appropriate circuit breaker or contactor operation. The 4.16 kV and 480 V circuit breakers and control circuits can also be tested independently while individual equipment is shut down. The circuit breakers can be placed in the test position and exe cised without operation of .the related equipment. B. 3. 1. 3. 15 Class 1P~ Loads not Tgstable During Power Operations Peedwater Line Isolation Valves The feedwa+er line isolation valves (HV-F032 A/8) are of the mo+or operated check valve type and'are not +estable with the feedwater flow present. Motor operation is not required for isolation. Only the outermost isolation valve is Class 1P. powered and would be motor operated for long term isolation after isolation of the feedwater line. Conformance with Regulatory Guide 1.22 Section D.4:
- 1. The feedwater isolation is not designed for isola ion with Eeedwater flow present as the loss of flow would adversely affect operability of the plant.
- 2. Motor operation is not'equired for isolation.
The motor operator of the outermost isolation valve is fully testable durinq shutdown. B. Mai n Steam Isolation Valves The'ain 'steam i.solation valves can be tested individually to the 90% open posi+ion at full powerOwith the slow acting test solenoid valve. A f ully closed test using the two fast acting 'main solenoids would require a reduction in ractor power. Conformance with Requlatory Guide 1.22:
- 3. 2a. 2. 2. 1. 2 and 5. 4.5. 4.
See Subsections C. ADS System - Safety/Relief Valves Rev. 29, 3/82 8. 3-16
The active components of the ADS system except the saf ety/relief valves and their associated solenoid valves are designed so they may be tested during plant power operaiton. The relief, valve and associated solenoid are not tested durinq reactor power operation. Conformance with Requlatory Guide 1. 22: The safety/relief valves are not tested, during power operation because of resultinq adverse affect on plant'operation.
- 2. Because of low failure rates of valve actuation, the probability of failure is acceptably low without testing.
- 3. The safety/relief valves and associated solenoid valves can be tested durinq startup following shutdown.
Rec ircu la t ion Loop Isolation Valves The recirculation pump isolation valves are not tested during reactor power operations. Conformance with Regulatory Guide 1.22 Section 9.4: Operation of a recirculation loop isolation valve would result in a reduction of circulation which would adversely affect the safety and operability of the plant.
- 2. The probability of failure is accep'tably low without testinq the valve motor during operation.
The valve and motor are fully testable during reactor shutdown. 8.3.1.4 Standby Power Supply The standby power supply for each safety related load qroup consists of. one diesel generator complete with its accessories and fuel st'oraqe and transfer systems. Each diesel generator is rated 4000 kw at 0.8 pf for continuous operation and 4700 kw for 2000 hr operation. The ratings for each diesel gene ato are 'calculated in accordance with the recommendation of Regulatory Guide 1. 9 (discussed in Subsection 8. 1. 6. 1) . The diesel-qenerators ran, operate at loads ot from 50 to 100 percent for unlimited periods without harm. Any diesel generator continuously operated at loads of less than 50 percent will be loaded to 75-100 percent for 15-30 minutes approximately every Rev. 29, 3/82 8. 3-17
SSES-FSAB six hours and immediately prior to shutdown. Any diesel generator continuously operatinq at loads of less than 50 percent for less than six hours will be loaded to 75-100 percen+ for 15-30 minutes immediately prior to shutdown. Such operation vill enhance engine performance and reliability. The four diesel qenerators are sha~ed by the two units. Each diesel generator is connected to the 4.16 kV bus of the assiqned load qroup per unit. The capacity of the diesel generators (assuminq one diesel fails) is sufficient to operate the engineered safety feature" loads of one unit and those systems required for concurrent safe shutdown of the second unit. No provisions axe provided. for parallel operation of. the diesel qenerator of. one load group with the diesel generator of the redundant load group. The diesel, qenerator circuit breaker and the off-site power incoming circui+ breakers are interlocked to orevent feedback into the off-site power system. These interlocks are bypassed during diesel generator load tests; however, only one unit is tested at any one time. During the test period, the diesel generator under test is manually synch.ronizecl to the. preferred off-site power system. Upon eceipt of a LOCA signal under the test condition, the diesel generator breaker is tripped but the diesel generator continues to T un. The diesel generators are physically and electrically isolated from each o+her. Physical separation for fire and missile protection is provided between diesel generators by separate rooms within a Seismic Category I structure. Power and control cable for each of the diesel qenexato s and associated switchqea are routed in separate raceways. Physical electrical equipment. layout of the diesel qenerator rooms i. shown on Figure 8.3-10. Auxiliaries xequired for startinq and continu'ous operation of each diesel qenerator are fed by the Class IE power load qroup associated with that diesel generator. Control power for each diesel qenerator is provided by its correspondinq 125 V dc system.. from both Uni+ 1 and Unit 2. These two power feeders are not redundant, but have been provided for ease of maintenance. Indication of which unit is supplying the dc control power is not provided in the control room. Manual switches are installed at the local panel to select the preferred power feeder. Since each diesel generator is shared by both units, either source of DC control pover is adequate. T.oss of DC power to the Diesel Generator is indicated on the HIS panels as a group trouble alarm on panel OC653 in the main control room. Each diesel qenerator is provided wi+h a local engine control panel, a qenerator-exci+er contxol panel, a local 4.16 kV Rev. 29, 3/82 8. 3-18
SS ES-FS AR distribution panel, and a 480 V motor control center in the diesel generator room. Local Engine Control Panel consists of a local annunciator, engine control devices, gauges, and control for diesel generator auxiliary equipment such as fuel oil transfer pump, standby jacket water pump, et r.. The diesel qenerator control system is desiqned in such a manner that some control devices are mounted in the free standing control panel separate Crom the engine, while others are mounted directly on the engine, as required for reliable service. All devices that are essential to the start-up or power output of the di.esel-generator set have been seismically qualified by analysis or test to acceleration levels consistent with their mounting loca tion. b) 4enerator-Exciter Control Panel - consists of generator excitation control equipment, generator protective relays and devices, etr.. 4.16 kV Distribution Panel provides connections for diesel qenerator feeders to Unit 1 and 2. Also houses potential transformers and current transformer, etc. 480 V Motor Control Center provides power to all 480 V auxiliary equipment related with tha> diesel qenerator. This HCC is equipped with an automatic transfer switrh for connection to either Unit 1 or 2 480 V Class IE load center. These two load centers helonq to the same load qroup channel as the diesel generator. Physical separation of standby power system is discussed in Section 3. 12.
- 8. 3. 1. 4. 1 Automatic Stagt in'nitiat in'irc ui t h
diesel generators are automatically started by any of the
~
k The following conditions: a) Total loss of power to the 4.16 kV Class XK bus of either 'unit to which the diesel qeneratoz i.s connected ! b) Safety injection siqnal low water level i.n the t ~ reactor, hiqh drywell pressure, or manual actuation. Rev. 29, 3/82 8. 3>> 19
SS BS- FS AB Two redundant control/starting circuits are provided, fo each diesel qenerator. Failure of one circuit would not prevent the respective diesel generator from starting or from continuous opera tin,n. The diesel generators are ready to accept loads within 10 sec after the initiation of the start circuit.
- 8. 3.1. 0. 2 Diesel Starting Mechanism and System The diesel qenerator start system is described in Subsection 9.5.6. To ensure fast and reliable starting, each diesel enqine is provided with immersion heaters in the engine jacket, water and oil the lube oil sy.,tern to maintain the engine coolant and lube temperature at an operable level. The electric jacket water immersion heater and the water circulatinq pump are interlocked for simultaneous operation when the jacket water temperature drops below the preset temperature. The electric lube oil immersion heater and the prelube circulatinq pump axe interlocked for simultaneous operation when the engine is below 280 rpm.
Refer to Subsection, 9.5.5 and 9.5.7 for further des" ription. 8.3.1. 4,3 Alarm and 'stripping Deyic:e The nrotective and alarm logic diagrams for the diesel generator and its associated breakers are shown on Fiqures 8.3-11 and 8.3-12. While supplying loads followinq an automatic start, each diesel engine and related generator circuit breaker are tripped by
, . protective devices under the followinq conditions only:
( a) Engine overspeed b) Lube oil low pressure c) (:one rator differential To prevent spurious tripping of the diesel qenerator due to malfunction of the enqine lube oil low pressure trip device, four independent sensors are provided and connected in a coincidence one-out-of-t wo taken twice tripping logic. An individual tripping alarm is provided by the annunciator at each local control panel. The startinq circuit. is also equipped with a "fail to start" relay operator that interrupts the sta t.ing of the diesel Rev. 29, 3/82 8. 3-20
SS ES-FS AR qenerator limited if a predetermined speed is not reached time followinq start initiation. a wi~ hin a E Xn addition to the above-listed trips, each generator circuit breaker is tripped by the followinq protective relays to disconnect the qenerator from a faulty bus (the diesel generator continues t.o run): a) Voltaqe restrained overcurrent b) 0 kV bus di fferent ia 1. Followinq a manual stark, a diesel generator is in the test mode and ready for a load test. Mhen so operated, in addition to the above-Listed trips, each diesel engine.and related generator circuit breaker are automatically tripped by the followinq protective devices: a) Generator loss of field t b) Generator overexcitation c) Antimotorinq d) Generator underfrequency e) Generator overvoltaqe f) Generator hiqh bearinq temperature q) Hiqh Jacket water temperature h) Turbo lube oil, pressure Low i) Main and connectinq rod bearinq temperature high jl Pngine vibration k) Turbo th rust bear in q fa ilure. An individual alarm is also provided for each of these abno=mal conditions at the Local control panel. A group alarm is provided in the main control room as a high priority alarm. Other relavs and devices are provided to annunciate abnormal diesel engine and generator conditions at the local control panel as followinq. These conditions are annunciated in the main control room as a low priority alarm. a) Generator field around b) Generator voltage unbalance Rev. 29, 3/82 8. 3-21
SSES-7S AR c) Generator neutral overvoltage d) Enqine lube oil pressure high e) Crankcase pressure high f) Engine lube oil temp of f normal q) Engine crankcase level low h) Auxiliary standby pump on i) Jacket water temperatu e off normal j)"= Jacket wa+er low pressure k) Fuel oil pressure high
- 1) Fuel oil pressure low m) Fuel strainer hiqh ditferential pressure n) Fuel filter hiqh differential pressure o) lube oil filter high differential pressure p) Starting air system low pressure or malfun,.tion g) Voltage regulator trans fe". to standby r) Jacket water standpipe level hiqh s) Jacket water standpipe level low t) Fuel oil day tank level high u) Fuel oil day tank level low v) Fuel storage tank level high w) Fuel storage tank level low x) Motor control center not proper for automatic operation (actuated hy hlown control fuse, e+c.)
Control switches not proper fo remote automatic operation (diesel generator auxiliaries) Luhe oil circulating pump malfunction aa) Lube oil heater malfunction Rev. 29, 3/82 8. 3-22
SSES-PS AR bh) Jacket wat er heat er mal function cc) Jacket water circulating E pump malfunction The followinq alarms are provided in the main control room annuncia tor: a) Diesel genera tor tripped b) High priority alarm (all trip conditions listed previously c) Low priority alarm (all abnormal conditions listed previously d) Diesel generator breaker tripped e) Diesel generator fails to sta t ~ f) Diesel generator near full load q) Diesel qenerator not in automatic mode.
- 8. 3.1,4. 4 Breaker Interlocks Interlocks have been provided in the closing.and tripping of the
- 4. 16 kV Class IH circuit breakers to protect against the following conditions:
a) Automatic energizing of electric devices or loads durinq maintenance b) Automatic closinq of the diesel generator breaker to any energized or faulted bus c) Connectinq two sources ou+ of synchronism Rev. 29, 3/82 8. 3-23
SS ES- PS AR
- 8. 3.l~4. 5 Control Pegmissgve A sinqle key-operated switch at the local control panel is provided for each diesel qenerator to block automatic start signals when the diesel is out of service for maintenance. An annunciator alarm in the main control room and an indication at the bypass-indication-system panel indicate when the switch is not in automatic position.
A pushbutton in the control room and a local pushbutton at the local control panel in the diesel qenerator room are provided to allow manual start of the diesel when all protective systems are permissive. During periodic diesel generator tests, permissives and inte locks are designed to permit manual synchronizing and loadinq of the diesel generator with either off-site power source. A key operated switch at the local control panel is provided for each diesel qenerator to regain speed and voltage control of the diesel generators followinq a loss of and subsequent restoration of offsite power. This permits the diesel generators to be synchronized to the offsite power source, while maintaining the diesel generator in the emergency mode of operation. An annunci-ator alarm in the main control room indicates when the switch is not in the normal position. 8.3.1.4.6 Loading Circuits Upon automatic starting of the diesel (emergency mode), connection of the diesel generator to the 4.16 kV bus is not made unless both off-site power sources are lost. As the generator reaches the predetermined voltage and frequency levels, control relays provide a permissive signal for the closing of the respective diesel generator breaker to the corresponding 4.16 kV bus. The diesel generator circuit breaker is closed within 10 sec. after the receipt of the starting signal. The required safety related loads are connected in sequential order to the Class XE buses as shown in Table 8.3-1. This prevents diesel generator instability and ensures voltage recovery thereby minimizing motor accelerating time. A fast-responding exciter and voltage regulator ensures voltage recovery of the diesel generator after each load step. Rev. 32, 12/82 8. 3-24
SS ES- PS AR 8.3 1.4.7 Testina Preonerational Test Each diesel qenerator is tested at the site prior to reactor fuel loadinq in accordance with requirements of Chapter 14. Periodic Testinq After beinq placed in service, the standby power system is tested periodically to demonstrate continued ability to perform its intended function, in accordance with the requirements of Chapter 16. 8.3.1.4.8 Fgeg gjg Sfgggge and transfer System The diesel qenerator fuel oil system is described in Subsection
- 9. 5.4.
8.3~1.4~9 Die@el Genegatog Cooling gnd Hegtlng The diesel generator coolinq system is described in Subsection 8.3.1.4.10 Instrumentation and Control Systems for The instrumentation and control circuit of each diesel generator is provided with a manual selector switch for connection to either Unit 1 or 2 125 V dc power supply. These two power supplies belong to the same load qroup channel to which the diesel qenerator is connected. Control hardware is provided in the control room for each diesel qenerator for the followinq operations: a) Startinq and stopping
')
Synchronization 4 h ~,. I c) Frequency and voltaqe adjustment 0 ' d) Manual or automatic voltaqe regulator selection e) 'Isochronous and droop selection. Rev. 32, 12/82 8. 3-25
SSES-FSAR Control hardware is provided. at each local control panel for the followinq operations: a) Startinq and stopping Frequency and voltage adjustment c) Manual or automatic diesel qenerator mode (key lock selector switch) d) Automatic or manual voltaqe regulator selection e) Normal or standby voltage regulator selection f} Units 1 or 2 dc control power supply selection. Electrical meterinq instruments are provided in the control room for surveillance of the diesel qenerator: a) Vol taqe b) Current c) F requency d) 'ower output. Electrical meterinq instruments are provided at the local control panel for surveillance of the diesel generator: a) Voltage b) Current c) Frequency d) Power (watt) output e) Reactive power (var) output. 8 3.e 1.4. a o 11 Oualification 0 a 1 Test Program q Rev. 32, l2/82 8. 3-26 I
SS ES-PS AR
- 8. 3.<< 1 ~ 4.~ 11 ~ 1 Class a XE E Eaui 6 ament D Identif ication The diesel-generator sets are designated Class IE since they perform essential safety-related functions. Therefore, the equipment was qualified per XEEE 323-1971 and documented in Cooper Enerqy Services (CES) Report OCE-0188-1. The diesel engine, synchronous generator, and auxiliaries, such as heat exchangers, air receivers, and fuel tanks were qualified.
8,3,1,4~11,2 Quggifggatjon Techgigues and Doc@mentation All testinq conducted by CES for the Susquehanna SES diesel-generator sets provides the basis for data evaluation of future, onqoinq, periodic, jobsite testing. Periodic exercising of the diesel-qenerator sets shows availability and reliability. Data taken durinq those tests will be compared to data taken under correspondinq load conditions during factory testinq. By comparison, trends which may indicate equipment degradation are developed and utilized to predict maintenance intervals. Testing and analyses completed to verify equipment performance ,capability are as follows: a) Testinq performed on the first generator of this contract included the following parameters, with testinq procedures as outlined in ZEEE 115. Refer to Electric Products test report for generator serial number 17402243-200 dated 5-20-76 for documentation of test results. Synchronous impedance curve.
- 2. zero power factor saturation curve.
- 3. Losses (for efficiency calculation).
4 Direct-axis synchronous reactance.
- 5. Negative sequence reactance.
- 6. Direct-axis transient reactance.
- 7. Direct-axis transient open circuit time constant.
- 8. Open circuit saturation curve.
Start circuit test. Rev. 32, l2/82 8. 3-27
SS ES- FS AB b) Testinq performed on each generator furnished under this contract included the followinq parameters with testing procedure as outlined in IEEE 1 15. Refer to Electric Products test report for generator serial numbers 17402244/246-200 dated 6/22/76 for documentation of test results.
- 1. 1nsulation resistance.
- 2. High potential tests.
- 3. Mindinq resistance.
- 4. Overspeed.
- 5. Phase sequence rotation.
- 6. Nechanical balance. il c) Testing was performed on each assembled engine-qenerator set per XEEE 387 and included the following.
Refer to CES test procedure T1-TS and to CES reports for enqine serial numbers 7157-60 for documentation of test results.
- 1. High potential testing of control wiring.
- 2. Neasurement of engine vibration;
- 3. 'ast start capability.
Transient performance evaluation.
- 5. Steady state load capability.
- 6. Load rejection.
- 7. Number of starts from a single air receiver.
- 8. Performance evaluation of power factor discriminator and standby voltage regulator.
d) Functional auxiliaries, such as lube oil pumps, )acket water pumps, heaters, and coolers were evaluated to ensure proper operation during the assembled engine-qenerator set testinq described in c above. The functional capability of the auxiliaries is documented in the test loq section of the CES reports for engine serial numbers 7157-60. The establishment of adequate pressures and temperaures in the lube oil, cooling water, and fuel oil systems confirms correct operation of auxiliaries. Rev. 32, 12/82 8. 3-28
SS ES-FS AR e) Enqine and generator control panels were assembled and tested with their respective engine-generator sets and evaluated for proper control and monitoring. Refer to CES reports for engine serial numbers 7157-60 for test results. The achievement of engine-generator transient and steady state performance confirms correct operation of control panels. f) To evaluate the seismic effects on the safe shutdown capability some tests have been performed, but most evaluations were achieved by analysis. Both CES and vendor furnished equipment, which are essential to the power output capability of the generator, have been seismically evaluated and determined adequate to meet the specified response spectra with no loss of functional or structural integrity. Refer to CES seismic reports numbered CES-1 through CES-49 for documentation of seismic analyses and tests. 8,3,1,4,11,3 Performance In Service Environment Actual performance requirements and service conditions are achievable in the field installation only. Simulation of performance is attained through computer technigues which comparatively analyze motor startinq data taken during factory testinq with motor load starting characteristics predicted for the essential pumps-motors to be started at the jobsite. S'imulation of service environments, such as the predicted diesel generator room ambient temperature, would require an environmental chamber larqe enouqh to store the entire engine-qenerator set. Jn order to ascertain the ability of this equipmen+ to perform in the predicted environment, operating experience and design experience are used. The varied types of enqines designed, the varied installation applications, and the resultant experience gained have determined the capabilities of t his equipment to perform under different service conditions. This experience is augmented by previous and ongoing RGD testing of a similar CES Type KSV engine where specific, data may be needed relative to particular performance requirements. However, much of this data is proprietary. As a result of this experience and testing, in Se"tion it is concluded the service conditions described 3. 11 can be accommodated while fulfilling the performance requirements. For example, installation elevations of up to 1500 feet are accommodated without any deratinq or design modification. The 676 feet elevation for the Susquehanna SFS diesel-generator sets falls well within this ranqe. To accommodate variance in combustion air temperature, coolers/heaters are supplied which toeither add the heat to or take heat from combustion air as needed provide
- 8. 3-29 Rev. 32, 12/82
SS ES-FS AR necessary manifold air temperature. The range. of -19 F to +lOSDF air 'temperature is therefore accommodated. In addition, all service water heat exchanqers'buildupare designed with of specified fouling factors incorporated permitting the amounts of dirt or sludge vhile maintaining the necessary heat transfer characteristics under the most adverse load and cooling water temperature conditions. Particles or minerals in the service water are therefore accommodated in heat exchanger design. Seismic effects are taken into account analytically and by test for all essential components and systems of the diesel-qenerator se ts. 8.3.1.0.12 Cogtgog agd glagg Lyric The "ontrol and alarm logic for the diesel generators is shown on Fiq. 8.3-12. Conditions which render the diesel gene ra tor incapable of responding to an automatic emergency start are shown on Table 8.3-16. The follovinq is an item by item analysis of, each of these conditions: General Note The diesel qenerator vill be tripped by (1) qenerator differential relay, (2) engine overspeed, and (3) lov engine lube oil pressure (one-out-of-tvo taken tvice logic} under emergency operation. For test operation, the diesel generator vill be tripped by all conditions listed under "Diesel Generator High Priority" alarm as shown on Figure 8.3-12. Following a manual stop, no reset is necessary for subsequent emergency or test operation except the mode selector switch must be returned to >>Remote>> position. This condition is annunciated locally and in the control room. Following a trip, the control circuit must be reset. The diesel qenerator trip is also alarmed locally and in the control room. There are tvo enqine starting circuits for each diesel generator for added reliability. Fach circuit is supplied from the same 125 V battery system but through separate circuit breakers. Only one circuit is required for starting and keeping the diesel qenerator in a runninq mode. Therefore, any single component failure (as listed in Column B of Table 8.3-16) cannot prevent the diesel generator from starting.
- 1) ID- B. 1 Generator Differential Relay activated A generator differential relay is provided for each diesel generator for internal fault protection. This relay will Rev. 32, l2/82 8.3- 30
SSES-FS AR trip the diesel qenerator under any mode of operation. The diesel qenerator differential alarm is annunciated locally and repeated as a group alarm>>Diesel Generator High Priority Trouble>> in the main control room.
- 2) ID-B.2 Enqine Overspeed Relay activated An independent overspeed sensor is provided for each diesel generator starting circuit. Activation of any one sensor is alarmed, but vill not prevent the diesel generator from startinq or runninq.
ID-B.3 Enqine Lube Oil Lov Pressure Relay activated Each of the control circuits have tvo independent engine lube oil low pressure switches arranged during in a one out of tvo loqic. Pressure switches are bypassed engine startinq. Therefore, alarm is initiated for any one pressure switch (or relay) activation. Disabling of the diesel generator can only be accomplished with one engine lube oil lov pressure relay activated in each control circuit.
- 4) ID-B.4 Operatinq Mode Switch in>>Local>>
Operatinq mode svitch (key locked) is put on "Local" for local testing and maintenance services only. "Local position" is annunciated in the main control room as>>Diesel Generator not in Auto.>> Alarm is also indicated in the Bypass Indication System (BIS) on "Diesel Generator Svitch in Local<<(also in the main control room). Automatic bypass of the>>Local>> operating mode under emergency condition is not provided. Only one diesel generator vill be tested or taken out for service at. any one time.
- 5) ID-B.5 Loss of 125 VDC Engine Control Power As discussed above, tvo separate control circuits are provided for each diesel generator. Alarm is indicated locally and annunciated in the main control room as "Diesel Generator Hiqh Priority.>> Indication is also provided at the BIS panel. Loss of either circuit vill not prevent the diesel qenerator from startinq or operatinq.
- 6) ID-B. 6 Control Relay Malfunction Control. relays can fail in either contact open or closed state. Since there are tvo circuits provided assuming a sinqle relay failure, the diesel generator will not be prevented from startinq or operatinq.
- 7) ID-B.7 Engine 8 Generator Mechanical Trouble Rev. 32, l2/82 8 3-31
SSES-FS AR Low priority and high priority trouble alarms are provided for enqine and generator mechanical" trouble as shown on Fiqure 8.3-12 and Table 8.3-16.
- 8) ID-B.8 Startinq Air Control Solenoid Valve Failure There are two starting air solenoid valves for each of the two startinq circuits for each D/G. Loss of any three startinq solenoids will not prevent the diesel generator from star tinq.
- 9) ID-B.9 Startinq Air System Trouble See (9) ID-B.9 and Section 9.5'.6 for a complete starting air system discussion. The startinq air pressure is monitored at all times with annunciation provided locally and in the main control room.
- 10) ID-B.10 Fuel Oil Control Solenoid Failure One fuel oil control solenoid is provided in each of the two control circuits for each diesel-generator. A failure of either fuel oil control solenoid will not prevent the diesel qenerator from startinq.
- 11) ID-B.11 Loss of 125 VDC Generator Control Power Loss of the qenerator control power will prevent the opera tion of the excitat ion sy stem. Indication is provided at the Bypass Indication System as ~~Excitation Control Power Loss" (Main Control Room) .
- 12) ID-B.12 Disabling of Enqine and Generator Mechanical Parts During Maintenance Services Before the diesel generator is taken out of the automatic mode for maintenance services, the operating mode selector switch must be in "Local" position as required by maintenance procedures. This will result in an alarm in the main control room as "Diesel Generator not in Auto" (>>Diesel Generator Control Switch in LOCAL" in BIS panel) .
No alarms are specifically provided for monitoring of engine and generator mechanical parts under the subject condition. Conclusi on go modifications are necessary as a result of this evaluation because adequate alarms and indications are pxovided in addition to the alarm redundancy of the control circuits. Rev. 32, 12/82 8 3-32
SSES-PSAR" 8.3.1.5 Electrical gqgipment Layout I Class IE switchqear, load centers, motor control centers, and distribution panels of redundant load groups are in separate rooms of the reactor buildinq and the control structure. Standby diesel qenerators and associated equipment are in separate rooms of the Seismic Cateqory I diesel generator building. Each room is provided with a separate ventilation syste m. Plant layout drawinqs are included in Section 1.2. The reactor protection system (RPS) power supply is a non-Class IE system. The normal 120 V ac power to each of the two reactor protection systems is supplied, via a separate bus, by its own high inertia motor qenerator set. The drive motor is supplied from a 480 V Class IE motor control center. High inertia is provided by a flywheel. The inertia is sufficient to maintain voltaqe and frequency within 5 percent of rated values for at least 1.0 sec following a loss of power to the dr'ive motor. The alternate 120 V ac power for each of the reactor protection systems is supplied by a non-Class IE motor control center throuqh a 480-120 V, 1'ransformer. A selector switch is provided for the selection of., the two power supplies. The switch also prevents parallelinq the motor generator set with the alternate supply. The electrical protective assembly {EPA}, consisting of Class 1E protective circuitry is installed between the RPS and each of the power sources. The EPA provides redundant protection to the RPS and other systems which receive power from the RPS busses by actinq to disconnect. the RPS from the power source circuits. The EPA consists of a circuit breaker with a trip coil driven by loqic circuitry which senses line voltage and frequency and trips the circuit breaker open on the conditions of overvoltage, undervoltaqe and underfrequency. Provision is made for setpoint verification, calibration and adjustment under administrative control. After tripping, the circuit breaker must be reset manually. Trip setpoints are based on providing 115 VAC, 60 Hz power at the RPS logic cabinets. The protective circuit functional range is + 10% of nominal AC voltage and -5% of nominal frequency. Rev. 32, 12/82 8 3-33
SS ES-FS AR The EPA assemblies are packaqed in an enclosure designed to be wall mounted. The enclosures are mounted'n a seismic Category I structure separately from the motor generator sets and separate from each other. Two EPAs are installed in series between each of the two RPS motor-generator sets and the RPS busses and between the auxiliary power sources and the RPS busses. The block diaqram in Figure 7.2-9 provides an overview of the EPA units and their connections between the power sources and the RPS busses. The EPA is designed as a Class lE electrical component to meet the qualification requirements of IZEE 323- 1974 and IEEE 344-1975. It is designed, and fabricated to meet the assurance requirements of 10CPR50, Appendix B. quality The enclosures containing the EPA assemblies are located in an area where the ambient temperature is,between 40~F and 122~P. The circuits within the enclosure are qualified to operate under accident conditions from 400F to 137~P ~ at 10% to 95% relative humiditv and survive a total integrated adiation dose of 2x105 rads. The assemblies are seismically qualified per IEEE 344-1975, to the Safe Shutdown Earthquake (SSE) and Operating Base Earthquake acceleration response spectra and environmentally qualified to the requirement of IEEE 323-1974. The enclosure dimensions are approximately '16x24x8 inches and accommodate power cable sizes from 7 AWG to 250 HCN. 8.3.1.7 Class IE 120 V ac Instrumentation and Control
~ -. Power Supply Four independent Class IE 120 V ac,instrumentation and control power supplies are provided to supply the four channels of engineered safety features load groups. The four bus arrangement provides a separate sinqle-phase electric power supply to each of the four protection channels that are electrically and physically isolated from the other protection channels. Each power supply consists of a 480-120 V transformer and a distribution panel. The 480 V power supply is provided by the correspondinq 480 V Class IE motor control center.
There is no manual or automatic transfer between the four 120 V ac Class IE panels. There is no automatic loadinq or load shedding of the panels. Rev. 32, 12/82 8 3-34
SSES-FSAR 8,3.1.g Non-C3.ass IE Instrument and Vital ac power Supply Two 208/120 V non-Class IE instrument ac power supplies per unit furnish reliable power to non-Class XE miscellaneous instrumentation systems. The non-Class IE instrument ac power supply for each unit consists of two subsystems, each with a requlatinq transf ormer, an automatic transfer switch, and a 208/120 V distribution panel. Each distribution panel is supplied as an associated circuit from two Class IE motor control centers. The transfer switch maintains separation between the two Class IE power supplies, and the redundant breakers act as an isolation system between the Class IE power supply and the non-Class IE l oad. Two 208/120 V non-Class IE vital ac power supplies (uninterruptible power suppliesj per unit supply essential non-Class lE equipment such as the plant computer. Each vital ac power supply consists of one inverter, automatic transfer switch, manual bypass switch, and distribution panel (s) . Normally, the distribution panel is supplied by the inverter. Each inverter is supplied by a separate Class IE 250 V dc sub. ystem as described in Subsection 8.3.2. If the inverter is inoperable or is to be removed from service for maintenance or testing, a transfer to the backup supply is made through the manual bypass switch. The backup supply is a regulating type transformer from a 480 V Class IE motor control center. A transfer switch provides the automatic switch-over in case of inverter fail ure. The supply from the Class IE 480 V NCC is an associated circuit. Redundant breakers act as an isolation system between the Class IE power supply and non-Class IE load. Rev. 32, 12/82 8. 3-35
SS ES- FS AR 8,3.1,9 Design Criteria fog Class IE Equipment The followinq design criteria are applied to the Class IF. equipment. NOTOR SIZE Motor size (horsepower capability) is equal to or greater than the maximum horsepower required by the driven load under normal running, runout, or discharge valve (or damper) closed condition. MINIM!JN NOTOR ACCELERATING VOLTAGE The electrical system is designed so that the total voltage drop on the Class IE motor circuits is less than 20 percent of the nominal motor voltage. The Class IE mo'tors are specified with acceleratinq capability at 80 percent nominal voltaqe.at their terminals. MOTOR STARTING TORQUE The motor starting torque is capable of startinq and acceleratinq the connected load to normal speed within sufficient time to perform its safety function for all expected operating conditions, including the design minimum t er mi na 1 vol ta qe. MININ!JN NOTOR TORQUE MARGIN, OVER PUMP TORQUE THROUGH ACCELERATING PERIOD The minimum motor torque margin over pump torque through the acceleratinq period is determined by using actual pump torque curve and calculated motor torque curves at 80 and 100 percent terminal voltage. The minimum torque margin (accelerating torque) is such that the pump-motor assembly reaches nominal speed in less than 6.5 seconds. This margin is usually not less than 10 percent of the pump torque. MOTOR INS!JLATION Insulation systems are selected on the basis of the ambient conditions to which the insulation is exposed. For Class I motors located within the containment, the insulation system is selected to withstand the postulated accident environment. TEMPERATURE MONITORING DEVICES PROVIDED IN 'LARGE HORSEPOWER MOTORS Six resistance temperature detectors (RTD) are provided in the motor stator slots, two per phase, for motors larger than 1500 hp. In normal operation, the RTD at the hottest location (selected hy test) monitors the motor temperature and provides an alarm on high temperature. RTDs are provided for motors from 250 to 1500 hp. Each bearinq that is not antifriction type has a chromel-constantan ISA Type F, thermocouple bearing temperature device to alarm on hiqh temperature. TNTERRUPTING CAPACITIES The interrupting capacities of the protective equipment are determined as follows: Rev. 32, 12/82 8. 3-36
SS ES-PS AR a) Switchgear Switchqear interruptinq capacities are greater than the maximum short circuit current available at the point of application. The maqnitude of short circuit currents in medium voltaqe systems is determined in accordance with ANSI C37.010-1972. The off-site power system, a single operatinq diesel generator, and running motor contributions are considered in determining the fault level. High voltage power circuit breaker interrupting capacity ratinqs are selected in accordance with ANSI C37. 06-1971. b) Load Centers, Motor Control Centers, and Distribution Panels Load center, motor control center, and distribution panel interruptinq capacities are greater than the maximum short circuit current available at the point of application. The maqnitude of short circuit currents in low-voltaqe systems is determined in accordance with ANSI C37. 13-1973, and NEMA AB1. .Low-voltage power circuit breaker interruptinq capacity ratings are selected in accordance with ANSI C37.16-1970. Molded case circuit breaker interrupting capacities are determined in accordance with NEMA AB1. ELECTRIC CIRCUIT PROTECTION Electric circuit protection criteria are discussed in Subsection 8. 3. 1.3. 13 . GROUNDING REQUIREMENTS Equipment and system grounding are desiqned in accordance with IEEE 80-1961 and 102-1972. 8,3,1,10 Safety-related Logic and Schematic Diagrams Safety-related loqic and schematic diaqrams are provided as listed in Section 1.7. Q~3~] .11 gnglysis A failure mode effects analysis for the ac power system is presented in Table 8.-3-9. Rev. 32, 12/82 8. 3-37
SS ES-FS AR 8.3.1.11.1 General Design Criteria and Regulatory Guide Compliance The followinq paragraphs analyze compliance with General Design Criteria 17 and 18. All Regulatory Guides are discussed in Subsections 3.13 and 8.1.6.1. GENERAL DESIGN CRITERION 17~- ELECTRIC POWER 'SYSTEMS
~
An on-site electric power system is provided to permit functioning of structures, systems, and components important to safety. With total loss of off-site power, the on-site power system provides -.. sufficient capacity and capability to ensure that: a) Specified acceptable fuel design limits and design conditions of the reactor coolant pressure boundary are not exceeded as a result of anticipated operational occurrences b) The core is cooled and containment integrity and other vital functions are maintained in the event of postulated accidents. Tables 8.3-1 to 8.3-5 list those loads important to safety under desiqn conditions. The on-site electric power system includes four load groups. The load qroups are redundant in that three load groups are capable of ensurinq (a) and {b) above. Sufficient independence is provided bet ween redundant load groups to ensure that postulated sinqle failures affect only a single load group and are limited to the extent of total loss of that load group. The redundant load groups remain intact to provide for the measures specified in (a) and (b) above. Durinq a loss of off-site power, the Class IE system is automatically isolated from the off-site power system. This minimizes the probability of losing electric power from the on-site power supplies as a result of the loss of power from the transmission system. Protection, such as voltage restraint overcurrent and 4. 16 kV bus differential relays, is provided to trip the diesel generator circuit breaker, if abnormal conditions occur. This protection prevents damage to or shutdown of the diesel generator. The turbine qenerator is automatically isolated from the switchyard followinq a turbine or reactor trip. Therefore its loss does not affect the ability of either the transmission network or the on-site power supplies to provide power to the Rev. 32, l2/82 8 3-38
SSES-FS AR Class IE .system. Transmission system stability studies indicate, that the trip of the most critical fully. loaded generating unit does not impair the ability of the system to supply plant station service. Further discussion is provided in Subsection 8.2.2. GENFRAL DESIGN CRITERION 18'NSPECTION AND TESTING OF ELECTRICAL POWER SYSTENS The Class IF. system is designed to permit: a) Periodic inspection and testing, during eguipment
- shutdown, of wi'ring, insulation, connections, and relays to assess the continuity of t5e systems and the condition of components b) During normal plant operation, periodic testing of the operability and functional pezformance of on-site power supplies, circuit breakers and associated control circuits, relays, and buses c) During plant shutdown, testing of the operability of the Class IE system as a whole, including the system's operational sequence, operation of signals of the enqinqered safety features actuation system and the transfer of power between the off-site and the on-site power system.
- 8. 3.1.11.2 Safety Related Equipment, Exposed to
~
Accigent FFnyironment The detailed information on all Class IE equipment that must operate in an accident environment during and/or subsequent to an accident is furnished in Section 3. 11. 8.3.1 11.3 Physical Identification of Safety Related Fguipment Each circuit and raceway is given a unique alphanumeric identification, which distinquishes a circuit or raceway relat'ed to a particular voltaqe, function, channel, or load group. 'ne alpha character of the identification is assigned to a load group on the basis of the following criteria: SEPARATION GROUP CHANNEL A (Red Color Code) - Class IE instrumentation, controls, and power cables, raceways, and equipment related to Channel A loads, dc subsystem A, 120 V ac instrumentation and control channel A, Division I raceways. Rev. 32, 12/82 '.' 8 3 3'g
SSES-FSAR SEPARATION GROUP CHANNEL B (Green Color Code) - Class IE instr umentation, controls, and power cab'.es, raceways, and equipment related to Channel B loads, dc subsystem B, 120 V ac instrumentation and control channel B, Division II raceways. SEPARATION GROUP CHANNEL C (Orange Color Code) Class IE instrumentation, controls, and power cables, raceways, and equipment related to Channel C loads, dc subsystem C, 120 V ac instrumentation and control channel C. SFPARATTON GROUP CHANNEL D, (Blue Color Code) - Class IE instrumentation, controls', and power cables, raceways, and equipment related to Channel D loads, 120 V ac. instrumentation and control channel D. SEPARATION GROUP N {Black Color Code) Mon-Class IE instrumentation, controls, and power cables, raceways, and related equi pme nt. SEPARATION GROUP DIVISION Iand(Red/Brown Color cables. Code) Class IE instrumentation, control, power SEPARATION GROUP DIVISION II (Green/Brown Color Cole) Class IE instrumentation, control, and power. cables. The affi1iated cables are routed with the separation groups they are associated with. The affiliated cables are identified as follows: a) Red/Brown associated with separation group channel A or division I. b) Green/Brown - associated with separation group channel B or division II. c) Orange/Brown associated with separation group channel C d) Blue/Brown associated with separation group channel D Cable and raceway separation groups are summarized in Table 8.3-10 For identification of raceways and Class IE cables refer to Section 3.12. Design drawings provide distinct identification of Class IE equipment. The applicable separation group or load group designation is also identified. Rev. 32, 12/82 8. 3-40
SSES-PS AR Electrical component identification is discussed, in Subsection
- 1. 8.6.
8-.3.1 11.4 Indeoendence 9 of Redundant R Systems 7 Separation Cr iter ia This subsection establishes the, criteria and the bases for preservinq the independence of redundant Class XF, power systems. (For PGCC see Section 3.12). raceway and Cable Routing Rherever possible cable trays are arranged from top to bottom, with trays containinq the highest voltage cables at the top. A raceway desiqnated for one voltaqe category of cables contains only those cables. Voltaqe categories are: a) 480 V ac, 120 V ac, 125 V dc and 250 V dc power b) 120 V ac, 125 V dc, and 250 V dc control and digital siqnal c) Low level signal. The 480 VAC power, 120 VAC control, and digital alarm signal cables oriqinated from the same 480 VAC motor control center (NCC) are routed through a common shuttle tray and riser above the NCC. The shuttle tray covers the length of the NCC, and it is used to connect the NCC to the main raceway system via with vertical tray risers. The cables are routed in accordance the above raceway cateqories once they leave the shuttle tray and vertical tray risers. 15 kV and 5 kV class cables are routed in conduits only. Cables correspondinq with each separation group, as def ined in Subsection 8.3.1.3, are run in separate conduits, cable trays, ducts, and penetrations Refer to Subsection 3.12.3.4. 2 for description of physical separation of raceway and cable routing. Rev. 32, l2/82 8. 3-41
SS ES- PS AR 8.3.1.11.5 Administrative Responsibilities and Controls for Epsugigg Separation Criteria The separation qroup identification described in Subsection
- 8. 3. 1. 11. 3 facilitates and en sures the maintenance of separation in the routinq of cables and the connections. At the time of the cable routing assiqnment durinq design, those persons responsible for cable and raceway schedulinq'nsure that the separation group designation on the scheme to be routed is compatible with a single-line-diaqram load group designation and other schemes nreviously routed. Extensive use of computer facilities assists in ensurinq separation correctness. Bach cable and raceway is identified in the computer proqram, and the identification includes the applicable separation group designation. Auxiliary programs are made available specifically to ensure that cables of a particular separation qroup are routed through the appropriate raceways. The routinq is also confirmed by quality control personnel during installation to be consistent with the design document. Color identification of equipment and cablinq (discussed in Subsection 8.3. 1.11.3 and Section 3.12) assists field personnel in this effort.
- 8. 3-2 DC POWER SYSTEMS
- 8. 3.2~1 Description The dc power systems are divided into Class IB and non-Class IE syste ms.
The Class IE dc system is shown on Piqures 8.3-5-and 8.3-6 . The dc system for each qenerating unit consists of four 125 V dc subsystems, two 250 V dc subsystems ~ and two 124 V dc subsystems. 8,3.2.1,1 1 125 V dc Subsvstems Four Class IE 125 V dc power subsystems provided for each unit are located in separate rooms in the control structure. These four subsystems are identified as channels A, B, C, and D. Each subsystem provides the control power for its associated Class IE ac power load group channel: 4.16 kV switchgear, 480 V load centers, and standby diesel generator as dicussed in Subsection Rev. 32, 12/82 8. 3-42
SSES- FS AR 8.3.1. Also these dc subsystems provide dc power to the engineered safety feature valve actuation, diesel generator auxiliaries, plant alarm and indication circuits, and emergency lightinq system. Fach 125 V dc subsystem consists of one load center, one Class IE and one non-Class IE distribution panel, one 125 V battery bank, and one battery charqer. The non-Class IE distribution panel is connected to the Class IE dc power supply through an isolation system. The isolation system is defined in Subsection 8.1.6.1{n) . The battery charqer of each system is supplied with 480 V Class XE ac power from the motor control center associated with the same load qroup channel. One spare 125 V battery charger is provided for both generating units. The charqer output voltage can be regulated at two different control points. One is a variable resistor located inside the cabinet and is used for rough voltage settings. The other is a screwdriver adjusted potentiometer located on the front of the cabinet, and is used for fine adjustments. By setting both controls at their maximum positions, the charger output voltage would be 145.2 volts. All equipment or devices connected to the 125 V DC supply are rated 105 V to 144 V DC. Maximum output voltaqe resulting from a failure of charqer voltage control circuit is not available at the present time. There are no over voltage protection devices provided for the 125 V dc subsystem. "The 125 V dc power is distributed through circuit breaker type distribution panels. The 125 V dc loads are shown in Table 8.3-6.'~ failure mode and effect analysis for the 125 V dc subsystem d'he is shown in Table 8.3-21.
- 8. 3.2. 1. 1. 2 $ 50 V dc Subsystems Two Class IE 250 V dc subsystems are provided for each unit and identified as Divisions I and IX as shown on Figure 8.3-5. The 250 V dc subsystems are located in separate rooms in the control structure. "The two subsystems supply the dc power required for larqer loads such as dc motor driven pumps and valves, inverters for plant computer and vital 120 V ac power supplies. The 250 V dc loads are. shown in Table 8.3-7.
A 2,000 amp fuse is provided at each pole of the 250 V dc battery output for short circuit protection. These fuses are also used to disconnect the load center from the battery during battery discharge and service tests. Rev. 32, 12/82 8. 3-43
SSES-PS AR The Division I 250 V dc subsystem is provided with one 250 V battery bank, one load center, two equal'capacity chargers, and motor control centers. The Division II 250 V dc subsystem is provided with one 250 U battery bank, one distribution load center, one battery charger, and motor control centers. The 250 V dc battery charqers are supplied by 480 V Class IE ac motor control centers. One spare 250 V battery charger is provided for both generating units. There is no load shedding provided for any of these non-Class 1E loads. All 250 V dc motor control centers (MCC), including non-Class 1E, are seismically qualified. However, the Class 1E MCC's are located in a seismic Category I structure while the non-Class 1E MCC's are located in a non-seismic Category I structure (Turbine Building) . The charger output voltaqe can be regulated at two different control points. One is a variable resistor located inside the cabinet and is used for rough voltage settings. The other is a screwdriver adjusted potentiometer located on the front of the cabinet, and is used for fine adjustments. By setting both controls at their maximum positions, the charger output voltage would be 290.4 volts. All equipment or devices connected to the 250 V dc supply are rated 210 V to 288 V dc. Maximum output voltaqe resultinq from a failure of charqer voltage control circuit is not available at the present time. There are no overvoltaqe protective devices provided for the 250 V dc subsyste m. The 250 V dc power is distributed through dc motor control centers except for the inverters, which are fed directly from the distribution load centers. The non-Class IE 250 V dc loads are supplied by a non-Class IE dc motor control center. The non-Class IE dc motor control center is connected to the Class IF. dc distribution load center through an isolation system as defined in Subsection 8. 1. 6. 1(n) . The non-Class IE 250 V dc loads consist mainly of emergency turbine qenerator auxiliaries. The failure mode and effect analysis for the 250 V dc subsystem is shown in Table 8.3-22. Rev. 32, 12/82 8. 3-44
SSES-PSAR
- 8. 3.2.1. 1. 3 +24 V dc Subsystems Two + 24 V dc subsystems are provided for each unit for radiation monitorinq'ircuits. These two subsystems are located in separate rooms "in the control structure and are identified as Divisions I and II. Each +24 V dc subsystem consists of two 24 V battery banks, two charqers, and a circuit breaker type distr ibution panel.
The 24 V dc charqers are, supplied by 120 V Class IE instrument ac power panels. The +24 V dc loads are shown in Table '8.3-8. One spare 24 V dc battery charqer is provided for both generating units. The 24 V dc subsystem is equipped with under/overvoltage relays for tripping of the chargers and annunciation. All 24 V dc equipment. and devices in Susquehanna SES are rated for 20 to 28 V dc. 8.3.2.1. 1. 4 Class Ig Station Bgtteries and Batte~r Chaggeps f
)
Refer to Subsection 8.3.2 1.1.5 for all Class IE dc system equipment ratings. The battery charqers are full wave, silicon controlled rectifiers. The housinqs are freestanding, NEMA Type I, and are ventilated.'he charqers are suitable for equalizing the batteries. The charqers are in compliance with all applicable NEMA, and IP ANSI standards. The capacity of each battery charqer, or the combined capacity of chargers in the case of Division I 250 V dc subsystem, is 'oth based on the largest combined demand of all the steady-state loads and the charger current required to restore the battery from the design minimum charqed state to the fully charqed state within 12 hr. The battery charqers are constant voltage type with capability of operatinq as battery eliminators, and would funct.ion properly with battery disconnection being a normal condition. The battery eliminator feature is incorporated as a precautional measure to protect aqainst inadvertent disconnection of the battery. There are no planned modes of operation which would require battery disconnection. Variation of the charger output voltage has been determined by 'testing to be less than 1% with or without the battery connected." Maximum output ripple for the 24 V and 125 V dc charqers is 30 millivolts RMS with or without the battery, and 200 millivolts for the 250 V charqers. Rev. 32, 12/82 8.3-45
SS ES-PS AR The failure mode and effect analysis for the + 24 V dc subsystem is shown in Table 8.3-23. Each 125 V, 250 V, and a24 V batter y bank has sufficient capacity without its charqer to independently supply the required loads for 4 hr as shown in Tables 8. 3-6 8. 3-7, and 8.3-8 respectively.
~
In accordance with IEEE 450-1972 initial rated battery capacity is 25 percent qreater than required. This margin allows replacement of the battery to be made when its capacity has decreased to 80 percent of its rated capacity (100 percent of desiqn load) . 8 3.2.1.1.5 Class 1E DC ~ Svstem Fauioment Ratinas a) 125 V dc Subsystems Battery 60 lead-calcium cells 720 amp-hr (8 hrs to 1.75 V per cell 8 77~P) Char qer ac input 480 V, 3g dc output - 100 A continuous rating Load Center Main bus (horizontal) 1600 A continuous rating, 25,000 A short circuit bracing Vertical bus 1200 A continuous rating, 25,000 A short circuit bracing Brea kers 600 A frame size, 2 poles 25,000 A interrupting rating Distribution Panel Main bus 225 A continuous rating, 50 F 000 A short circuit bracing Breakers 100 A frame size, 2 poles (molded case) 10,000 A interrupting rating b) 250 V dc Subsystems Battery 120 lead calcium cells 1800 amp-hr (8 hrs to 1.75 V per cell 8 77oP) Rev. 32, l2/82 8.3-46
SSES-PSAR Charqers ac input 480 V, 3g dc output 300' continuous Load Center Main bus (horizontal) 1600 A continuous rating 25,000 A short circuit bracing Vertical bus 1,200 A continuous rating 25,000 A short circuit bracing Breakers 600 A continuous rating 25,000 A interrupting rating Control Center Main bus (horizontal) 600 A continuous rating 10,000 A short circuit bracing Vertical bus 600 A continuous rating 10;000 A short circuit bracing Breakers 100 A, 225 A and 600 A frame (molded case) rating sizes, 2 poles, 10,000 A interrupting c) '+2 4 Volt Subsystems. Battery 2 groups of 12 lead-calcium cells. 75 amp-hr (8 hrs to 1.75 V per cell 9 77 F) Charqers ac input 120 V, output 25 amp continuous 1p'c 4 Distribution Panels Main bus 100 A continuous 5,000 A short circuit bracing Breakers 100 A frame size, 2 poles, (molded case) 5,000 A interrupting rating 8.3.2.1. 1.6 Insoection o ~ Maintenance e a e~ and Testin a.ng Testing of the dc power systems is performed prior to plant operation in- accordance with the requirements of Chapter 14. Rev. 32, 12/82 8 3-47
SSES- FS AB In-service tests and inspections of the dc power systems includinq batteries, charqers, and auxiliaries are specified in Chapter. 16. 8,3,2 1,1,7 I Se P a at. 3 orD. and Ve 3 tila+.'n For each Class IE dc subsystem, the battery bank, chaxgers, and dc switchqear are located in separate rooms of the Seismic Cateqory I control structure.'he battery rooms are ventilated bv a system that is designed to preclude the possibility of hydrogen accumulation. Section 9.4 contains a description of the battery room ventilation system.
- 8. 3.2.1. 1.8 Non-Class IE dc System Generally, non-Class IE dc loads are connected to a.Class IE dc system throuqh a non-Class IE dc distribution panel. These cases are discussed in Subsections 8.3. 2.1. 1.1 and 8. 3-2-1 1 2-A non-Class IE 125 V dc system is provided for the remote river water intake pump house 4.16 kV switchgear control. This 125 V dc system consists of a distribution panel, two 25A chargers, 60 lead-calcium cells and is rated 50 Ah at 8 hr discharqe rate based on a terminal voltaqe of 1. 75 V per cell when discharged.
- 8. 3.2. 2 Analysis 8.3.2.2. 1 Compliance with General Design Criteria, Regulatory Guides~ and IEEE Standards The f ollowinq paraqraphs analyze compliance of the Class IE dc power systems with General Design Criteria 17 and 18, Regulatory Guides 1.6, 1. 32, 1. 41, 1.81, and 1.93, and .ZEEE 308-1974 and 450-1972.
Rev. 32, 12/82 8 3-48
SS ES- PS AR a) General Design Criterion 17~ Electric power Systems Consideration of Criterion, 17 leads to the inclusion of the followinq factors in the design of the dc power systems:
- 1) Separate Class IE 125 V dc subsystems supply control power for each of the Class IE ac load qroups.
- 2) The ac power for the battery charqers in each of these dc subsystems is supplied from the same ac load qroup for which the dc subsystem supplies the control power.
- 3) Two independent 250 V dc subsystems are provided to ensure the availability of the dc power system for maintaining the reactor integrity durin postulated accidents.
- 4) The Class IE dc subsystems including batteries, charqers, dc switchqear, and distribution equipment are physically separate and independent.
- 5) .,Sufficient capacity, capability, independence, redundancy, and testability are provided in the Class IE dc subsystems, ensuring the performance of safety functions assuminq a single failure.
b) General Desiqn Criterion 18, Inspection and Testing of Flectric power Systems
~
Each of the Class IE subsystem is designed to permit:
- 1) Inspection and testing of wirinq, insulation, and connections durinq equipment shutdown to assess the continuity of the subsystem and the condition of its components.,
2} Periodic testing of the operability and functional perf ormance o f the components of the subsystems durinq normal plant operation. The Class IE dc subsystems are periodically inspected and tested to assess the condition of the battery cells, charger, and other components in accordance with Chapter 16. Preoperational testing's discussed below in assessment of compliance with Regulatory Guide 1. 41. Rev. 32, 12/82 8. 3-49
SS ES- PS AR The design of the dc system complies with Regulatory Guide
- 1. 6.
Seoarate Class IE 125 V dc subsystems supply control power for each of the four Class IE load groups. Loss of any one of the subsystems does not prevent the minimum safety function from beinq performed. The 125 V dc subsystem charqers are supplied from the same ac load group for which the dc subsystem supplies the control power. Each of the four 125 V dc subsystems, including battery bank, charger, and distribution system, is independent of other 125 V dc subsystems. Thus, suf ficient independence and redundancy exist between +he 125 V dc subsystems to ensure performance of minimum safety functions, assuming a single failure. Two independent Class IE 250 V dc subsystems are provided. Each subsystem is independent of the other. Sufficient independence and redundancy exist in these subsyst'ems so that a single failure in the 250 V dc subsystems does not prevent the performance of minimum safety functions. Two independent Class IE 124 V. dc subsystems are provided. Each subsystem is independent of the other. Sufficient independence and redundancy exist in these subsystems so that a sinqle failure in the x24 V dc subsystems does not prevent the performance of minimum safety. functions. d), Rygugg,togy Guj,gg 1. 32 f8g72g The battery charqer capacity for each of the Class IE dc subsystems complies with this Regulatory Guide. Each Class IE battery charqer has sufficient capacity to supnly the larqest combined demand of the various steady-state loads and the charging current required to restore the battery from the desiqn minimum charge state to the fully charged state irrespective of the status of the plant during which these demands 'occur. e) Regulatory Guide 1. 41/3/73} The Class IE dc subsystems have been designed in accordance with Requlatory Guides 1. 6 and 1. 32 and testing capabilities are provided in accordance with the quidance of Regulatory Guide 1.41 and will be preoperationally tested as described in Chapter 14. Rev. 32, 12/82 8 3-50'
SSES-PS AR The requirements of the Requlatory Guide are met. Bach qeneratinq unit is provided with separate and independent on-site dc electric power systems capable of supplying power to the control systems of engineered safety features loads and loads such as valves, and actuators, required for attaininq a safe and orderly cold shutdown of the unit, assuminq a sinqle failure. Compliance is discussed in Subsection 8. 1. 6. 1 fq) . h1 IPEP Standard D 308-1974 The Class IE dc systems provide power to Class IE loads and for control and switchinq of Class IE systems. Physical separation and electrical isolation are provided to prevent the occurrence of common mode failures. The desiqn of the Class IE dc systems includes the following:
- 1) The 125 V dc system is separated into four
,subsystems
- 2) The 250 V dc and + 24 V dc systems are each separated into two subsystems
- 3) The safety action by each group of loads are independent of the safety actions provided by their redundant counterparts
- 4) Each dc subsystem includes power supplies that consist of one battery bank and one or two charqers as required for capacity as shown on Piq ures 8. 3-5 a nd 8. 3-6.
- 5) The batteries are not interconnected.
Each Class IE distribution circuit is capable of transmittinq sufficient energy to start and operate all required loads in that circuit. Distribution circuits to redundant equipment are independent of each other. The distribution system is monitored to the extent that it is shown to be ready to perform its intended function. The dc auxiliary devices required to operate equipment of a specific ac load group are supplied from the same load qro up. Each battery supply is continuously available during normal operations and followinq the loss. of power f rom the ac system to start and operate all required loads. Rev. 32, 12/82 8 3-51
SS ES- FS AR The 125 V dc and 250 V dc subsystems are unqrounded; thus, single qround fault does not cause immediate loss of the faulted system. Ground detection and alarm is provided for each dc subsystem so that ground faults can be located and removed. The +24 V dc subsystem is grounded. Equipment of the Class IE dc system is protected and isolated by fuses or circuit breakers for short circuit or overload protection. The following instrumentation is provided to monitor the status of each of the dc subsystems:
- 1) 125 V dc and 250 V dc subsystems:
System undervoltage System ground Battery availability Battery charger trouble - ac undervoltage; charger failure; charger output breaker trip Load center breaker trip (250 V dc subsystem only) All above alarms are annunciated as a group alarm in the main control room.
- 2) + 24 V dc subsystems:
Positive bus low voltage Negative bus low voltage Positive bus high voltage Negative bus hiqh voltaqe Battery availability Battery charqer trouble ac failure; charger failure; charqer output breaker trip All above alarms are annunciated in the main control room as + 24 V dc system trouble, a group alarm for each battery bank and its associated system. The batteries are maintained in a fully charged condition and have sufficient stored energy to operate all necessary circuit breakers and to provide an adequate amount of energy for all required emergency loads for four hours after los of ac power. Rev. 32, l2/82 8. 3-52
SSES-FSAR Each battery charqer has an input ac and output dc circuit breaker for isolation of the charger. Each battery charger power supply is desiqned to prevent the ac supply from becoming a, load on the battery due to a power feedback as the result of the loss of ac power to the charqers. The battery charqer ac supply breaker can be periodically opened to verif y the load carr ying ability of the battery. The batteries, battery charqers, and other components of the dc subsystems are housed in the control structure, which is a Seismic Cateqory I structure. The periodic testinq and surveillance requirements for the Class IE batteries are detailed in Chapter 16. I EF E S tanR dard 450- 1972 The recommended practices of XEEF. 450 for maintenance, testing, and replacement of batteries are followed for the Class IE batteries and are discussed in Chapter 16. 8.3.2. 2. 2 Physical Identif ication of Safety Related Eguipmggt Physical identification of Class ZE equipment is discussed in Subsection =8. 3 1. 3.
- 8. 3.2.2. 3 Independence of Qedundang Systems The general considerations for the independence of Class IE dc power subsystems are described in Subsection 8.1.6.1{n)'. The ph'ysical separation criterion is discussed in Section 3.12.
8 3,3 PIRE PROTECTION POR CABLE SYSTEMS
- 8. 3. g. 1 Cable Degating and- Cable /rag Pill The power and control cable insulation is designed for a conductor temperature of 90~C. Allowable current carrying capacity of the cable is based on not=exceeding the insulation desiqn temperature while the surrounding air is at an ambient temperature of 65.50C for the primary containment and 400C for all other areas. The desiqn operatinq conditions of all Class IE cables are discussed in Section 3.11.
Rev. 32, 12/82 8. 3-53
SS ES- FS AR The power cable ampacities are established in accordance vith TPCEA Publications P-54-440 and P-46-426 and are shovn in Tables 8 3-11 through 8 3-15 For control circuits, minimum 414 AWS conductors are generally used. Tnstr umentation cable is also designed for a conductor temperature of 90~C. Operating currents of these cables are low (usually mA or mV) and vill not cause the design temperature to be exceeded at maximum design ambient temperature. Tn aeneral, cable tray fill is limited to 30 percent cross-sectional area. In cases where the limitation is exceeded, fill by a reviev will be performed for each case for the adequacy of the design. In qenerali conduit fill is in compliance with Tables I and II, Chapter 9, National Electrical Code, 1975. In cases where these values are exceeded ~ a review is performed for each case +o in sur e t ho.. ad equacy o f the design. Pover cables, control cables, and instrumentation cables are defined as follows: Power Cables Power cables are those cables that provide electrical energy for motive power or heatinq to all 13.8 kV ac, 4.16 kV ac, 480 V ac, 120 V ac, 250 V dc, and 125 V dc loads. Control Cables Control c.ables, for the purpose of derating, are generally 120 V ac, 250 V dc, 125 V dc, and 24 V dc circuits between components responsible for the automatic or manual initiation of auxiliary electrical. functions and the electrical indication of the state of auxiliary components. Instr umentat ion Cables Instrumentation cables are those cables conducting low-level instrumentation and control siqnals. These signals can be analog or digital. Typically, these cables carry signals from t hermocouples, resistance temperature detectors, transducers, neutron monitors, etc. Rev. 32, 12/82 8. 3-54
SSES-FS AR 8.3.3.2 Pire Detection for Cable Systems Fire detection systems are discussed in Subsection 9.5.1. 8.3.3.8 Pire Barriers and Separation Between Redundant Trays Electrical equipment and cablinq has been arranged to minimize the propaqation of fire from one separation group to another. Physical separation of cablinq systems is discussed in Subsection
- 3. 12. 2.
Mher.. th~ minimum physical separation cannot be met as specified i.n Subsection 3.12.2 ~ and a fire barrier is selected as the al ternative, a 1/4 in. Haysite ETR-PR-C is installed. The bolts and hardware used to secure the Haysite panel to the tray support are coated after installation with 1/8 in. of f ireproofing material Dynatherm's Plamemastic 71K compound.
- 8. 3. 3. 4 Pire Stoos
'I Fire stops and seals are provided for cable penetrations in the floor for vertical runs of raceways, at each access opening in are
'he ceilinqs and at fire-rated wall penetrations. fire stops furnished to provide a method of sealinq off air spaces around cable penetrations. The properties of materials and qualification tests are discussed in Subsection 9.5.1.
Rev. 32, 12/82 8. 3-55
TABLE 8,3-9 AC POWER FAILURE NODE EFFECTS ANALYSIS ID Effect on Safety No. Component Name Function Failure Node Effect on Subsystem Function 1 Offsite power source Supplies preferred Loss of power Loss of preferred No effect offsite through engineered power to Units 162 pover to Unit" 162 power through engineered safeguards transformer load group channels load groups AGC safeguards transformer 101 AGC 201 supplies backup Supplies alternate Less of power Loss of backup No effect - diesel pover to Units 1C2 power to Units 162 generators provide load group channels load groups BGD standby power BCD 2 Offsite power source Supplies preferred Loss of power Loss of preferred No effect - offsite through engineered power to Units 162 power to Units 162 pover through engineered safeguards transformer load group channels load groups BCD safeguards transfo.mer 201 BGD 101 supplies backup Supplies alternate Loss of pover Loss of backup No effect - diesel power to Units 162 power to Units 1C2 generators provide load group channels load group AGC standby pover AGC Load Group <<A<< 3 u ~ 16 kV Bus 1A201 Provide power to Fault Loss of pove" to No effect redundant all loads belonging to all load group>>A<< equipment from load load group <<A<< loads groups B,C,CD provide the required safety function 3A Circuit breaker Provides preferred Fails open Loss of preferred No effect - automatic 52-20101 pover to load group pover to load group transfer to alrernate
<<A<< <<A<< offsito power by clo-ing breake" 52-20109 (See ID No. 11) m Circuit breaker Provides powe" to Fails open Loss of power to No effect - three 52-20102 RHR pump 1P202A RHR pump 1P202A redundant RHR pump" from load groups B,C,GD provide the required safety function 5 Circuit breaker Provides pover to Fails open Loss of pove r to No effect - non-Class ZE 52-20103 reactor chiller reactor chiller equipment 1K206A 1K206A 6 Circuit breaker Provides standby Fails to close Failed to provide No effect - safety 52-2010m power to bus 1A201 standby power to functions are provided load group <<A<< by redundant equipment supplied by load groups B,C,GD
TABLE 8.3-9 (Continued) ID Effect on Safety No Component Name Punction Failure Node Effect on Subsystem Punction 7 Circuit breaker Provides pover to Pails open Loss of pover to No effect - three 52-20105 core spray pump core spray pump redundant core spray 1P206A 1P206A pumps from load groups b,C,GD provide tho required safety function 8 Circuit breaker Provides power to Fails open Loss of pover to No effect - safety 52-20106 480 V load center all load group <<A<< functions are provided 18210 (2B210) 480 V loads by redundant equipment supplied by load groups BrCeSD 9 Circuit breaker Provides pover to Fails open Loss of power to No effect non-Class IE 52-20107 CRD vater pump CRD vater pump equipment 1P 132A (2P132A) 1P132A (2P132A) 10 Cxrcuit breaker Provides pover to Fails open Loss of power to No effect - three 52-20108 the emergency service the emergency service redundant emergency water pump OP504A vater pump OP504A service vater pumps from load groups B,C,CD provide the required safety function 11 Circuit breaker Provides alternate Pails to close Loss of alternate No effect diesel 52-20109 preferred offsite preferred offsite generator provides the pover to bus 1A201 pover to load group standby power (see II A << ID No 6) 12 Circuit breaker Provides pover to Fails open Loss of power to No effect non-Class IE 52-20110 turbine building turbine building equipment chiller 1K102A chillec 1K102A Load Group <<C<< 13 4.16 kV bus 1A203 Provides pover to Pault Loss of power to No effect redundant all loads belonqinq to all load group <<C<< equipment from load load qroup <<C<< loads groups A,B,ED provide the required safety function 13A CiLcuit breaker Provides preferred Fails open Loss of preferred No effect automatic 52-20301 pover to load group pover to load group transfer to alternate
<<C<< <<C<< offsite pover by closing breaker 52-20309 (See ID $ 21)
ID Effect on Safety No Component Name Function Failure Hole Effect on Subsystem Punction 14 Circuit breaker Provides power to Pails open Loss of power to No effect - three 52-20302 RHR punp 1P202C RHR pump 1P202C redundant RHR pumps (2P 202C) (2P202C) from load groups A,B,CD provide the required safety function 15 Circuit breaker Provides emergency Pails open Loss of pover to No effect three 52-20303 service water pump emergency service redundant emergency OP504C vater pump OP504C service water pumps f ron load groups A ~ B,CD provide the required safety function 16 Ciccuit breaker Provides standby Pails to close Pailure to provide No effect - safety 52-20304 pover to bus 1A203 standby pover to functions are provided (2A203) load group by redundant equipment supplied by load groups
oss A~B ~ CD 17 Circuit breaker Provides pover to pails open of power to No effect - three 52-20305 core spray pump core spray pump redundant core spray 1P206C 1P206C punps fron load groups h, B,CD provide the required safety function 18 Circuit breaker Provides power to pails open Loss of pover to No effect safety 52-20306 480 V load center all load group "C" functions are provided 18230 480 V loads by redundant equipment supplied by load groups B,C,CD 19 Circuit breaker Spare 52-20307 20 Circuit breaker Provides pover to Pails open Loss of power to No effect redundant 52-20308 the RHR service RHR service water RHR service vater vater pump 1P506A pump 1P506A pump 1P5068 provides the required safety function 21 Circuit breaker Provides alternate Fail" t o close Loss of alternate No effect diesel 52-20309 preferred offsite preferred offsite generator provides power to bus lA203 power to load group the standby pover v CII (see ID No. 16) 22 Circuit breaker Provides pover to Fails open Loss of power to No effect - the 52-20310 control structure the control structure redundant contcol chiller OK112A chil ler OK 11 2A structure chiller OK1128 provides the requi ed safety function
TABLE 8.3-9 fContinued1 ID Effect on Safety No. Component Name Function Failure Node Effect on Subsystem Function Load Group >>8>> 23 4.16 kV bus 1A202 Provides powe" to Pault Loss of power to No effect - redundant all loads belonging all load group>> 8>> equipmont from load to load qroup >>8>> loads groups A,C,CD provides the required safety function 23A Circuit breaker Provides preferred Fails open Loss of preferred No effect - automatic 52-20201 mover to load group power to load group transfe" to alternate
>>8>> >>8>> offsite power by closing breake-52-20209 (ID No. 31) 24 Circuit breaker Provides power to Fails open Loss of pover to No effect - three 52-20202 RHR pump 1P2028 RHR pump 1P2028 redundant RHR pumps from load groups A,C,CD provide the required safety function 25 Circuit breaker Provides pover to Fails open Loss of pover to No effect non-Class IE 52-20203- reactor building reactor building equipment chiller 1K2068 chiller 1K2068 26 Circuit breaker Provides standby Fails to close Failure to provide No effect safety 52-20204 power to bus 1A202 standby power to functions are provided load group >>8>> by redundant equipment supplied by load groups A,C,CD 27 Circuit breaker Provides pover to Pails open Loss of pover to No effect three 52-20205 core spray pump core spray pump redundant core spray 1P2 068 1P2068 pumps from load groups A,C,CD provide the required safety function 28 Circuit breaker Provides power to pails open Loss of power to No effect safety 52-20206 480 V load center all load group "8>> functions are provided 18220 480 V loads by redundant equipment supplied by load groups A,C,CD 29 Circuit breaker Spare 52-20207
ID Ef feet on Safety No. Component Name Function Failure Node Effect on Subsystem Punction 30 Circuit breaker Pcovides power to Pails open Loss of power to No effect - three 52-20208 emerqency service emergency service redundant service water water pump OP5048 water pump OP5048 pumps from load groups A,C,SD provide the required safety function 31 Circuit breaker Provides alternate Fails to clo e Loss of alternate No effect diesel 52-20209 prefecred offsite preferred of fsite generator provides power to bus lA202 power to load group the standby power II Blt (See ID No. 26) 32 Circuit breaker Provides power to Pails open Loss of power to No effect - non-Class IE 52-20210 condensate vacuum condensate vacuum equipment pump 1P105 pump 1P 105 33 Circuit breaker Provides powe" to Pails open Loss of powec to No effect non-Class IE 52-20211 turbine building turbine building equipment chiller 1K1028 chiller 1K10 28 Load Group "D" 34 4 16 kV bus 1A204 Provides power to Pault Loss of power to No effect - redundant all loads belong all load group "D" equipment from load to load group "D" loads groups A,B,SC provide the requiced safety function 35 Circuit bceaker Provides preferred Fails open Loss of preferred Ho effect automatic 52-20401 power to load group power to load group transfer to alternate It 8 tl nDn offsite powec by closing breaker 52-20409 (See ID No. 43) 36 Circuit breaker Provides power to Pails open Loss of power to Ho effect three 52-20402 RHR pump 1P202D RHR pump 1P2020 redundant RHR pumps from load groups A,B,EC provide the required safety function 37 Circuit breaker Provides power to Pails open Loss of power to No effect - three 52-20403 emergency service emergency service redundant emergency water pump OP504D water pumn OP504D service water pumps from load groups A, B,SC provide the required safety function
TABLE 8 3-9 (Continued) ZD Effect on Safety No ~ Conponent Hase Function Failure Node Effect on Subsysten Function 38 Circuit breaker Provides standby Fail to close Failure to provide No ef f ect - saf ety 52-20404 power to bus 1A204 standby power to functions are provided load group "C>> by redundant eguipnent supplied by load groups A,B,CC 39 Circuit breaker Provides power to Fails open Loss of power to No effect - three 52-20405 core spray punp core spray puap redundant core spray 1P206D 1P206D punps fron load group's A,B,GC provide the required safety function 40 Circuit breaker Provides power to Fails open Loss of power to No effect - safety 52-20406 480 V load center all load group "D" functions are provided 18240 480 V loads by redundant eguipnent supplied by load groups A,B,GC 41 Circuit breaker Provides power to Fails open Loss of power to No effect - non-Class IE 52-20407 CRD punp '1P1328 CRD punp 1P132B eguipnent 42 Circuit breaker Provides power to Fails open Loss of power to No effect - redundant 52-20408 RHR service water RHR service water RHR service water punp punp 1P506B punp 1P5068 1P506A provides the reguired safety function 43 Circuit breaker Provides alternate Fail to close Loss of alternate No effect - diesel 52>>20409 preferred power preferred offsite generator provides the supplies to bus 1A204 power to load group standby power (See ID
>>D>> No 38) 44 Circuit breaker Provides power to Fails open Loss of power to No effect - redundant 52-20410 control structure control structure control structure chiller OK1128 chiller OK1128 chiller OK112A provides the reguired safety function 45 Circuit breaker Spare 52-20411
SS ES-PS AR TABLE 8 3-11 CABLE AHPACITIES 15 kV CABLES {ALUMINUM) Amps in Duct Amps in Conduit and Embedded in Air Conduit Conductor 400C 40OC 65.5oC Size Ambient Ambient Ambient 3-1/c ¹ 1/c 1/c 1/c
<<4/0 ANG 195 232 162 350 KCMIL 258 313 219 500 KCMXL 313 387 271 750 KCMIL 386 486 340 1000 KCMIL 444 574 402 6-1/c 2/c 2/c 2/c <<4/0 A MG 353 427 299 350 KCMIL 463 576 403 500 KCMIL 559 712 498 750 KCMIL 686 894 626 1000 KCMIL 786 1056 739 9-1/c 3/c 3/c 3/c <<4/0 A L'G 472 592 414 350 KCMIL 616 798 559 500 KCMIL 738 987 691 750 KCMIL 900 1239 867 1000 KCMIL 1024 1463 1024 3-1/c indicates single conductor per phase, and 6-1/c indicates two conductors per phase, etc.
Rev. 29, 3/82
SSBS-FS AH TABLE 8 3-12 CABLE AMPACXTXBS 5 kV CABLES (ALUMINUM) Amps in Duct Amps in Conduit and Embedded in Air Conduit Conductor ,40~C 40OC 65 50C Size Ambient Ambient Ambient 3-1/c 'l/c 1/c
¹4/0 A MG 194 226 158 350 KCMIL 257 307 215 500 KCMIL 3'l2 381 267 750 KCMXL 386 479 335 1000 KCMXL 445 560 392 6-1/c 2/c 2/c 2 jc ¹4/0 A WG 333 416 291 350 KCMIL 438 565 396 500 KCMIL 527 701 491 750 KCMXL 647 881 617 1000 KCMXL 741 1030 721 9-1/c 3/c 3/c 3/c ¹4/0 A QG 471 576 403 350 KCMIL 618 783 548 500 KCMIL 743 972 680 750 KCMXL 907'037 1221 855 ~ 1000 KCMIL 1428 1000 Rev. 29, 3/82
SS ES-FS AR coolinq system alone. RHR system to the It is spent fuel therefore necessary to connect the pool. Mhen this is done the pool temperature can be maintained well below 125oF. All pipinq and equipment shared with or connecting to the RHR intertie loop are Seismic Category I, Quality Group C, and can be isolated from any pipinq associated with the non-Seismic Category r Quality Group C fuel pool cooling system. Provisions to minimize and monitor leakage from the fuel pool are described in Subsection 9.1.2. 3. Makeup for evaporative and small leakage losses from the fuel pool is normally supplied from the demineralized water system to the skimmer surge tanks of each unit. The intermittent flow rate is approximately 50 qpm to each surge tank. A Seismic Category I makeup of 60 gpm is provided by a 2 in. line from each emerqency service water (ESQ) loop to the RHR fuel pool diffusers, thus providing redundant flow =paths from a reliable source of water. The design makeup rate from each ESQ loop is based on replenishing the boil-off from the MNHL in each fuel pool for 30 days followinq the loss of the FPCCS capacity. The time required to reach, boiling after loss of. loading is approximately 25 hours. The water level in the spent fuel storage pool is maintained at a height which is sufficient to provide shieldinq for required buildinq occupancy. Radioactive particulates removed from the fuel pool are collected in filter demineralizer units in shielded cells. For these reasons, the exposure of station personnel to radiation from the spent fuel pool coolinq and cleanup system is normally minimal. Further details of radiological considerations are described in Chapter 12. An evaluation of the radiological effect of a boiling fuel pool is presented in Appendix 9A.
- 9. 1.3.4 Tnspectgon and Tegtipg geguipements No special tests are required because at least one pump, heat exchange , and filter demineralizer are continuously in operation while fuel is stored in the pool. The remaining components are periodically operated to handle increased heat loads during .
refuelinq. The pool liner leak detection drain valves are periodically opened and the leak rate estimated by the volumetric method. Gas or dye pressure testing from behind the liner plate may be performed to locate a liner plate leak. Rev. 29, 3/82 9. 1-27
SSES-PSAR Routine visual inspection of the system components, instrumentation, and trouble alarms is provided to verify system operability. Components and piping of the PPCCS designed per ASIDE Boiler and Pressure Vessel Code, Section III, Class 3 are in-service inspected as described in Section 6.6. The system vill be preoperationally tested in accordance with the requirements of Chapter 14. 9~ 1 4 PEEL HA NDLING SYSTEN-
- 9. 1. 4. 1 Des ign Bases The fuel-handling system is designed to provide a safe and effective means for transporting and handling fuel from the time it reaches the plant until it leaves the plant after post-irradiation cooling. Safe handling of fuel includes design considerations for maintaining occupational radiation exposures as low as practicable during transportation and handling.
Desiqn criteria for ma)or fuel handling system equipment is provided in Tables 9.1-2 through 9.1-4 which list the safety class, quality group, and seismic category. %he e applicable, the appropriate ASIDE, ANSI, Industrial and Electrical Codes are identified. Additional desiqn criteria 'is shovn below and expanded further in Subsection 9.1.4.2. The transfer of new fuel assemblies between the uncratinq area and the nev fuel inspection stand and/or the new fuel storage vault is accomplished using the reactor building crane or the refuelinq floor jib cranes equipped with a general purpose qrapp le. The reactor buildinq crane auxiliary hoist or a refuelinq floor gib crane is used vith a qeneral purpose grapple to transfer nev fuel from the fuel inspection stand or the new fuel vault to the fuel storaqe pool. Prom this point on, the fuel vill be handled by the telescopinq qrapple on the refuelinq platform. The refuelinq platform includinq refueling platform rails, clamps, and clips are Safety Class 2 and Seismic Class 1 from a structural standpoint in accordance with 10CZR50, Appendix A and B. Allovable stress due to safe shutdown earthquake loading is 120 percent of yield or 70 percent of ultimate, whichever is least. A dynamic analysis is performed on the structures using the response spectrum method vith load contributions resulting
,from each of three earthquakes being combined by the RNS procedure Rev. 29, 3/82 9 1-28
SS ES-FS AR 9,1.4. 2. 10 Fuel Transfer Description
- 9. 1.4.2. 10.1 Arrival of Fuel on Site New fuel arrives in the railway bay of the reactor building Unit 1 either by railcar or truck. The access doors are closed to maintain the secondary containment as required by Technical Snecifica+ions. Unloading of the metal shipping contain..rs is done bv the auxiliary hoist of the reactor building crane.
- 9. 1. 4. 2. 10. 2 Refueling Procedure The plant refuelinq and servicinq sequence diagram is shown in Figure 9.1-15. Fuel handling procedures are described below and shown visually in Fiqure 9. 1-16 throuqh Fiqure 9. 1-19.
The Refuelincr Floor Layout is shown in Figure 9.1-4 and component drawings of the principal fuel handlinq eguipment are shown in Figures 9.1-7 throuqh 9. 1-14 and Fiqure 9. 1-20. l The fuel handlinq process takes place primarily on the refueling floor above the reactor. The principal locations and equipmont are shown on Figure 9.1-16. The reactor, fuel pool, and shippinq cask oool are connected to each other by slots, as shown at (A) and (B) . Slot (A) is open during reactor refueling, and slot {B) is open d>>rinq spent fuel shipping. At other times the slots are closed bv means of blocks and qates. which make water-tight barriers. The handlinq of nev fuel on the refueling floor is illustrated in Fiqure 9.1-17. The transfer of the bundles between the crate {C) and the new fuel inspection stand (D) and/or the new fuel storage vault (E) i" accomplished usinq 5-ton auxiliary hoist of the reactor buildi ng crane or a half-ton floor mounted refueling jib crane equipped with a general-purpose grapple. The fuel bundle cannot be handled horizontally without support, so the crate is placed in an almost vertical position before being opened. The top and front of the crate are opened, and the bundles removed in a vertical position. The auxiliary hoist of the reactor building crane or the jib crane are also used with a qeneral-purpose grapple to transfer new fuel from the new fuel vault or inspection stand to a storage rack position in the fuel pool. From this point on, the fuel is handled by the welescopinq grapple on the refueling platform. Rev. 29, 3/82 9. 1-41
SS ES-PS AR The storage racks in both the vault and the fuel pool hold the fuel bundles or assemblies vertical, in, an array which is subcritical under all possible conditions. The new fuel inspection stand holds one or two bundles in vertical position. The Inspector(s) ride up and down on a platf orm. and the bundles are manually rotated on their axes. Thus the inspectors can see all visible surfaces on the bundles. The general-purpose grapples and the fuel q apple of the refuelinq platform have redundant hooks, and an indicator which confirms positive qra pple enqa qemen t. The refuelinq platform uses a qrapple on a telescoping mast for liftinq and transportinq fuel bundles or assemblies. The
",.elescopinq mast can extend to the proper work level; and, in its normal up position state, maintains adequate water shieldinq over the fuel being handled.
The reactor refuelinq procedure is shown schematically in Figure 9.1-18. The refuelinq platform (G) moves over the fuel pool, lowers the qrapple on the telescoping mast (H), and engages the bail on a new fuel assembly which is in the fuel storage rack. The assembly is lifted clear- of the rack, and moved through slot {A) and over the appropriate'mpty fuel location in the core (J) . The mast then lowers the assembly into the location, and the grapple releases the bail. The operator then moves the platform until the grapple is over a soent fuel assembly which is to be discharged f rom the core. The assembly is qrappled, lifted, and moved through slot (A) to the fuel pool. i!ere (K) it is placed in one of the fuel prep machines An operator, using a lonq-handled wrench, removes the screws and springs from the top of the channel. The channel is then held, while a carriage lowers the fuel bundle out of the channel. The channel is then moved aside, and the refuelinq platform grapple carries the bundle and places it in a storage rack. The channel handlinq boom hoist, (L), moves the channel to storage, if appropriate. Ia actual practice, channelinq and dechannelinq may be performed in many seauences, dependinq on whether a new channel is to be used, or a used channel is to be installed on a new bundle and returned to the core. A channel rack is conveniently located near to the fuel prep machines, for temporary storage of channels which are to be reused. To preclude the possibility of raising radioactive material out of the water, redundant electrical limit switches are incorporated in the auxiliary hoists of the refueling platform Re v. 31, 7/82 9. 1-42
SSES-PS AR and the gib crane hoist, and interlocked to prevent hoisting above the preset limit. In addition, the cables on the hoists incorporate adjustable stops that will jam the hoist cable aqainst the hoist structure, which prevents hoistinq if the limit svitch interlock system should fail. When spent fuel is to be shipped, it is placed in a cask, as shovn in Figure 9.1-19. The refuelinq platform grapples a fuel bundle from the storaqe rack in the 'fuel pools, lifts it, carries it through slot (B) into the shipping cask pool, and lovers it into the cask, (N) .,)(hen the cask is loaded, the reactor building crane sets the cask cover (N) on the cask. After d aininq the shippinq cask pool, the cask is decontaminated and lovered through the open hatchways, (P) onto the truck or
~
railcar in the railway bay at grade level. Provision of a separate cask loadinq pool, capable of being isolated from the fuel storage pool, eliminates the potential accident of dropping the cask and rupturing the fuel storage pool Additional detailed information is provided belov.
- 9. 1.4.2. 10. 2. 1 Nev Puel Preparations 9- 1.4.2. 10 2 1. 1 Receipt and Inspection of Nev Puyl The incominq nev fuel vill be delivered to a receiving station .
The crates should be unloaded from the transport vehicle and examined, for damage during shipment. The crate dimensions are approximately 32" x 32" x 18 feet long. Each crate contains two fuel bundles supported by an inner metal container. TheShipping receiving veiqht of each unit is approximately 3000 pounds. station includes a separate area vhere the crate covers can be removed. The crates are then moved to the reactor building where the metal inner containers are removed and lifted to the refuelinq cloor. Both inner and outer shipping containers are reusable. Handlinq during uncrating is to be- accomplished by use of the reactor building crane extending down from the refueling floor through the equipment hatch. Rev. 29, 3/82 9 1-43
SS ES- PS AR 9.1.4.2.10.2.1.2 .Channeling Hew Fuel The initial core for both units will be channeled as each new fuel bundle is inspected in the fuel inspection stand. This process vill be repeated whenever new fuel channels a re to be placed on new fuel bundles. Usuall j channeling new fuel is done concurrently with de-channelinq spent fuel. Two fuel preparation machines are located in the fuel pool; one used for de-channeling spent fuel and the other to channel new fuel. The procedure is as follows: Using a jib crane and the general purpose grapple, a new fuel bundle is transported to one the fuel prep machine if it had been residinq in the fuel storage vault. Otherwise it is moved from a spent fuel pool storage rack to the fuel preparation machine usinq the refuelinq bridqe. A spent fuel'undle is moved from a spent fuel pool storage rack to the other fuel prep machine. The channel is unbolted from the spent fuel bundle using the channel bolt wrench. The channel handling tool is fastened to the top of the channel and the fuel prep machine carriage is lowered removing the Tuel from the channel. The channel is then positioned over a new fuel bundle located in the first fuel prep machine 02 and the process reversed. racks The channeled new fuel is then stored in the pool storage ready for insertion into the reactor.
- 9. 1. 4. 2. 10. 2. 1. 3 Egu hymen t Prepagat ion Prior to the plant shutdown for refueling, all eguipment must be Placed in readiness. All tools, qrapples, slings, strongbacks, stud tensioners, etc. should be given a thorouqh check and any defective (or well worn) parts should he replaced. Air hoses on grapples should be routinely leak tested. Crane cables should be routinely inspected. 1lll necessary maintenance a nd' nterlock checks should be performed to assure no extended outage due to equipment fa ilure.
The in-core flux monitors, in their shipping container, should be on the refueling floor. The channeled new fuel and the replacement control rods should be ready in the storage pool.
- 9. 1.4. 2. 10. 2. 2 Eeactor Shutdown The reactor is shut down according to a prescribed procedure.
Durinq cool down the reactor pressure vessel is vented and filled to above flange level to equalize cooling. The drywell and suppression chamber are de-inerted. The eight reactor well shield pluqs can be removed. This is accomplished with the reactor building crane and the supplied slings. Rev. 29, 3/82 9 1-44
SS ES-PS AR This operation can be immediately followed by removal of the three canal pluqs and the three slot plugs. Thus, a total of 14 separate pluqs must be removed and placed on the refueling floor.
"Befuelinq Equipment Storage and Crane Clearance" arrangement drawing is issued to locate placement 'of these plugs on the refueling floor. The outer fuel pool gate is also removed at this time. The gate sling is attached to the gate lifting lugs and the reactor building crane lifts the gate and places it on the fuel pool gate storage lugs.
- 9. 1. 4. 2. 10. 2. 2. 1 Drgwelg Head Removal Immediately after removal 'of the reactor well shi'eld plugs, the work to unbolt the drywell head can begin. The drywell head is attached by removable bolts protruding from the lower drywell flange. The nuts on top are merely loosened and the bolt heads, swinq outward. The bolts are then pulled upwards and supported with the nuts on a slotted lip of the head.
The sister hook of the reactor building crane is attached to the hook box on top of the unbolted drywell head and lifted to its appointed storage space on the refueling floor. The drywell seal surface protector is installed before any other activity proceeds in the reactor well area.
- 9. 1.4.2. 10.2.2,2 ~ Reactor Well Servicing.
When the drywell head has been removed, an array of piping is exposed that must, be serviced. Various vent piping penetrations through the reactor well must be removed and the penetrations made water tight. Vessel head piping and head insula tion must be removed and transported to storage on the refueling floor. Water level in the vessel is now brought to flange level in preparation for head removal.
- 9. 1.4.'2. 10. 2. 3 Reactor Vessel Opening
- 9. 1.4.2.-10.2.3.1 Vessel Head- Removal The stud tensioner is transported by the rea'ctor building crane and positioned on the reactor vessel head. Each stud is tensioned and its nut loosened in a series of 2-3 passes. When.
the nuts are loose, they are backed off using a nut runner until only a few threads enqage. The vessel nut handling tool is Rev. 29, 3/82 9 ~ 1- 45
SS ES-PS AB engaged in the upper part of the nut and the nut is rotated free from the stud. The nuts and washers are placed in the racks provided for them and transported to the refueling floor for storage. With the nuts and washers removed, the vessel stud, protectors and vessel head guide caps are installed. The head stronqback, transported by the reactor building crane, is attached to the vessel head and the head transported to the head holding pedestals on the refueling floor. The head holding pedestals keep the vessel head elevated to facilitate inspection and "0" ring replacement. The six studs in line with the fuel transf er canal are removed from the vessel flange and placed in the rack provided. The loaded rack is transported to the refuelinq floor for storage.
- 9. 1.4.2. 10.2.3.2 =Dryer Removal The dryer-separator sling is lowered by the reactor building crane and-attached to the dryer lifting luqs. The dryer is lifted from the reactor vessel and transported to its storage location in. the dryer-separator storage pool adjacent to the reactor well. The dryer is transported in air. However, dryer should become highly contaminated, the reactor well if and the storage pool can be flooded and a wet transfer effected.
- 9. 1. 4. 2. 10. 2. 3. 3 Separator Remova l Xn preparation for separator removal, the service platform and service platform support are installed on the vessel flange.
Prom the service'platform work area, the four main steam lines are plugged from inside the vessel using the furnished plugs for this duty. 'ervicing of the safety and relief valves can thus be accomplished without adding to the critical refueling path time. Working from the service platform, the separator is unbolted using the shroud head bolt wrenches furnished. When the unbolting is accomplished, the service platform is removed and stored on the refueling floor. The service platform support remains on the vessel flange during the remainder of the refuelinq outaqe and acts as .the flange seal surface protector. The dryer-separator sling is lowered into the vessel and attached to the separator liftinq lugs. The water in the reactor well and in the dryer-separator storage is raised to fuel pool water level and the separator is transferred underwater to its allotted storage -place in the ad jacent pool. Rev. 29, 3/82 9 1-46
SSES-FS AR
- 9. 1.4. 2..10~2 ~ 3. 4 fuel Bundle Sampling Durinq reactor operation, the core off-qas radiation level is monitored. Xf a rise in of f-gas activity has been noted, the reactor core will be sampled during shutdown to locate any leaking fuel assemblies. The fuel sampler or sipper rests on the channels of a four bundle array in the core. An air bubble is pumped into the top of the 4 fuel bundles and allowed to stay about 10 minutes. This stops water circulation through the bundles and allows'ission products to concentrate if a bundle is defective. After 10 minutes, a water sample is taken for fission it product analysis.
the fuel pool and ifIf a defective bundle is found, reguired, may be stored in a special defective fuel storage container to prevent the spread of is taken to contamination in the pool. 9 1.4 ~ 2. 10. 2.4 Refueling and Reactor Servicing The remaining gate isolating the fuel pool from the reactor well is now removed thereby interconnecting the fuel pool, the reactor well, and the dryer-separator storage pool. The actual refueling of the reactor can now begin. 9 1.4.2. 10. 2.4.1 Refuel ing Durinq a normal equilibrium outage, approximately 25% of the fuel is removed from the reactor vessel, 25% of the fuel is shuffled in the core (generally from peripherial to center locations) and 25% new fuel is installed. The actual fuel handling is done with the fuel qrapple which is an integral part of the refueling platform. The platform runs on rails over the fuel pool and the reactor well. In addition to the fuel grapple, the refueling platform is equipped with two auxiliary hoists which can be used with various grapples to service other reactor internals. To move fuel, the fuel grapple is aligned over the fuel assembly, lowered and attached to the fuel bundle bail. The fuel bundle is raised out of the core, moved through the refueling slot to the fuel pool, positioned over the storage rack and lowered to storaqe. Fuel is shuffled and new fuel is moved from the storage pool to the reactor vessel in the same manner. Rev. 29, 3/82 9. 1-47
SS ES- FS AR
- 9. 1. 4. 2. 10 2. 5 Vessel Closure.
The followinq steps, condition. when performed, will return the reactor to The procedures are the reverse of those operatinq described in the proceeding sections: Many steps are performed in parallel and not as listed. a) Install inner fuel pool gate. b) Core verification. The core position of each fuel assembly must be verified to assure the desired core configuration has been attained. c) Control rod drive tests. The control rod drive timing, friction and scram tests are performed. d) Replace separator. e) Drain dryer-separator storaqe pool and reactor well.
.f) Decontaminate reactor well.
g) Install service platform, bolt separator, and remove the four steam line pluqs. Return the service platform and platform support to storage on refueling floor. h) Remove drywell seal surface covering. i) Open drywell vents, install vent piping. j) Replace fuel pool outer gate. k) Replace steam dryer.
- 1) Decontaminate dryer-separator storage pool.
m) Replace vessel studs. n) Replace slot plugs. o) Install reactor vessel head. p) Install vessel head piping and insulation. q) Replace dryer-separator canal plugs. r) Hydro-test vessel, if necessary. s) Install drywell head. t) Inert reactor drywell and suppression chamber. Rev. 29, 3/82 9. 1-48
SS ES- FS AR. u) Install reactor well shield plugs. v) Startup tests. The reactor is returned to full power operation. Power is increased, gradually in,a series of steps until the reactor is operating at rated power. in-At specific steps during the approach to power, the core flux monitors are calibrated. 9.1.4.2.10.3 Qepagtuge of Spegt gum], from Site ll The spent fuel shipping cask arrives by railcar or truck in the railway bay of the reactor building Unit 1. It is lifted from there by the 125 ton hook of a reactor building crane through the floor hatches to the refueling floor and placed into the empty shipping cask pit between the fuel pools of Units and 2. 1 The cask outside is decontaminated'from road dirt and the lid removed by the reactor building crane. One of the inner gates of the shippinq cask pit is removed. After filling of the removed shipping cask pool, the second gate to one of the fuel pools is and loading, of the cask with irradiated fuel commences. The refueling platform is used to transfer fuel bundles of sufficiently low decay heat level from the spent fuel storage racks underwater into the shippinq cask. Followinq replacement of the, cask lid, the gates to the fuel pool are inserted, the shipping cask pit drained, and the cask outside decontaminated. The reactor building crane then transfers the cask from the storage pit onto the shipping vehicle where a cooling system dissipates the remaining decay heat of the fuel during transport. 9.1.4.3 Safety Evaluation 4 9.1.4.3.1 Spent Fuel Cask The spent fuel cask is equipped with dual sets of lifting lugs and yokes compatible with the reactor building crane main hook, thus preventinq a cask drop due to a single failure.,An analysis of the spent fuel cask drop is therefore not required. Rev. 29, 3/82 9; 1-49
- 9. 1. 4. 3. 2 - Reactor Building. Crane See Subsection 9.1.5.3 for the reactor building crane safety eva luati on."
- 9. 1.4. 3. 3 Fuel Servicing Bgui~menf.
Failure of any fuel servicing equipment listed in Table 9.1-2 poses no hazard beyond the effect of the refueling accident analyzed in Chapter 15. Safety aspects (evaluation) of the fuel servicing equipment are discussed in Subsection 9.1.4. 2.3. 9.1.4.3.4 Servicing Aids The small manual devices listed in'Table 9.1-5 facilitate underwater viewinq and handling of fuel. Pailure of any servicinq aid does not pose any hazard beyond the effect of the refuelinq accident.
- 9. 1.4. 3. 5 reactor Vessel Servicing Equipment The dryer-separator slinq and the reactor vessel head strongback are both of a cruciform desiqn providing two redundant sets of liftinq points compatible with the single failure proof reactor buildinq crane main hoist and hook. Therefore accident analysis is not required.
- 9. 1.4. 3. 6 In-Vessel Servicing Equipment Pailure of any in-vessel servicinq equipment~listed in Table 9. 1-5 poses no hazard beyond the effect of the refueling accident analyzed in Chapter 15.
Rev. 29, 3/82 9. 1-50
SS ES-PS AR
- 9. 1. 4. 5. 4 Rad iation Nonitorinar The area radiation monitorinq equipment for the refueling area is described in Subsection 12. 3. 4.
9 1 5 REACTOR BUILDING CRANES Tvo reactor buildinq cranes are provided for the Susquehanna SES. Unit 1 crane is a single failure-proof crane and is designed to handle the spent fuel cask. The Unit 2 crane is not single failure-proof and is de iqned to handle construction loads and all normal plant operation loads except the'pent fuel cask. The Unit 2 reactor building crane, rated 125 tons (main hoist), 5 tons (auxiliary hoist),, is potentially. capable of carryinq any loads vithin its rated capacity, but net over or areas of the refuelinq floor. Limits of the within'estricted . restricted areas are shovn on Figures 9.1-16 A C B. Admin istrative controls are, used to preclude the Unit 2 reactor build inq crane from beinq used for 'handlinq the spent fuel cask when stored in the spent fuel shipping cask storage pit. The f ollovinq description vill address the Unit 1 crane only, which will be re'fe red to as the reactor building crane or the crann.
- 9. 1.5. 1 Des ian Bases The main purpose of the reactor building crane is to handle the spent fue1 cask betveen the cask transport vehic1e, the cask storaqe pit, and the wash-down area in the reactor building.
Secondary purposes of the reactor building crane include:
- 9. 1-55 Rev- 31
SSES-FSAR a) Handlinq loads related to maintenance and replacement of equipment from the reactor .building which are received or shipped through the railroad access, doors b) Handlinq of shield pluqs, reactor vessel and drywell heads, steam dryer and separator, etc, during refueling operations. The reactor buildinq crane is designed for the following ratings: Hain hoist capacity 125 tons Auxiliary hoist capacity 5 tons Speed o f main hoist {at rated load) ., 5 f pm (see Note 1) Speed of. auxiliary hoist (at rated load) 20 fpm (see Note 1) Speed of trolley {usinq main hoist) 30 fpm Speed of trolley (usinq aux hoist) 50 fpm Speed o f bridge 50 fp@ Lift of main hook {see Note 2) 173 ft Lift of auxiliary hook 173 ft Cra ne span 130 Lenqth of runway (between stops) 323 ft Uncontrolled drop Hain hoist 0.5 in. (max.) Auxiliary hoist 8.55 in. (max.) Note 1: Minimum speed at rated load is less than 2 percent of rated speed Note 2: Unit 2 reactor building crane ratings are identical to those of the Unit 1 crane, except for the main hook 68 ft. This, in addition to lift, which is administrative controls, precludes inadvertent use of the Unit 2 crane for spent fuel cask handling, since the main hook does not reach the spent fuel cask plant entry level. 3 ev. 31, 7/82 9. 1-56
SS ES- FS AR The auxiliary hooks of both cranes are designed for use underwater, up to 50 ft. depth.
- 9. 1.5. 2 Eauioment Design a) General The reactor buildinq crane is designed, fabricated, installed, and tested in accordance 'with ANSI 830.2.0, CN N A-70, an d OS HA requlat ions.
b) Structural The structural portions of the crane bridge and trolley are desiqned for {1) dead load plus rated plus impact load of 15 percent of the lift load total dead plus rated live loads, not to exceed allowable stresses; (2) dead load plus rated lift load plus a lateral load of 10 percent of the-.total dead pius rated live loads, not to exceed allowable stresses; {3) the'operating basis earthquake (OB E) wh i le workinq stresses not to li fting the rated load, the exceed 125 percent of the allowable stress: (4) the design basis earthquake (DBE) while lifting the rated load, the allowable stresses to be less than 90 percent in bendinq, 85 percent in axial tension, and 50 percent in shear of the material minimum yield stresses; (5) a tornado loading of 300 psf, without live load, the allowable stresses to be the same as for (4) above. The structure of the crane bridge consists of welded box tvpe qirders with truck saddles and truck frames of welded steel construction. The trolley side frames, sheave frames, and truck frames are of structural steel welded construction. c) Nechanical The crane is of a sinqle trolley top runninq electric overhead travelling bridge design'. The general arranqement of the crane in the reactor building is shown on Piqure 9.1-4. The main hoist is provided with the following dual components preventinq a single failure to result in a drop of. the spent fuel shipping cask: Pev. 31, 7/82 9. 1-57
SS ES- FS AR
- 1) Dual sister hook thook within a hook)
- 2) Dual reevinq systems complete with redundant vire ropes, upper, lower, and equalizinq sheaves
- 3) Dual main hoist gear boxes with individual braking systems.
Each vire rope has a safety factor of five against breakinq while liftinq the rated capacity. In case ot failure of one of the two reevinq systems, the dynamic load transfer to the other system vill not cause the rope load to exceed one-third of the rope breaking strenqth. The following holding brakes are provided: Nain hoist Three, rated for 150 percent of the motor torque, with provision for manual operation to allov lowering of the load
, af ter a power failure Trolley Two, rated for 50 percent of motor torque one, rated for 100 percent nf motor to rque.
Al 1 holding brakes are ac magnet operated. In addition the bridqe is provided vith a hydraulic foot operated brake. d) Controls Bridge and trolley ac static stepless speed control vith reversinq plugging control Hoists dc static reversinq stepless speed control including regenerative braking, with a minimum speed of less than 2 'percent of the rated speed. Operation of the crane is from the bridge mounted cab or floor. The floor operation is by pendant or radio control. Control at any one time is from one point only. Rev. 31, 7/82 9 1-58
SSES-PS AR 9.1.5.3 Safety Fyaluation As described in Subsection 9.1.5.2, the main hoist is provided vith dual main hoist components capable of holding the load in the event of a single failure. The reactor building crane is provided with limit switches to prevent overtravel of the bridqe and trolley and stop the main and auxiliary hooks in their highest and lowest safe positions. Two limit switches, each..of different design, are provided to limit the upward movement of the main and auxiliary hoist. Two geared limit switches are provided for the main hoist, and one for the auxiliary hoist to limit the dovnvard movement of the respective hoists. When the 125-ton hook is not in the parked upper position, I movement of the crane bridge and/or trolley will he stopped vhen enterinq the restricted areas shown on Pigures 9. 1-16A 6 B. The followinq means are provided to accomplish the above: a) A series of proximity svitches mounted on the crane, adjacent to the cra'ne and trolley runways. b), A series of trip bars mounted on the bridge and trolley runways are positioned to trip respective proximity switches. c) Relays and logic systems to trip power supplies to affected drive motors, vhen a proximity switch is tripped. This vill result in the setting of respective holdinq brakes and cessation of bridge or trolley movement. <<Memory logic<<vill then allow the bridge or trolley to move in the opposite direction avay from the
. restricted area.
d.) Administrative controls. A key locked bypass switch is provided in -the cab and the pendant to allow the use of the main- hoist over the.RPV area for handlinq shield plugs, RPV and drywell heads, steam dryer/separator, etc. Crane overload protection is provided by an electrical cut-out on the hoist drive motor. In addition, a loud, cell is provided on the equalizer to prevent the crane from lifting loads in excess of its rated capacity. An overspeed svitch activating all spring set motor brakes in the lowering direction holds the load in suspension. Pev. 31, 7/82 9. 1-59
SS ES- FS AR See Section 3.13 for discussion of compliance with Regulatory Guides 1.104 and 1.13. See Appendix 9B for a discussion of compliance with BTP ASB9-1. The results of a failure mode and effect analysis are presented in Table 9.1-6. The crane is safety related and a quality assurance program has been established and implemented in the design, fabrication, erect ion, and testinq. The crane is designed to remain on the runway i.n a parked and restrained position (by tornado locks) vith no load attached under the following tornado vind loadings: a) 300 psf on the windvard crane girder b) a200 psf on the leevazd crane girder. The crane mechanical and structural components are qualified to Seismic Cateqory I requirements. The crane, however, may become and remain inoperational after the operating basis earthguake, hut no parts or, the load vill, dislodge oz fall. Manual towering of the main hoist load is provided. 9 1.5 4 Inspection and Testing Requirements Crane components tests are performed during the crane fabrication a s follovs: a) Fach hook: Ultra sonic tests 200 percent load test followed by dimensional check Dry powder maqnetic particle test b) Wi re ro pe: Rope sample"destructive breakinq test c) Gears, gear pinions, swivels, load block frames. hook trunnions, seismic restraints, and tornado locks: Magnetic particle tests d) Ma ]or structural, Rev. 31, 7/82 9 1-60
SS ES- FS AR fields: 100 percent magnetic particle testinq. The crane hoists, trolley, and bridqe drives are operated in the shop to demonstrate their operability and the trolley tracking. After the crane is erected, it is thorouqhly tested, including the crane ratinq test in accordance with ANSI B30.2.0. The crane periodic operational test" are in accordance with applicable ASH A regulations, local codes, and ANSI B30. 2. 0.
- 9. 1.5.5 Instrumentation Requirements The crane is furnished with dual devices and controls, as described in Subsect.ion 9. 1.5. 3, to prevent or detect a single crane failure and thus preclude dropping of the spent fuel cask.
- 9. 1 6 RFFERENCZS 9 1-2 "'CHEFTAH-B Man'ual, LEAHS Nuclear Fuel Manaqement
~
and Analysis Package, >>Control Data Corporation, Publication Number 84006200, Minneapolis, Minnesota, (1974) . 9 1-3 R. F. Barry, "LEOPARD A Spectrum Dependent Non-Spatial Depletion Code for the IBM-7094, >>WCAP-3741, Westinqhouse Electric Corporation (1963) . 9 1-4 >>CORC-BLADE Manual, LEAHS Nuclear Fuel Management and Analysis Package,>> Control Data Corporation, Publication Number 84005400, Minneapolis, Minnesota,(1974) . 9 1-5 W. R. Cadvell, ".PDQ-7 Reference Manual"WAPD-TM-678, January, 1967.
- 9. 1-6 M. Petrie a nd N. F. Cross, >>KENO-IV An Improved Monte Carlo Criticality Program,>> ORNL-4938, November, 1975.
- 9. 1-7 N. M. Greene, J; L. Lucius, W. E. Ford, XII, J. E.
White, R. Q. Wriqht, and L. M. Petrie, >>AMPX A Modular Code System for Generatinq Coupled Multiqroup Neutron-Gamma Libraries f rom ENDF/B>>, ORNL-TM-3706, 1974 R ev. 31, 7/82 9. 1-61
SS ES-PS AR
- 9. 1-8 Desiqn and Fabrication Criteria for Susquehanna FSAR
- 9. 1-9 PARSP/3157, P. 7-1 and Appendix X.
9 1-10 Summary Report, Nuclear Criticality Analysis for the Spent Fuel Racks of the Susquehanna Power Plant; Nuclear Associates International, DR-3157-3 ~ Report NAI78-15, Nay 15, 1979. Rev. 31, 7/82 9 1-62
SS ES-FS AR the header start in standby mode. their respective compressor if the compressor is A pressure transmitter on the header transmits to a pressure indicator in the main control room. Two local pressure gages indicate the pressure in the manifold of each safety related instrument. qas supply bottle header. A pressure switch on each header annunciates safety related header low pressure in the main control room. Reduced pressure instrument qas is provided via a pressure reducinq valve. Local and control room indication of this pressure is provided, as well as local pressure indication on the instr ume nt qa s acc um ula to r. 3 2 PROCESS SANPLING SYSTEM The process samplinq system is provided to monitor the operation of plant equipment and to provide information needed to make operational decisions. The process samplinq system provides remote samplinq facilities and the ca@ability for samplinq fluids of various process systems durinq normal plant power operation and shutdown conditions. The monitorinq of gaseous and liquid process streams for nuclear radiation is covered separately in Section 11.5.
- 9. 3.2. 1 Design Bases The port.ion of the process samplinq system running from the reactor coolant system to t'e first isolation valve outside the containment is constructed in accordance with AS.'lE Boiler and Pressure Vessel Code, Section III, Class 1. Other sample piping, from the point where it connects to the process system and includinq the first process shutoff valve {root valve), will be the same classif ication as the system piping to which connects. For ASNE III,. Class l, 2, arid 3 systems the sampling it piping downstream from the root valve will be ASNE III, Class 3 up to and includinq the isolation valve above the sample station.
All ASIDE Section III Class l, 2 and 3 sample piping and valves are desiqned to Seismic Category I requirements. Lines connected to reactor water or main steam systems are of sufficient length to permit decay of short lived nuclides so that sampling personnel will not be unnecessarily exposed to radiation. Additionally, shieldinq is installed at points on samplinq piping to further curtail exposures {as described in Rev. 30, 5/82 9 3-13
SS ES- FS AB Chapter 12) and ensure that they be kept below the limits of 10cr820. The process samplinq system is designed to ensure that representative samples of all appropriate process fluids will be obtained. Process samplinq system pipinq is large enough to avoid beinq clogged by anticipated solids. Piping size is minimized to permit effective line purging with a minimum loss of fluid volume. The process samplinq system is desiqned so that the sample stations will not affect plant safety. The pro"ess samplinq system is designed to provide the capability to conduct continuous analysis as well as analysis of discrete sample., (grab samples) . The process samplinq system is desiqned. to prevent hazards to operatinq personnel f rom high pressure, temperature, or radia tion levels of the process fluid durinq all modes of operation. The process samplinq systems for each unit is designed to be functionally similar but operationally independent. 9.3.2.2 System Description The process sampling system is illustrated schematically by Figures 9.3-6 thru 9.3-9. Locations of sample points are shown on the appropriate system pipinq and instrumentation diagrams for the systems to be sampled. The process sampling system consists o f samplinq lines, heat exchanqers, sample vessels, sa'mple sinks, and analysis equipment and instrumentation. Samplinq stations are located in the reactor, turbine, and radwaste buildings. The liquid radwaste collection sample station and the auxiliary boiler sample station are common for Units and 2. The reactor and turbine building sample stations 1 are operationally independent systems with the following exception: the spare fuel pool filter demineralizer effluent sample and the common offqas recombiner closed loop cooling water sample are located in Unit 1 stations. Local grab samples rather than permanently installed sample lines to a control samplinq station are provided for process points that require weekly sampling and are in zones where radioactivity is less than 15 mrem/hr (radiation Zones I, II or IXIt.~ Samples of reactor feedwater, reactor recirculation water, main steam, and fuel pool water are routed to the reactor building Bev. 30, 5/82 9 3-14
SS ES-FS AR 9.3.3.5 Tnstrumentation Aoolication High and low level switches are provided in each sump. For sumps having tvo pumps, the level svitch vill actuate the second pump at a higher level. The first pump to start is alternated on each pumpinq cycle to equalize run times. Table 9.3-10 shovs the usaqe factors resulting from this provision. The drvwell equipment drain tank drains by gravity. The drain tank~s discharge valves automatically open when a predetermined hiqh level in the tank is reached. The discharge valves close at a Predetermined low level. Oil sumps are equipped with level switches and high level alarms in the main control room. To detect leaks, a level alarm vill be provided in the main control room for each ECCS equipment room. The drywell floor drain sump and the dryvell equipment drain tank temperatures are indicated, and a hiqh alarm is annunciated on a local panel in the reactor buildinq of each unit. The levels in the dryvell floor drain sumps and drywell equipment drain tanks are recorded, and a hiqh-high level ala rm is annunciated in the main control room. Refer to Subsection 5. 2.5 and Section 7.6 for further details of the Leak De tee tion System.
- 9. 3.4 CHEMICAL AND VOLUME CONTROL SYSTEM Not applicable to BMR's.
9.3.5 STANDBY LzguID CONTROL SYSTEM 9.3.5.1 Design Bases The standby liquid control system is a special safety system and is desiqned in accordance with Seismic Category I requirements. It shall meet the followinq safety design bases: la> Backup caPability for reactivity control shall be Provided, independent of normal reactivity control provisions in the nuclear reactor, to be able to shut down the reactor if the normal cont'rol ever becomes inoperative. Rev. 30, 5/82 9. 3-25
SS ZS- FS AR (b) The backup system shall have the capacity for controlling the reactivity difference between the steady-state rated operating condition of the reactor with voids and the cold shutdown condition, including shutdown marqin, to assure complete shutdown -from the most reactive condition at any time in core life. (c) The time required for actuation and effectiveness of the backup control shall he consistent with the nuclear reactivity rate of change predicted between rated operatinq and cold shutdown conditions. A fast scram of the reactor or operational control of fast reactivity transients is not specified to he accomplished by this system. (d) Means shall be provided by which the -functional performance capability of the backup control system components can be verified periodically under conditions approachinq ac+ual use requirements. Demineralized water, rather than the actual neutron absorber solution, can be injected into the reactor to test the operation of all components of the redundant control system. (e) The neutron absorber shall he dispersed within the reactor core in sufficient quantity to provide a reasonable margin for leakage or imperfect mixing. (f} The system shall be reliable to a deqree consistent with its role as a special safety system; the possibility of unintentional or accidental shutdown of the reactor by this system shalL be minimized.
- 9. 3.5. 2 Syste m Description The s+andby liquid control system (see Figure 9.3-13) is manually initiated through a single keylock switch in the main control room to pump a boron neutron absorber solution into the reactor if the operator determines the reactor cannot be shut down or kept shut down with the control rods. The keylocked control room switch is provided to assure positive action from the main control room should the need arise. Procedural controls are app1ied to the operation of the keylocked control room switch.
The boron solution tank, the test water tank, the two positive displacement pumps, the two explosive valves, the two pump suction valves, and associated local valves and.controls are Located in the reactor buildinq. The liquid is piped into the reactor vessel and discharged near the bottom of the core shroud so it mi xes with the coolinq water rising throuqh the core {see Section 5. 3) . Rev. 30, 5/82 9. 3-26
SS PS-PS AR The snecif ied neutron absorber solution is sodium pentaborate {Ha2 Blp>610H>0). It is prepared by dissolving stoichiometric quantity.es of borax and boric acid in demineralized water. An air sparger is provided in the tank for mixing. To prevent system pluqqinq, the tank outlet is raised above the bottom of the tank. The SLC system is sized to deliver enough sodium pentaborate solution into the reactor {see Piqure 9.3-14) to assure reactor shutd own. The saturation temperature of the recommended solution is 59~F at the low level alarm volume and approximately 49 F at the tank overflow volume (see Figure 9.3-15). The equipment containing the solution is installed in a room in vhich the air temperature is to be maintained within the ranqe of 600 to 1000F. In addition. a heater system maintains the solution temperature at 75~ to 85oF to prevent precipitation ot the sodium pentaborate from the solution durinq storaqe. High 'or lov temperature, or high or Lov liquid level, causes an alarm in the control room. Hach positive displacement pump is sized to inject the solution into the reactor in 50 to 125 minutes. The pump and system desiqn pressure between the explosive valves and the pump discharqe is 1400 psiq. The tvo relief valves are set slightly under 1400 psiq. To prevent bypass flow from one pump in case of relief valve failure in the line from the other pump, a check valve is installed dovnstream of each relief va lve line in the pump discharqe pipe. The tvo c.xplosive-actuated injection valves provide assurance of opening who.n needed and ensure that boron vill not. leak into the reactor even when the pumps are being tested. Hach explosive valve is closed by a plug in the inlet chamber. The plug is circumscribed with a deep groove so the end will readily shear off when pushed with the valve plunger. This opens the inlet hole through the plug. The sheared end is pushed out of the way in the chamber; it is shaped so ports after release. it vill not block the The shearinq plunqer is 'actuated by an explosive charqe with dual iqnition primers inserted in the side chamber of the valve. Ignition circuit continuity is monitored by a trickle current, and an alarm occurs in the control room if either circuit. opens. Indicator liqhts show vhich primary circuit opened. The SLC system is actuated by a three-position keylocked switch on the control room console. 'This assures that svitching from the>>off>> position is a deliberate act. Switching to either side starts an injection pump, actuates both of the explosive valves, and closes the reactor cleanup system outboard isolation valve to prevent loss or dilution of the boron. Rev. 30 '/B2 9 3-27
A light in the control room indicates that power is available to the pump motor contactor and that the contactor is deenergized (pump not runninq) . Another light indicates that the contactor is enerqized (pump runninq) . Storaqe tank liquid level, tank outlet valve position, pump discharqe pressure, and loss of continuity on the explosive valves indicate that the system is functioning. If any of those items indicate that the liquid may not be flowing, the operator may immediately chanqe the other switch status to "run" thereby activatinq the redundant train of the SLC system. The local switch will not have a "stop" position. This prevents the isolation of the pump from the control room. Pump discharge pressure and valve status are indicated in the control room. I,"quinment drains and tank overflow are not piped to the radwaste system but to separate containers (such as 55-gal. drums) that can be removed and disposed of independently to prevent any trace of boron from inadvertently reachinq the reactor. Instrumentation consistinq of solution temperature indication and control, solution level, and heater system status 'is provided locally at the storaqe tank. Table 9.3-11 contains the process data for the various modes of. operation of the SLC.
- 9. 3.5. 3 Sa fety Evaluation The standby liquid control system is a reactivity control system and is maintained in an operable status whenever the reactor is critical. The system is expected never to be needed for safety reasons because of the large number of independent control rods available to shut down the reactor To assure the availability of the SIC system, and to facilitate maintena nce and testinq, two sets o f the components required to actuate the system pumps and explosive valves are provided in parallel redundancy.
The system is desiqned to brinq the reactor from rated power to a cold shutdown at any time in core life. The reactivity compensation provided will reduce reactor power from rated to zero level and allow coolinq the nuclear system to room temperature, with the control rods remaininq withdrawn in the rated power pattern. It includes the reactivity gains that result f rom complete decay of the rated power xenon inventory. Xt also includes the positive reactivity effects from eliminating steam voids, chanqinq water density from hot to cold, reduced Doppler effect in uranium, reducing neutron leakage from boiling to cold, and decreasing control rod worth as the moderator cools. Bev. 30, 5/82 9 3-28
SS ES- FS AR The minimum average concentration of natural boron in the reactor to provide adequate shutdown marqin. after operation of the SLC system, is 660 ppm. Calculation of the minimum quantity of sodium pentaborate to be injected, into the reactor is based on the required 660 ppm average concentration in the reactor coolant includinq recirculation loops, at 70~P and reactor normal water level. The result is increased by 25'4 to allow for imperfect mixinq and leakaqe. Additional sodium pentaborate is provided to accommodate dilution by the RHR system in the shutdown coolinq mode. This concentration will be achieved if the solution is prepared as defined in Subsection 9.3.5.2 and maintained above saturation temperature. Cooldown of the nuclear system will require a minimum of several hours to remove the thermal enerqy stored in the reactor, cooling water, and associated equipment. The controlled limit for the reactor vessel cooldown is 100oF per hour, and normal operatinq temperature is approximately 550oF. Use of the main condenser and various shutdown coolinq systems requires 10 to 24 hours to lower the reactor vessel to room temperature (70~P); this is the condition of maximum reactivity and, therefore, the condition that requires the maximum concentration of horon. The specified boron injection rate is limited to the range of 6 to 25 ppm per minute. The lower rate assures that the boron is injected into the reactor in approximatley two hours. This resultinq reactivity insertion is considerably quicker than that covered hy the cooldown. The upper limit injection rate assures that there is sufficient mixinq so that boron does not recirculate throuqh the core in uneven concentrations that could, possibly cause reactor power to rise and fall cyclically. The SLC system is required to .be operable in the event of a station power failure, therefore the pumps, heaters, valves, and controls are powered from or connectable to the standby a-c power supply. The pumps and valves are powered and controlled from separate buses and circuits so that a single electrical failure will not prevent injection of sodium pentaborate on demand. The SLC system and pumps have sufficient pressure margin, up to the system relief valve settinq of approximately 1400 psig, to assure solution injection into the reactor above the normal oressure -in the bottom of the reactor. The nuclear system relief and safety. valves begin to relieve pressure above approximately 1100 psiq. Therefore, the SLC system positive displacement pumps cannot overpressurize the nuclear system. Only one of the two standby liquid control pumps is needed for system operation. Zf a redundant component (e.q., one pump) is found to be inoperable, there is no immediate threat to shutdown capability, and reactor operation can continue during repairs. The time durinq which one redundant component upstream of the explosive valves may be out of operation should be consistent Rev. 30, 5/82 9. 3-29
SS ES- PS AR with the follovinq: the probability of failure of both the control rod shutdown capability and the alternate component in the SLC system; and the fact that nuclear system cooldovn takes several hours while liquid control solution injection takes approximately two hours. Since this probability is small, considerable time is available for repairing and restorinq the SIC syst: em to an operable condition while reactor operation continues. Assurance that the system will still -fulfill its function during repairs is obtained by demonstratinq operation of the operable pump. In the event of a loss of the thermostatically-controlled storage tank heater >>A>>, a low temperature alarm vould eventually be annunciated in the control room and vould alert the operator to control storage tank temperature manually from the local panel by means of the mixinq heater <<B<<. A lov-temperature alarm vill also annunciate in the control room if there is a loss of the suction piping heat tracing. The alarm setpoint. is sufficiently above saturation temperature of the sodium pentaborate solution such that, even in the unlikely event that. ambient temperature is belov 70~P, sufficient time vill be available to enable the operatinq personnel to take appropriate temporarv measures to heat the suction piping before p reci pit at ion occ urs. The SLC system is evaluated against the applicable General Design Criter ia as f oil ovs: Criterion 2: The SLCS is located in the area outside of the nrimary containment (dryvell) and belov the refueling floor. In " this location it is protected by the containment and compartment walls from external natural phenomena such as earthquakes, tornadoes, hurricanes and floods and internally from effects of such events and internal postulated events. Lriterion 4: The SLCS is desiqned for the expected environment in the containment and specifically for the compartment in which it is located. Tn this compartment, it is not sub ject to the more violent conditions postulated in this criterion such as missiles, vhippinq pipes, and discharqinq fluids. This system is only called upon to perform a 'pseudo-safety function under normal operation conditions. Criterion 21: Criterion 21 is applicable to protection systems only. The SLC system is a reactivity control system and should be evaluated aqainst Criterion 29. Criterion 26: The SLCS is the second reactivity control system required hv this criterion. The requirements of'his criterion do not apply vithin the SLCS itself. Rev. 30, 5/82 9 3-30
SSES-PS AB Criterion 27: This criterion applies no specific requirements onto the SLCS and, therefore, is not applicable. See the General Design Criteria Section (Section 3. 1) for discussion of combined capabilit.y. rgiterinn 29: The SLCS pumps and valves outboard of the isolation valves are redundant. Two pumps, and two injection valves are arranged and cross-tied such that operation of any one of each results in successful operation of the system. The SLCS also has test capability. A special test tank is supplied for providinq test fluid for the yearly injection test. Pumping capability may be tested at any time. A trickle current continuously monitors continuity of the firing mechanisms of the in jection sauib valves. The SLC svstem is evaluated aqainst the applicable regulatory guides as follows: reactivity control system, all mechanical components are at least Quality Group D. Those portions which are part of the Reactor Coolinq Pressure Boundary are Quality Group A. This is shown in Table 3.2-1. Regulatory Guide l.29 Revision 1: All GE supplied components of the SLCS which are necessary for injection of neutron absorber into the reactor are. Seismic Cateqory I. This is shown in Table
- 3. 2-1.
Since the SLC system is located within its own compartment within the reactor buildinq, it is adequately protected from flooding, tornadoes, and internally and externally generated missiles. SLC system equipment is protected from pipe break by providing adequate distance between the seismic and non-seismic SLC system equipment where such protection is necessary. In addition, appropriate distance is pro'vided between the SLC system and other pipinq systems. Where adequate protection cannot be assured, barriers have been considered to assure SLC system protection from pipe break (See Section 3.6). It should be noted a safety function that the SLC system is not required to provide durinq any postulated pipe break events. This system is only required under an extremely low probability event where all of. the control rods are assumed to be inoperable while the reactor is at normal full power operation. Therefore, the protection provided is considered over and above that required to meet the intent of APCSB 3-1 and NFB 3-1. This system is used in a couple of special plant capability demonstration events cited in Appendix A of Chapter 15. Specifically Events 51, 52, and 53 which are extremely low probability non-design basis postulated incidents. The analyses Rev 30, 5/82 9 3-31
SS ES- FS AR given there are to demonstrate additional plant safety consideration far beyond reasonable and conservative assumptions. A system-level, qualitative-type failure mode and effects analysis is presented in Subsection 15A.6.6. g.3 5.4 Testing and Inspection Requirements Operational testinq of the SLC system is performed in at least two parts to avoid inadvertently injecting boron into the reactor. With the valve from the storage tank closed and the valves to and from the test tank opened, demineralized water, in the test tank can he recirculated by locally starting either pump. Durinq a refuelinq or maintenance outage, the 'injection portion of the system can be functionally tested by valving the suction line to the test tank and actuatinq the system from the control room. System operation is indicated in the control room. After functional tests, the injection valve shear pluqs and explosive charges must be replaced and all the valves returned to their normal positions as indicated. After closinq a local locked-open valve to the reactor, leakage throuqh the injection valves can be detected by opening valves at a test connection in the line between the containment isolation check valves. Position indicator lights in the control room indicate that the local valve is closed for tests or open'nd ready 'for operation. Leakage from the reactor through the first check valve can be detected by opening the same test connection in the line between the Containment Isolation Check Valves when the reactor is pressurized. The test tank contains demineralized water for approximately 3 minutes of pump operation. Demineralized water from the makeup system or the condensate storaqe system is available for refillinq or flushinq the system. Should the boron solution ever be injected into the reactor, either intentionally or inadvertently, then after making certain that the normal reactivity controls will keep the reactor subcritical, the boron is removed from the reactor coolant system by flushing f or gross dilution followed by operatinq the reactor cleanup system. There is practically no effect on reactor operations when the boron concentration has been reduced below approximately 50 ppm. The concentration of the sodium pentaborate in the solution tank is determined periodically by chemical analysis. Electrical Bev. 30, 5/82 9. 3-32
SS ES- FS AR supplies and relief valves are also subjectede too perio ic testing (see Chapter 16). The SLC system is preoperationally tested in with th e accordance e wi requirements of Chapter 14. 9.33.5. 5 Instr omen ta t iog Rendu i reme t The instrumentation and control system forr thee .SLC is desiqned to allow the in jection
'ec of liquid poison into the react or an d th e maintenance of the liquid poison solution well above the
~ ~
saturation temperature. A further discussion o f the S1.C instrumentation may be found in Chapter 7. R ev. 3 0, 5/82 9 3-33
TABLE 9.3-10 Page 2 of EQUIPMENT AND FLOOR DRAINAGE SYSTEM COMPONENT DESCRIPTION SUMPS AND DRAIN TANKS Sump (Tank) Live/ Nominal Oil Sump Equipment Material Capacity Oil Inter- Capacity Nos. Quant~it Liner/Cover ~Each al Manhole ~ce torTTpe ~Each al Drywell Floor Drains Unit fl Lined Sump W. SS/- 230/ 450 No Drywell Floor Drains Unit 02 Cooling Coil SS/- 230/ 450 No Drywell Equipment Drains 1T-218 Vert. Tank CS 1000/1060 Yes Dryvell Equipment Drains 2T-218 Vert. Tank CS 1000/1060 Yes Reactor Building Drains Unit 41 Lined Sump SS/18>> Conc. 2510/4050 Yes API-500 gpm 670 Reactor Building Drains Unit 82 Lined Sump SS/18>> Conc. 2510/4050 Yes API-500 670 Turbine Bldg. Outer Area Drains Turbine Bldg. Outer Area Drains Unit Unit fl Lined Sump SS/9>> Conc. 2570/4130 Yes API-500 gpm gpm 670 02 Lined Sump SS/9" Conc. 2570/4130 Yes API-500 gpm 670 Turbine Bldg. Central Area Drains Unit.fl Lined Sump SS/9>> Conc. 2570/4130 Yes API-500 gpm 670 Turb. Bldg. Central Area Drains Unit d2 Lined Sump SS/9>> Conc. 2570/4130 Yes API>>500 gpm 670 Turb. Bldg. Condenser Area Drains Turb. Bldg. Condenser Area Drains Unit fl Lined Sump SS/1>> CS / 692 No Turbine Bldg. Chemical Drains Unit t2 Unit dl Lined Lined Sump SS/1>> CS / 692 No Sump SS/1>> CS 486/ 935 No Turbine Bldg. Chemical Drains Unit f2 Lined Sump SS/1>> CS 486/ 935 No Chem. Radvaste Drains OT-114 Vert. Tank SS 280/ 378 No Laundry Radwaste Drains OT-115 Vert. Tank SS 280/ 378 No Radvaste Building Drains Common Lined Sump SS/12>> Conc. 970/1940 Yes Radvaste Building Chem. Drains Common Lined Sump SS/12>> Conc. 630/1215 Yes Pipe Tunnel Drains Unit 81 Only Lined Sump SS/1>> CS 150/ 360 No Circ. Water Pump House Drains Common Unlined Sump 15>> Conc. 920/1550 Yes AP & Baffle 250 Diesel Generator Bldg. Drains Common Unlined Sump -1/4>> CS 920/1390 Yes Baffle 135 Cl and Acid Storage Bldg. Common Unlined Sump -/12>> Conc. 790/4110 Yes Water Treat. Bldg. Chem. Drains Common Unlined Sump -/15>> Conc. 600/1190 Yes Rev. 25, 7/81
'SES-PSAR 10~ 4 6 CONDENSATE CLEANUP SYSTEM 't 0.4.6.1 presign "Bases The.,condensate demineralizer.'ystem has no safety-.related functions'and's"desiqned to maintain the condensate at the
'equired purity by removal of the .following contaminants: a) Products, resulting. from corrosion that occur in the main steam and turbine extraction piping, feedwater heater shells, and drains b) ~ Suspended and dissolved solids that may be introduced by small leakages of circulating=-water thxough condenser tubes c) Fission and activati'on products that are entrained in reactor steam and retained in condensate leaving the hot well d) 'olids carried into,'the condenser by makeup'ater and
~%
miscellaneous drains., The system design is- based, on'he influent concentrations given in Table 10.4-2. At 4800 qpm per vessel, and with the influent quality listed in a) b)
,d)
Silica 254c,; Conductivity at 254C pH at (SiO>
'ron",,total ) .
(Pe) Table 10.4-2, the ion exchanqers effluent will not exceed the followinq quality:
' '.1 5 ppb 5 ppb micromho/cm 6.5,to 7.5 ')
=
e) q)
=
f)...Nickel (Ni),'=, Copper (Cu) Chlori.de (Cl) .-
~
. 1 ppb 2 ppb ppb-h) Tota 1 metallic im puri.ties + 9 pp b 4Total metallic residue retained on a 0.45 micron film. filter.
hp Pipinq is furnished in accordance with ANSI B31.1.0., Pressure vessels that fall within the jurisdiction of ASME Section VIII are furnished in accordance. with that Code. The design pressure of the condensate,. demineralizer system is 740
~
psig at '1504P, which is above the shut-off head of the condensate-pum ps. Rev. 30, 5/82 10 4- 19 4 I
SS ES- PS AR
'The'ondensate 'demineralizer system (Pigure 10.4-2) is designed,
-to purify'condensate'=c'ontin'uously at 131~P and 550 psig at a flow
=
rate of .28,800 qpm. Each demineralizer .vessel has a flow
, capacity of 4,800 gpm and is'capable of operating at flow rates f'. 'up to 5,760 gpm't'or short perious.
10.4. 6.2 1 Condensate Demiperalizer~Sstem The condensate demineralizer system consists of a battery of seven"'ion exchanqers, each containing a bed of mixed resin in the proportion of two'arts cation resin .to one part anion resin by volume. Six exchanqers are in service at one time during'ormal conditions. The seventh exchanqer is held on standby for replacement of an inservice unit at the end of its service run and in the event 'of an abnormal condenser leak., The condensate
', demineralizers are piped directly into the feedwater cycle and receive condensate under pressure from the condensate pumps..
Regeneration- of a specific demineralizer unit occurs when one of three endpoints is reached: 1 Total flow throuqh a unit .reaches a preset limit {130,000,000 qallons), 20 If the pressure drop across the influent and effluent it is the lowest-flow headers -,exceeds 50 psid- and demine ra lizer unit. 3 Conductivity measurements at the outlet of each unit reach a preset le vel (0. 1 p mho/c m) . Based on a total throughput of 130,000,000. gallons, regeneration frequency is approximately every 19 days for each resin bed based on influent quality listed in Table 10.4-2 at full load. These endpoints have been chosen in order that each'resin bed be taken ou t of service prior to reaching an unacceptable level of operation. In particular, the conductivity measurements provide indication that a specific bed may be ionical'ly exhausted:in order that it may be reqenerated 'before an unacceptable. level of overall condensate water quality is reached. The control room alarm setpoint for the outlet of each.
'emineralizer vessel, indicatinq resin bed exhaustion, is lp mho/cm as is:the,control room alarm setpoint for the condensate effluent header. II Condensate influent to the Rev. 30, 5/82 10 4- 20
SSES-PS AR demineralizers is alarmed in the control room at 0.2p mho/cm conductivity. The resin beds are transferred from the ion exchangers- to the external reqeneration system for cleaning and chemical reqeneration. A spare charge of resins is held in the ex'ternal regeneration system for immediate replacement of an exhausted bed' in an ion exchanger so that the exchariger may be made available promptly for replacement of another exhausted exchanger. 10.4.6.2~2 external Regenegation System The system provided for cleaninq and chemical regeneration of the resins used in the condensate demineralizer. is shown in Pigure 10.4-3. It consists essentially of three vessels: a,cation, an anion, and a resin storage tank. The cation tank also'erves as a resin receiving, resin cleaninq, and resin separation tank, through which exhausted resins are transferred from the ion exchanger to the regeneration system. Interlocks are provided an off-line demineralizer cannot detect condensate pressur'e so'hat unless
- addition, it if is isolated from the exte'mal regeneration system. an hiqh pressure occurs in the ress,n transfer line, Xn.
isolation valve in the line will automat'ically close and a relief valve will open to protect %he system: The r,'eqeneration system is designed for 75 psig and 150oP. The removal of crud accumulation on the resins i:s accomplished by a cycle of draininq, air backwashing, and rinsing in the cation tank. The regeneration system is designed for use with an ultrasonic resin cleaner and space and connections are provided so that one may be added later. The cleaned resins are transferred back to the oriqinal ion exchange..vessel for further ion exchange. I ~ Resins in need of complete regeneration are tLansferred to the cation regeneration tank and cleaned as described in the preceding paragraph. The anion and cation resins are then separated by backwashing before the anions are transferred to the anion reqeneration tank. At, the end of regeneration the resins-;." are mixed and stored in the resin storage tank. 10,a,6a$ ,3 Aci.d agd C~gstic g~1~ic~ms stems ada of acid and caustic required for regeneration of cation 'o and anion resins are prepared by in-line dilution of 66 degree" ~ acid and 50 percent sodium hydroxide pumped from. 'aume'ulfuric bulk storaqe tanks below the regeneration equipment Rev. 30, 5/82 10 4-21
SSES-FSAR Approximatey 5-1/2 percent concentration of acid solution is required to regenerate the cation resins. The strong acid is mixed in a mixinq tee with clean condensate as needed. Mater is supplied at a constant rate by condensate transfer pumps through a pressure control valve. Approximately 5-l/2 percent concentration -of caustic at 120oF is required to reqenerate the a'nion resins. Strong caustic is mixed with dilution wa'ter at 120~P in a mixing tee as needed. Dilution water is produced by blending 180~P water from the caustic-dilut=ion hot water tank with cool water. 10.4 6 2 4 Mast@ System Three types of wastes are seqreqated from the regeneration waste discharqe These are: high conductivity, low conductivity and low solids content, and low conductivity and high solids content. High conductivity wastewater (conductivity above 100 micromhos) is channeled to the chemical waste neutralizer tanks where it is, neutralized and pumped to the radwaste evaporators for distillation. Low conductivity condensate from this process is returned to the condensate storaqe.tank. Low conductivity low solids wastewater is channeled to the turbine buildinqs outer area sump where it is pumped to the liquid radwaste collection tanks. Low conductivity high solids waste water (greater than 3 JTU) is channeled to the regeneration waste surge tanks. The tanks are designed with cone bottoms. From there the wastewater is pumped at 35 qpm to the waste sludqe phase separator. See Section 11.2 for the effect of the Condensate Cleanup System on the radwaste system.
- 10. 4. 6. 3 Safety Evaluation The equipment and controls in the condensate demineralizer system are of the same. design and operational integrity as those in the radwaste system.
Spare capacity is provided'n the system to negate the possibility of difficulties in handling radioactive waste when the system is operating. If the radwaste handling system approaches desiqn capacity, such as when condenser tube leaks reguire maximum rates of regeneration of ion exchanqers, the unit R e.v. 30, 5/82 10 4- 22
SS ES-PS AR l load is reduced to eliminate the possibility of exceeding operational limits. The effluent water quality stated in. Subsection 10.4.6.1 will not be exceeded with an 11.5 qpm condenser leak when circulating water contains 1000 ppm of'total dissolved solids. The system will sustain an effluent conductivity of 0.15,micromho with a 46 qpm condenser leak when circulating water contains 1000 ppm of total dissolved solids. The circulatinq water quality used in the desiqn of the CCS is given in Table 10.4-3. Conductivity is recorded at '12 locations in the condenser, at analysis stations located on the:common influent and effluent healer to the condensate demineralizer system, on the discharge of each ion exchange vessel, and at the discharge healer of the reactor feed = pumps. High conductivity alarms are,providel to. alert the plant operators to an abnormal condition. E II Treated condensate conductivity levels are maintained within the limits of Table: 2 of Regulatory Guide 1.56, Hev. 1 in the follosinq manner: Individual demineralizer vessel outlet conductivity is monitored and continuously recorded locally'at the Turbine Building Sample Station Control Panel. High conductivity, indicating, ionic exhaustion,,i.s alarmed locally'and at the main,.control r'oom-panel.. The hiqh conductivity alarm setpoint's,O'1 p mho/cm, thus an ionically exhausted resin bed is removed"from', service an'd regenerated before reaching the Table 2 of Regulatory Guide 1.56 ' Hev. 1 lower -limit of 0.2pmho/cm. In addition, a regenerated resin bed beinq-brouqht on line is automatically,recycled to.,the condenser prior to being placed in service to ensure'.that the . vessel is,not brought on stream at high..:conductivity levels.,'he combined demineralizer outlet conductivity is also monitored and continuously recorded locally at the-Turbine B'uilding sample station control. panel. High conductivity of the combined effluent is alarmed locally. and at the main control room panel at O.l p mho/cm. Since each vessel is alarmed vhen conductivity
- reaches 0.1 pmho/cm. The likelihood of the combined effluent reaching the alarm point is remote except, under conditions of a larqe condenser lea'k. However, demineralizer inlet conductivity is 'monitorel in the same manner,.'as the outlet flovs, with an alarm setpoint of 0.2 p mho/cm indicating condenser leakage.
(Table 2 of'Regulatory Guide 1.56, Rev.. 1 lover limit is 0.5p" mho/c m) . The condensate demineralizer system is designed to operate'in a manner such that, corrective action is initiated "prior to reaching the"lover limits of Table 2 of Regulatory Guide 1.56, Rev. 1. The values shown in Table 10.4-4 are arrived at assuming 100 percent removal 'efficiency for all dissolved. principal fission Rev. 30, 5/82 10 4- 23
SS ES-PS AR and corrosion activation products. However, because the removal efficiency for suspended'olids*is 50 to 75 percent, .the overall removal of co'rrosion activation products is somewhat less than l00 percent for the system. fables 10.4-4 anl 10.4-5 provide the design bases for radiation shieldinq in the condensate de min erali!z er area. The effluent strainer in the dischar'ge from each'ion exchanger protects the feedwater system aqainst a massive discharge of resins in the event of an underdrain failure. 10.4.6 4 Tests and Inspectgogs Piping is inspected and tested in: accordance with ANSI B31.1.0. All pressure vessels are hydrostatically tested to 1.5 times their design pressure.: The system will be preoperationally tested in accordance with the requirements of Chapter 14.
- 10. 4. 6. 5 Contgolg'gd Xggtrumgytat ion .
The condensate demineralizer and .re'generation systems, are controlled from a local contr'ol panel for all modes .of operation, includinq transfer of resins, for. cleaning and retu'ming 'these, resins to the exchange vessel, 'or the,,transfer of resins for cleaning and regeneration and transferring, previously regenerated stored resins to the exchanqer*for 'standby,; The conductivities are monitored by 'a, multipoint recorder for the followinq: " .' ',
- a) Influent and effluent. of the'- condensate polishing demineralizer, system b) Effluent from each .condensate polishing'emineralizer.
In addition,',conductivity alarms are provided,'to alert the operator for!off-normal conditions Resin condition is monitored in accor dance with. Regula tory Guide 1..56. 4 differential. pressure transmitter is provided to monitor the differential pressure across the condensate demineralizer system. Flow transmitters, recorders, and flow totalizers are provided -in the effluent of each condensate polishing demineralizer." Rev. 30; 5/82 10 4-24
SSES-FSAR
- 11. 3 GASEOUS QASTE MANAGEMENT SYSTEMS ~
- 11. 3 1 ~ DESIGN BASES
~
11 3. 1. 1. Design Objective The gaseous waste'anagement systems (GRMS) are designed to process and control the release of qaseous radioactive wastes to the site environs so that the total radiation exposure of persons in offsite areas is as low as reasonably achievable and does not exceed applicable guidelines. This is to be accomplished while maintaininq the occupational exposure as low as reasonably achievable and without limiting plant operation or availability.
- 11. 3. 1. 2 Desian Basis The gaseous waste systems are =.desiqned to limit offsite doses from routine station releases to significantly less than the limits specified in 10CFR20, and to operate within the dose objectives established in 10CFR50, Appendix I.
The desiqn basis and maximum expected source terms correspond to 100,000 and 60,000 p Ci/sec respectively of nob le radiogas after a 30 minute delay. Table 11.3-1 lists the quantities of nuclides expected to be released to the environs when opera, ting at the maximum expected failed fuel levels. The expected doses to individuals at or beyond the site boundary are shown in Subsection 11.3.4 and Environmental Report Subsection 5.2.4.2. A description of the major equipment items in the offgas system is Provided in Table 11. 3-5. The seismic and quality group classifications of the GWMS components, piping and structures housinq them are listed in Section 3.2. Conservative analyses similar to those presented in Ref 11.3-1 demonstrate that equipment failure cannot result in doses exceedinq acceptable guidelines; thus, neither the offgas system nor the buildings housinq the equipment were designed to meet Seismic Category I requirements; however, the offgas structural walls are part of the total structural shear wall system and were ) analyzed to withstand the effects of earthquakes. The failure of the Ambient Temperature Charcoal Offgas Treatment system is analyzed in Subsection 15.7.1.1. The related failure of the steam jet air ejector lines and failure of the main turbine gland sealinq system are analyzed in Subsections 15.7. 1.3 and 15.7.1. 2 respectively. Rev. 30, 5/82 1 1~ 3
SSES-PSAR
- 11. 3. 2 SYSTFN DESCRI PTXONS 11 3. 2.1 nffaas System Noncondensible radioactive offqas is continuously removed from the main condenser by the steam jet air ejector {SJAE) durinq plant operation. This is the major source of gaseous releases from the plant and is larqer than all other sources combined.
The SJAH offqas will normally contain activation gases, principally N-16, 0-19, and N-13. The N-16 and 0-19 have short half-lives and are readily decayed. The N-13, with a 10-minute half-life is present in small amounts that are further reduced by delay. The SJAF. offqas will also contain various isotopes of the radioact ive noble qases Xe and Kr, precursors of biologically siqnificant Sr-89, Sr-90, Ba-140, and Cs-137. The concentration of. these noble gases depends on the amount of tramp uranium in the coolant and on the claddinq surfaces {usually extremely small) a nd the number and size of fuel cladding leaks. An of fgas system has been provided to treat these radioactive sources. This system utilizes catalytic recombination and charcoal adsorption as discussed below. The building layout and equipment location of the offqas system corn ponents is shown on Piqures 11. 2-3 through 11. 2-7.
- 11. 3. 2. 1. 1 process Plow Description The noncondensible qases in the main turbine condenser are removed hy a two staqe steam jet air ejector (SJAF) and discharged to the offqas recombiner system. During startup, clean auxiliary steam maybe used to drive the SJAE and the recombiner system to minimize operation of and untreated noncondensible releases from the mechanical vacuum pump. After start up, pressure reduced steam from the main steam line is used.
Because of the limited motive steam capacity of the second stage .SJAE, additional dilution steam to maintain the H2 concentration below 4% by volume in the offqas stream, bypasses around the e jector nozzle to the discharge. This arrangement allows ad justinq the total dilute.on steam flow without sacrificing SJAE performance. The offqas-steam flow then enters the associated or the common standby catalytic recombiner system through an elect.rically heat traced piping manifold This prevents condensation of the dilution steam particularly during cold start-up. The purpose of the recombiner system is to reduce the offqas volume and eliminate the potential for explosion by controll ed recombination of the radiolytic hydrogen with oxygen to less than 1% concentration by volume on a dry basis of 5 scfm Rev. 30, 5/82 1 1&3 2
SSES- F SAR air flow and less than 0.5% concentration for an air flow of atl east 10 scfm. The offgas first passes through the recombiner preheater in order to minimize the moisture contents prior to entering the catalyst bed. The recombination pr ocess takes pl ace inside the recombiner vessel which is el ectrically preheated during standby to a range of 240'F to 270'F strip heaters on the outside. The reaction temperature is approximately 800'F. The moisture in the offgas .leaving the recombiner vessel is removed in the recombiner 'condenser where the offgas is cool ed to 150'F. A motive steam jet then boosts the saturated gas stream pressure fr om bel ow to sl,ightly above atmospheric pressure. The reduced pressure main or auxiliary motive steam used in the motive jet is then removed from the offgas stream in the motive steam jet condenser and the 150'F offgas passes through a delay pipe from the recombiner system in the turbine building to the ambient temperature charcoal offgas system in the radwaste building. The pressure differential between the condensers in the recombiner systems and the main condenser is sufficient to drain the condensate without additional motive force to the main condenser, while the delay pipe is drained by level controlled valves to the turbine building radwaste sump. The delay line varies in diameter from 8 to 16..in. and is approximately 600 ft in length. At the design flow rate of 30 scfm, this pipe provides for approximately nine minutes of decay of the radioactive products in the offgas stream prior to entering the adsorption train. After exiting this line, the gas is cooled to approximately 40'F by a refrigerated chiller unit and reheated to approximately 65'F to prevent condensation. Moisture and temperature instrumentation measure the process conditions downstream of the chiller to monitor the performance of the water removal assemblies and to guard against degraded charcoal performance that might result from either an increase in the moisture content or temperature of the gas. Prior to entering the main char coal vessels, the process stream passes through a sacrificial guard bed. The principal function of this guard bed is to absorb impurities that may be entrained in the process gas that might adversely affect the performance of the charcoal adsorbent. Each guard bed has been sized to absorb the moisture that might result from a failure of the chiller over a period of 48. hours. This design feature, in conjunction with the moisture and temperature instrumentation, should provide adequate protection against the contamination of the charcoal Rev. 33, 4/83 11.3-3
SSES-FSAR adsorber bed. Differential pressure indication is provided as a backup to the moisture instrumentation. After passing through the guard bed, the gas enters the main charcoal adsorption bed. This bed, operating in a controlled temperature vault, selectively adsorbs and delays the xenon and krypton from the bulk carrier gas. This delay on the charcoal permits the xenon and krypton to decay in place. After undergoing a sufficient decay in the charcoal vessels, the process stream passes through a HEPA outlet filter, where radioactive particulate matter and possible charcoal fines are retained. This stream is c'ontinuously monitored and an alarm will annunciate any abnormal releases from this system. The process stream is then directed to the turbine building ventilation exhaust duct where it is diluted with minimum 42,000]scfm of air prior to being released from the top of the reactor building. Table 11.3-1 indicates the estimated annual release rates from the turbine building of various isotopes. 11.3.2. 1. 1. 1 Process Flow Dia ram Figure 11.3-1 is the process flow diagram for the system. The process data for startup and normal operating conditions are contained in Table 11.3-8. 11.3.2. 1. 1.2 Process and Instrumentation Dia ram PAID The PAID is shown as Figures 10.4-9, 11.3-3, A8B and 11.3-4. 11.3.2. 1. 1.3 Process Desi n Parameters The krypton and xenon holdup times are closely approximated by the following equation: K M (Equation 11.3-1) Y Where: holdup time of a given gas dynamic adsorption coefficient for a given noble gas mass of charcoal adsorber Rev. 33, 4/83 11. 3-4
SSES-PS AR V = flov rate of the carrier qas. Conservative dynamic adsorption coefficients of 420 cc/gm for xenon and 23.7 cc/qm for krypton vere assumed for the charcoal adsorbent material. They were derived by adjusting the values presented in NUREG 0016 for the temperature and humidity conditions of the Susquehanna SES offqas process stream. Dynamic adsorption coefficients for xenon and krypton have been reported by Browning {Ref. 11.3-2). General Electric has performed pilot plant tests at their Vallecitos Laboratory, and the results vere reported at the Twelfth AEC Air Cleaning Conference (Ref. 11.3-6). Further data on a similar system operatinq at ambient temperature are reported in Ref 11.3-3. The temperature adjustment was obtained by a straight-line interpolation of the coefficients provided, in NUREG 0016 .for the followinq data points: 77~P, dev point OOF and 00P, dew point 20~F. The moisture content of a qas mixture at these two points is relatively low and thus the variations in adsorption coefficients between these points is mainly a function of temperature. The coefficients thus obtained were adjusted to reflect the effects of moisture content in a manner consistent with that employed in NUREG 0016. With a design condenser air in-leakage of 30 scfm, and above adsorption coefficients this system provides a design delay of 32 hours for krypton and 23.7 days for xenon. Since the expected condenser in-leakaqe is belov the design value, the actual delay times should be several times longer than the design delay times. Table 11.3-1 lists isotopic activities at the discharge of the turbine buildinq exhaust vent. After passing thru the recombiner section, the, off qas stream consists primarily of the air in-leakage from the main condenser. The air in-leakage design basis is conservatively assumed at 30 scfm. The Sixth Edition of the Heat Exchange Institute Standards for Steam Surface Condensers (Ref 11.3-4, paraqraph 5.16(c) (2)) indicates that with certain conditions of stable operation and suitahle construction, noncondensibles should not exceed 6 scfm for larqe condensers. Dresden-2, Fukushima-1, Tsuruqa, and KRB have all operated at 6 scfm or less. Re v. 30, 5/82 11. 3-5
SSES-FSAR 11.3.2.2 Com onent Descri tion 11.3.2.2.1 Recombiner S stem The offgas treatment system is divided into two sections to facilitate plant arrangement: the recombiner system and the charcoal offgas system. Three recombiner assemblies are located in the turbine building in a shielded area below the main condenser steam jet air ejectors. Each recombiner assembly consists of the following major components: a recombiner preheater, recombiner vessel, recombiner condenser, motive steam jet, motive steam jet condenser and a condensate cooler. One recombiner assembly is primarily designated for the service of each nuclear unit and the third assembly is a common standby to both units. Each recombiner assembly is sized to accommodate the design flow from one nuclear unit. The piping and valve manifold upstream of the recombiner assemblies permit the transfer of the offgas stream between a unit designated assembly and the common standby recombiner assembly. The materials of construction, design. pressures and temperatures, and the design codes for the components associated with the recombiner assemblies are listed in Table 11.3-5. 11.3.2.2.2 Charcoal Off as S stem After the radiolytic hydrogen and oxygen have been removed from the process stream by the recombiner assembly, the .remaining gas enters a delay line which is approximately 600 ft in length and varies in size from 8 to 16 in . The purpose of this delay line is to permit the large quantity of N-16 to decay to a reasonable activity concentration prior to entering the charcoal adsorption portion of the offgas system. Although there is a separate delay line for each recombiner assembly, these lines are joined into a single common header in the radwaste building . However, the process offgas stream from each unit is segregated by the use of isolation valves that are installed in this common header. After entering the common inlet header, the gas mixture from each unit can be directed to either of two parallel equipment subtrains consisting each of a water removal/temperature reduction assembly, and a charcoal guard bed. The utilized charcoal adsorption train of each offgas treatment system is primarily designated for the service of the associated nuclear unit. Each adsorption train consists of five charcoal adsorber beds in series. The trains and subtrains are isolable at both the inlet and outlet by remotely operated valves. The following Rev. 33, 4/83 11.3-6
SS ES- PS AH 12 .2- - RADIATION SOURCES Xn this section the sources of radiation that form the basis for shield desiqn calculations and the sources of airborne radioactivity required for the design of personnel protective measures and for dose assessment are discussed and identified. 12.2. 1 CONTAr NHD SOVRCZS The shieldinq design source terms are based on a noble gas fission product release rate of 0.1 Ci/sec (after 30 minutes decay) and the correspondinq fission, activation, and corrosion product concentrations in the primary coolant. The sources in the primary coolant are discussed in Section 11.1 and listed in Tables 11.1-1 through 11.1-5. Throughout most of the primary coolant system, activation products, prin" ipally nitrogen-16, are the primary radiation sources for shielding design. Por all systems transportinq radioactive materials, conservative allowance is made for transit decay, while at the same time providinq for dauqhter produ"t formation. Basic reactor data and core reqion description used for this section are listed in Tables 12.2-1 through 12. 2-5. ln this subsection the desiqn sources are presented by building location and system. General locations of the equipment discussed in this section are shown on the shielding and zoning drawinqs, Figures 12.3-8 throuqh 12.3-27. Detailed data on sour"e des"riptions for each shielie9. plant area are presented in Tables 12.2-38 throuqh 12.2-40. Shiel.ding source terms presented in this section and associated tables are based on conservative assumptions regarding system and equipment operations and characteristics to provide reasonably conservative radioactivity concentrations for shielding design. Therefore, the shielding source terms are not intended to approximate the actual system design radioactivity concentrations. Rev. 29, 3/82 12 2-1
SS ES-PS AR 12 2. 1.1 Dcvwell 12 2.-1.:I 1.. Reactor Core The primary radiations within the drywell ducing full power operation are neutron and gamma radiation resultinq from the fission process in the core. Tables 12.2-4 and 12.2-5 list'he multiqroup neutron and qamma ray fluxes at the outside surfaces of the reactor pressure vessel and the primacy shield at the core midplane. The qamma fluxes include those resulting from capture or inelastic scattering of neutrons within the reactor pressure vessel and core shroud and the gamma radiation resulting from prompt fission and fission product decay. The largest radiation sources after reactor shutdown are the decayinq fission products in the fuel. Table 12.2-9 lists the core qamma sources as a function of shutdown time. Secondary sources are the structural material activation of the RPV, its internals, and the pipinq and equipment located in the primary containment and also the activated corrosion products accumulated or deposited in the internals of the RPV, the primary coolant pipinq, and other process system piping in the primary conta inment.
- 12. 2. 1. 1.2 Reactor Coolant Svstem
~
Sources of radiation in the reactor coolant system are fission products estimated to be released from fuel and activation and corrosion products that are circulated in the reactor coolant. These sources are listed in Tables 11.1-1 thru 11.1-5 and their bases are discussed in Section 11.1. The nitrogen-16 concentration in the reactor coolant is assumed to be of coolant at the reactor re"irculation outlet nozzle. 61'i/gm
- 12. 2. 1.-1.3. Primary- Steam. System Radiation sources in the primary steam system piping include activation gases, principally nitrogen-16, and the corrosion and fission products carried over to the steam system.
The nitrogen-16 concentration in the main steam is assumed to be 100 p Ci/gm of steam leaving the reactoc vessel at the main steam outlet nozzle. Fission product activity corresponds to an offgas release rate of 100 000'i/sec at 30 minutes delay from the
~
reactor steam nozzle. Partition fractions for activity into the Rev. 29, 3/82 1 2w 2 2
SS ES- PS AR 12.3-1.3 Radiation. Zoning and Access Control Access to areas inside the plant structures and plant yards is requlated and controlled. Each radiation zone defines the radiation level range to which the aggregate of all contributing sources must be attenuated by shielding. All plant areas are categorized into radiation zones according to expected radiation levels and anticipated personnel occupancy, with consi'deration qiven toward maintaininq personnel external exposures ALARA and within the standards of 10CPR20. Each zoom, corridor, and pipeway of every plant building is evaluated for potential radiation sources during normal operation and shutdown; for maintenance occupancy requirements, and for general access requirements to determine appropriate zoninq. Radiation zone categories used and their descriptions are given in Table 12. 3-1 and the specific zoninq for each plant area is shown on Figures 12.3-8 thzouqh 12.3-27. All frequently accessed areas, ie, corridors, are shielded for Zone I and Zone II access. The control of ingress or eqress of plant operating personnel to controlled access areas and procedures employed to ensure that radiation levels and allowable working time are within the limits prescribed hy 10CFR20 as described in Section 12. 5. 1$ .3. 1.4 Contgol of Activated Coggosion Products In order to minimize the radiation exposure associated with the deposition of activated corrosion products in reactor coolant and auxiliary systems, the followinq steps have been taken: (1) The reactor coolant system consists mainly of austenitic stainless steel, carbon steel and low alloy steel components. Nickel content of these materials is low, and controlled in accordance with applicable ASME it is material specifications. A small amount of nickel base material (Inconel 600) is employed in the reactor vessel internal components. Inconel 600 is required where components are attached to the reactor vessel shell and the coefficient of expansion must match the thermal expansion characteristics of the low alloy vessel steel. Inconel 600 was selected because proper thermal expansion characteristics, it provides the adequate corrosion resistance and can be readily fabricated and welded. (2) Materials employed in the reactor coolant system are purchased to ASME material specification reguirements. No Rev. 3 0, 5/82 12w37
SSES-PSAR special controls on levels of cobalt impurities are specified. (3) Hardfacinq and wear materials having a high percentage of cobalt are restricted to applications where no satisfactory alternate materials are available. Studies currently are being made to determine whether, any alternate low cobalt alloys are satisfactory for lonq term use in nuclear reactor applications. To date, no satisfactory replacement materials have been found. (4) A high temperature filtration system was not employed in the Reactor Mater Clean-up System. The reasons for this included:
- a. Lack of quantitative data on the removal efficiency for insoluble cobalt by the hiqh temperature filter; b Uncertainty in the deposition model including the relative effectiveness of cobalt removal on deposition rate; co Doubtful cost-effectiveness in an area where other methods under study (such as decontamination) may prove better at reducing dose rates while also being more cost-ef fective.
(5) Items 1, 2 and 3 above also apply to valve materials in
~
contact with reactor coolant. Ualve packing materials are selected primarily for their properties in the particular environment. (6) Subsections 12. 1. 2.2, 12.3 1. 1, and, 12.3.1.2 describe the various flushinq, draining, testing, and chemical addition connections which have been incorporated into the 'design of piping and equipment which handle radioactive materials. decontamination is to be performed, these connections would If be used for that purpose. (7} The plant is desiqned with a 1% mixed resin, a pressure ! precoat clean-up system for the primary coolant in the reactor and a full flow deep'bed condensate demineralizer system for the feedwater. See Piqures 10.4-2, 10.4-3, 5. 4-16 a nd 5. 4-.18. 12,3,2 SH XELDING In this subsection the bases for the nuclear radiation shielding and the shielding configurations are discussed. Rev. 30, 5/82 12 3-8
SSES-PS AR 12 3. P.1 Design gbgectives The basic objective of the plant radiation shielding is to reduce personnel exposures, in conjunction with a program of controlled personnel access to and occupancy of radiation areas, to levels that are within the dose requlations of 10CPR50 and are as low as reasonably achievable (ALARA) within the dose regulations of 10CFH20. Shieldinq and equipment layout and design are considered in ensuring that exposures are kept ALARA during ahticipated personnel activities in areas of the plant containing radioact ive materials,. Basic plant conditions considered in the nuclear radiation shieldinq design are normal operation at full-power, and plant shutdown. The shielding design objectives for the plant during normal operation, including anticipated operational occurrences, and for shutdown operations are: a) To ensure that radiation exposure to plant operating personnel, contractors, administrators, visitors, and proximate site boundary occupants are ALARA and within the limits of 10CPR20 b) To ensure sufficient personnel access and occupancy time to allow normal anticipated maintenance, inspection, and safety related operations required for each plant equipment and instrumentation area') To reduce potential equipment neutron activation and mitiqate the possibility of radiation damaqe to materials d) To sufficiently shield the control room so that the direct dose plus the inhalation dose (calculated in Chapter 15) in the event of design basis accidents will not exceed the limits of 10CPR50, Appendix A, General Design Criterion 19. 12 3. 2. 2 General Shieldina Desian Shieldinq is provided to attenuate direct radiation through walls and penetrat'ions and scattered radiation to less than the upper limit of the radiation zone for each area shown in Pigures 12.3-8 throuqh 12.3-27. The minimum shielding requirements (see Subsection 12.3.2.3) for all plant areas are presented on those scaled layout drawings. General locations of the plant areas and Rev. 30, 5/82 12. 3-9
SS ZS-FS AR equipment discussed in this -subsection are also shown on those drawings. The material used for most of the plant shielding is ordinary concrete with a minimum bulk density of 105 lb/ft~. Whenever poured-in-place concrete has been replaced by concrete blocks or other material, desiqn ensures protection on an equivalent shieldinq basis as determined by the characteristics of the concrete block selected Compliance of concrete radiation shield design with Regulatory Guide 1.69 is discussed in Section 3. 13. Water is used as the*'pr'imary shield material for areas above the spent fuel transfer and storage areas. Special features employed to maintain radiation exposures ALARA in routinely occupied areas such as valve operating stations and sample stations are described in Subsections 12.3. 1.1 and 12 3. 1. 2. 12,3,2,2,1 Reacts Building Shieldincn Design Durinq reactor operation, the steel-lined, reinforced concrete dryvell wall and the reactor building valls protect personnel occupying ad jacent plant str'uctures and yard areas from radiation oriqinatinq in the reactor vessel and associated eguipment within the reactor building. The reactor vessel shield vali, dryvell wall, and various equipment compartment valls together with the reactor building valls minimize the radiation levels outside the reactor building. Where personnel and equipment hatches or penetrations pass through the dryvell wall, additional shielding is designed to attenuate the radiation to below the required level defined by the radiation zone outside the dryvell va11 during normal operation and shutdown and to acceptable emergency levels as defined by 10CFR50 during design basis accidents. 12 3,2,2,2 Reactor Building Integiog Shielding Design
\
Tnside Dryvell Stgucture: Areas within the drywell are designed as Zone V areas and are normally inaccessible during plant operation. The reactor vessel shield provides shielding for access in the dryvell during shutdown, and reduces the activation of and radiation damage to dryvell eguipment and materials. Outside Drywel+Structuge: The dryvell wall is designed to reduce radiation levels in normally occupied areas of the reactor building from sources vithin the dryvell to less than the maximum level for Zone IX. Rev. 3 0, 5/82 12 3-10
SS ES- PS AR Penetrations and hatch openinqs in the drywell wall are shielded, as necessary, to meet adjacent area radiation zoninq levels. Shieldinq requirements for the personnel, eguipment, and CRD removal hatch openings are shown on Figure 12.3-19 in the areas numbered 412 ~ 413, and 402, respectively. Drywell piping and electrical penetrations are shielded by providing either local shields within the penetration assembly or a shielded penetration room. Shielded piping penetration room locations and bulk shieldinq requirements are shown on Figures 12.3-18 through 12.3-
- 20. These rooms, numbered 202, 204, 205; 403, 411, 501, 504, 506, 515; are desiqnated radiation Zone V during reactor power operation and are provided with personnel access controls.
Electrical penetrations which are not located within these rooms are provided with supplementary local shielding as needed to meet outside zoninq levels. Six inches of lead, in addition to the self-shielding by the electrical cables, is furnished in each electrical penetration assembly to attenuate drywell radiation so urces& The components of the reactor water cleanup (RRCU) system described in Section 5.5 are located in shielded compartments which are desiqned as Zone V restricted access areas. is provided for each piece of equipment in the RWCU systemShielding
~
consistent with its postulated maximum activity Subsection 12.2. 1 and with the access and -zoninq requirements of the adjacent areas. This equipment includes: a) Regenerative heat exchanger h) Nonreqenerative heat exchanger c) RHCU pumps and pipinq d) RWCU filter demineralizers and holdup pumps e) RWCU backwash receiving tank and piping. The traversing in-core probe (TIP) system is located inside a shielded compartment to protect personnel from the neutron activated portion of the TIP cable. Naia steamlines are located within shielded structures from the drywell wall to the reactor building wall. Spent fuel is a primary source of r adiation during re fueling. Because of the extremely high activity of the f ission products contained in the spent fuel assemblies and the proximity of Zone II areas, shieldinq is provided for areas surrounding the fuel transfer canal and pool to ensure that radiation levels remain below zone levels specified for adjacent areas. Rev. 30, 5/82 12. 3-11
After reactor shutdown, the Residual Heat Removal (RHR) System pumps and heat exchanqers are in operation to remove heat from the reactor water. It is anticipated that the radiation levels in the vicinity of this equipment will temporarily reach Zone V levels due to corrosion and fission products in the reactor water. Shielding is designed to attentuate radiation from RHR equipment during shutdown coolinq operations to levels consistent with the radiation zoninq requirements of adjacent areas. Adequate shielding will also be provided to maintain radiation zoning requirements during hot standby operation of the RHR syste m. During functional testinq operations of the Reactor Core Isolation Cooling (RCIC) System and the High Pressure Coolant In j~ction (HPCI), the steam driven turbine and the inlet and exhaust pipinq are shielded consistent with the maximum steam activities in the lines and the access zone requirements of surrounding areas. The concrete shield walls surro'undinq the spent fuel cask loadinq, storaqe, and transfer areas, as well as the shield walls surrounding the fuel transfer and storage areas, are designed to provide Zone the shield walls. II maximum dose rates in accessible areas outside of Mater in the spent fuel pool provides shieldinq above the spent fuel transfer and storaqe areas. Direct radiation levels at the fuel handlinq equipment are calculated to be less than 2.5 mrem/hr from spent fuel during normal operations. Water is also used as shielding material above the steam dryer and. separator storage area. Concrete walls and water in the pool are designed to provide Zone II dose rates in adjacent accessible areas during storage of the dryer and separator. The Fuel Pool Coolinq and Cleanup (EPCC) System (see Section 9.1.3) shieldinq is based on the maximum activity discussed in Subsection 12.2.1 and the access and zoning reguirements of ad jacent areas. Equipment in the PPCC system to be shielded includes the PPCC heat exchangers, pumps and piping, filter demineralizers, and backwash recdiving tank. Shieldinq is provided as necessary around the following equipment in the radwaste building to ensure that the radiation zone and access requirements are met for surrounding areas. a) Laundry drain tank and pumps Rev. 30, 5/82 12 3-12
SSES-PSAR b) Chemical waste tank and pumps c) Radwaste evaporators d) Radwaste evaporator tanks and pumps e) Liquid radwaste collection tanks and pumps f) Liquid radwaste surge tanks q) Liquid radwaste sample tanks and pumps h) Reactor water cleanup phase separator and pumps i) Waste sludqe phase separator and pumps I g) Spent resin tank k) Waste filling and capping station
- 1) Waste liner transfer and storaqe areas m) Liquid radwaste demineralizer and piping n) Waste mixing tanks o) Liquid radwaste filters p) Gaseous radwaste eguipment.
12.g,2,2.4 Tughiye Building Shielding Design Radiation shielding is provided around the following equipment in the turbine buildinq to ensure that zone access requirements (Figures 12.3-10 through 12.3-15) are met for the following surroundinq areas: a) Condensate filter demineralizers and piping b) Regeneration waste surge tanks and pumps c) Chemical waste neutralizinq tanks and pumps d) Reactor feed pump turbines and piping e) Condensate pumps and piping f) Main condensers and hotwell g) Mechanical vacuum pump Rev. 30, 5/82 1 2w 3 1 3
SSES-FSAR h) Recombiners and pipinq i) Steam packing exhauster g) Condensate demineralizer resin regeneration tanks k) Air egectors and gland steam condensers
- 1) Peedwater heaters, heater drains, and piping m) Main steam piping n) Steam seal evaporator and drain tank o) Moisture separator and drain tanks p) Hiqh pressure and low pressure turbines q) Offgas piping.
Areas within most of these shield walls have high radiation levels and limited access. 12.3.2.2 5 Cggtgog gong Shgeldipg Design Figures 12.3-9 and 12.3-28 represent layout and isometric drawings of the control room, showing its relationship to the reactor building. The design basis loss-of-coolant accident (LOCA) dictates the shieldinq requirements for the control room. Shielding is provided to permit access and occupancy of the control room under LOCA conditions with radiation doses limited to 5 rem whole body from all contributing modes of exposure for the duration of the accident, in accordance with 10CPR50 Appendix A, General Design Criterion 19. The desiqn basis LOCA is described in Subsection 15.1. 13 and is based on Regulatory Guide 1.3. Th'e direct radiation from airborne fission products inside the reactor building would contribute less than 361 mrem to personnel inside the control room for the 30-day period followinq the LOCA, based on radioactivity sources described in Subsection 12. 2. 1. 6.. The parameters used in the demonstration of the control room habitability are listed below and in Regulatory Guide 1.3. {The ventilation system parameters are listed in Subsection 12. 3.3). Rev. 30, 5/82 12 3-10
SSES-FSAR For all isotopes that escape from the drywell to the reactor building, no credit is taken for shielding by the internal structures in the reactor buildinq. Shielding credit is taken for the reactor and control building walls. For all isotopes that remain within the drywell, shielding credit is taken for the drywell wall. 1g.3 2.P,6 Diesel Gene@atop Building Shielding Design There are no radiation sources in the diesel generator building; therefore, no shielding is required for the building. 12.3. 2.2.7 Higcellaneoug Plant Areas agd Plant Yard Areas Sufficient shieldinq is provided for all plant buildings containinq radiation sources so that radiation levels at accessible areas outside buildings are minimized. Plant yard areas which are frequently occupied by plant personnel are accessible during normal operation and shutdown. Some operations, such as loadinq solidified waste into shield casks, require access restrictions in adjacent areas. These areas are surrounded by a security fence and closed off from areas accessible to the general public. 12.3. 2.2.8 Countina Room Shieldina Because the countinq room contains sensitive instruments to radioactivity measurements, it is imperative that .the background radiation levels are minimized. To accomplish this, no flyash was used in the concrete mix for the walls and slabs surrounding the countinq room. Flyash normally contains a relatively large amount of slow decaying radioactive isotopes. 1n addition, the shield walls and slabs were sized to maintain a background radiation level of less than 130 mrem/year .for anticipated operational occurrences and 45 mrem/year for normal operation. 12.3. 2.3 Shielding Calcula~ional methods The shieldinq thicknesses provided to ensure compliance with plant radiation zoning and to minimize plant personnel exposure are based on maximum equipment activities under the plant operatina conditions described in Subsection,12.2.1. The thickness of each shield wall surrounding radioactive equipment is determined by approximating as closely as possible the actual Re v. 30, 5/82 12 3-15
SSZS-PS AR geometry and physical condition of the source oz sources. The isotopic concentrations are converted to energy group sources using data from standard Refs 12.3-1 through 12.3-5. The geometric model assumed for shielding evaluation of tanks, heat exchangers, filters, demineralizers, and evaporators is a finite cylindrical volume source. Por shielding evaluation of pipinq, the geometric model is a finite shielded cylinder. In cases where radioactive materials are deposited on surfaces such as pipe, the latter is treated as an annular cylindrical surface source. Typical computer codes that are used for shielding analysis are listed in Table 12.3-2. 'hielding attenuation data used in those codes include gamma class attenuation coefficients (Ref. 12.3-6), gamma buildup factors (Ref. 12.3-7), neutron-gamma multiqroup cross sections (Ref. 12. 3-20), and albedos (Ref. 12. 3-
- 12) .
The shieldinq thicknesses are selected to reduce the aggregate computed radiation level from all contributing sources below the upper limit of the radiation zone specif ied for each plant area. Shielding requirements are evaluated at the point of maximum radiation dose through any wall. Therefore, the actual anticipated radiation levels in the greater region of each plant area is less than this maximum dose and therefore less than the radiation zone upper limit. Where shielded entryways to compartments containing high radiation sources are necessary, labyrinths or mazes are desiqned usinq a qeneral purpose qamma-ray scattering code G-33 (Ref. 12.3-11) . The mazes are constructed so that the scattered dose rate plus the transmitted dose rate through the shield wall from all contributinq sources is below the upper limit of the radiation zone specified for each plant area. 12 3 3 VENTILATION The plant heatinq, ventilating, and air conditioning (HVAC) systems are designed to provide a suitable environment for personnel and equipment during normal operation and anticipated operational occurzences. Parts of the plant HVAC systems perform safety related functions. 12.3. 3 1 Design Objectives The systems are designed to operate such that the in-plant airborne activity levels for normal operation (including anticipated operational occurrences) in the general personnel access areas are within the limits of 10CPR20. The systems Rev. 30, 5/82 12. 3-16
SSES-PSAR operate to reduce the spread of airborne radioactivity during normal and anticipated abnormal operating conditions. During post accident conditions the ventilation system for the plant control room provides a suitable environment for personnel and equipment and ensures continuous occupancy in this area. The plant ventilation systems are designed to comply with the airborne radioactivity release limits for offsite areas during normal operation.
- 12. 3. 3. 7 Design Critegia Design criteria for the plant HVAC systems include the folloving:
a) During normal operation and anticipated operational occurrences, the average and maximum airborne radioactivity levels to which plant personnel are exposed in restricted areas of the plant is ALARA and within the limits specified in 10CPR20. The average and maximum airborne radioactivity levels in unrestricted areas of the plant during normal operation and anticipated operational occurrences vill be ALARA and within the limits of Appendix B, Table II of 10CPR20. b) During normal operation and anticipated operational occurrences, the dose from concentrations of airborne radioactive material in unrestricted areas beyond the site boundary will be ALABA and vithin the limits speci fied in 10C PR 20 and 1 OC FR50. c) The plant siting dose guidelines of 10CPR100 vill be satisfied following those hypothetical accidents, described in Chapter 15, which involve a release of radioactivity from the plant. d) The dose to control room personnel shall not exceed the limits specified in General Design Criterion 19 of Appendix A to 10CPR50 following those hypothetical accidents, described in Chapter 15, which involve a release of radioactivity from the plant. 12 3. 3.3 Desian Guidelines In order to accomplish the design objectives, the following guidelines are followed wherever practicable. Rev. 30, 5/82 1 2w 3 1 7
SS ES-PS AEt
- 12. 3. 3.3. 1 Guidelines to djni~mse Rirbonne Radioact~ivit a) Access control and traffic patterns are considered in the basic plant layout to minimize the spread of contamination.
Equipment vents and drains are piped directly to a collection device connected to the collection system instead of allowing any contaminated fluid to flow across the floor to the floor drain. c) All-welded piping systems are used on contaminated systems to the maximum extent practicable to reduce system leakage. If welded piping systems are not used, drip trays are provided at the points of potential leakaqe. Drains from drip trays are piped directly to the collection system The valves in some systems are provided with leak-off connections piped directly to the collection system. Suitable coatinqs are applied to the concrete floors of potentially contaminated areas to facilitate decontamination. Where practicable, metal diaphragm or bellows seat valves are used on those systems where essentially no leakage can be to1erated. q) Contaminated equipment has design features that minimize the potential for airborne contamination during maintenance operations. These features may include flush connections on pump casings for draining and flushing the pump prior to maintenance or flush connections on piping systems that could become highly radioactive. h) Exhaust hoods are used in plant areas to facilitate processing of radioactive samples by drawing contaminants away from the personnel breathing areas and il into the ventilation and f ter ing syste ms. Equipment decontamination facilities are ventilated to ensure control of released contamination and minimize personnel exposure and the spread of contamination. 'Bev. 30, 5/82 12.3-18
SS ES-PS AR Accuracy: The overall accuracy within the design range of temperature, humidity, line voltage, and line frequency variation should be such that the actual reading relative to the true readinq, iacludinq susceptibility and energy dependence (100 Key to 3 HeV), should be within 9.5 percent of equivalent linear full scale recorder output for any decade. Beproducihilitg: At desiqn center the reading shall be reproducible within 110 percent of point with constant geometry. Pnvironmenta1 Con)it joys Sensor Location Control Boom Design Design Parameter Center= ~a~ne ~ Center /ange Tempera ture 25 0 to 60 25 5 to 50 (degrees C) Relative 50 20 to 100 50 20 to 90 Humidity (Percent) 1Q 3.0.1 2 Criteria for Location of Area monitors Generally, area radiation monitors are provided in areas to which personnel normally have access and for which there is a potential for personnel unknowingly to receive high radiation doses (e g., in excess of 10CPR20 limits) in a short period of -time because of system failure or improper personnel action. Any plant area that meets one or more of the following criteria is monitored: a) Zone I areas which, during normal plant operation, including refueling, could exceed the radiation limit of 0.5 mremfhr upon system failure or personnel error or which will be continuously occupied following an accident requiring plant shutdown b) Zone II areas where personnel could otherwise unknowinqly receive h iqh levels of radiation exposure due to system failure or personnel error c) Area monitors are in accordance with General Design Criterion 63 of 10CPR50 Appendix A. Rev. 30, 5/82 12&323
SSES-PS AH 1 2. 3. 4. 1 . 3 sgngem.gedciimt jon pa~en Radiation Moni~torin General The area radiation monitorinq system is shovn in diagram form in Figure 12.3-29. Each channel consists of a combined sensor/converter unit, a local auxiliary unit (readout with visual and audible alarm), a combined indicator/trip unit, a shared power supply, and a shared multipoint recorder. The location of each area radiation detector is indicated on the shielding and zoninq dravinqs, Figures 12.3-8 through 12.3-27, and is listed in Table 12.3-7.'ircuit Descri2tion I Sensorgconverteg: Each sensor/converter contains all silicon semiconductors in sealed enclosure with a Cooke-Yarborough courtyard circuit vhich combines a long integrating time constant at low radiation levels with fast overall response at high radiation levels. Auxiliary Unit= Each auxiliary unit gives instant local readout at the senso location with a visual alarm. An audible alarm is connected to the auxiliary unit to alert personnel of excessive area radiation. Indicator and Trip Unit: The indicator and trip unit provides channel control for the area r adiation monitoring system. Its circuitry provides an upscale trip that indicates trouble high radiation and a downscale trip that may indicate instrument or loss of power. The module has an a nalog readout, a low and high trip indicatinq light, trip a test device, an alarm reset and an output for a multipoint record er. Ranges and 'Sensitivity: Ranqes and sensitivities are selected for each location based on the anticipated radiation level as provided by experimental measurements of levels in similar plants and shieldinq calculations. Refer to Table 12. 3-7 for detail. Accuracy: The overall accuracy is such that the actual reading relative to the true reading is vithin a7.5 percent of equivalent full scale.
- 12. . 4 1.4 Area Radiation Monitorina Instrumentation Power- Sources: The power source for the area radiation monitoring system is the 120 V ac instrument bus and local lightinq panels. The area radiation monitor instrumentation is povered by a high and lov voltage electrically regulated power Rev. 30, 5/82 12 3-24
SS ES- FS AR supply capable of handlinq up,to 10 channels. The system has no e merqenc y po we r s up pl y. Alarm Se t Points: Refer to Table 12. 3-7. Recording Devices: Two multipoint recorders are located in the control room for recording channels pertaining to Unit 1, Unit 2, and channels which are common to both units. This data is also stored in computer history files and can be retrieved and printed using the PMS Historical Recording service program. Location of Devices: Refer to details in Table 12.3-'7. Readouts and Alarms: Readouts, visual and audible alarms are provided locally for each monitorinq channel. Readouts and visual alarms are provided by each indicator/trip unit in the Control Structure (Upper Relay Room). Multipoint recorders, visual alarms and PMS displays are provided in the Control Structure (Control Room), with the exception of the three Technical Support Center channels (43, 44, 45) . The followinq annunciators are located in the main control room to alert the operator:
\
a Reactor Building Area Hiqh Radiation (Units 1 and 2) b Turbine Building Area High Radiation (Units 1 and 2) c Radwaste Building Area Hiqh Radiation d Befuelinq Floor Area Hiqh Radiation (Units 1 and 2} e Spent Fuel Pool Area Hiqh Radiation (Units 1 and 2) f Reactor Buildinq Common Area High Radiation q Administration Buildinq Area High Radiation h Cont ol Structure Area High Radiation i Area Radiation Monitorinq Downscale (ganged for all channels) 12.3.4.1.5 Safety Evaluation The area radiation monitoring system is designed to operate unattended for extended periods and is designed for high reliability. Failure of one monitor has no effect on any other. The system is not essential for safe shutdown of the plant, and serves no active emergency function during operation. The system Rev. 32, 12/82 1 2 3-25
SSES-PS AR is not safety related and is constructed to Quality Group D R equi rem en ts.
- 12. 3. 4. 1. 6 Calibration getho d and Testability Pacilities for calibrating these monitor units are provided, which include a test unit designed for use in the adjustment procedure for the area radiation monitor sensor and converter unit. These provide several qamma radiation levels between 1 and 250 m rem/h r.
A cavity in the calibration unit receives the sensor and converter unit. A window through which radiation from the source emanates is located on the back wall of the cylindrical lower half of the cavity. A chart on each calibration unit indicates the radiation levels available from the unit for the various control settings. An internal trip test circuit, adjustable over the full range of the trip circuit, is provided. The test signal is fed into the indicator and trip unit input so that a meter reading is provided in addition to a'real trip. All trip circuits are the latching type and must be manually reset in the Upper Relay Room. The radiation monitors will be calibrated at regular time intervals in accordance with station procedures'. 12.3.4.2 Airborne Radioactivitiy Nonitorina Refer to Subsections 12. 5.2.6.3 and 12. 5. 3. 5.4 for information on air borne radioactivity monitorinq. 12 3- 5 REFERENCES u4 Blichert-Tof t, Nuclear s w 12-3-1 J.J. Hartin and P. H. Data Tables "Radioactive Atoms, Auger Electrons, and X-Ray Data", Academic Press, October, 1970. 12& 3-2 J.J. Hartin, Radioactive Atoms Supplement 1, ORNL 4923, Auqust, 1973.
- 12. 3-3 W. W. Bowman and K. W. HacHurdo, Atomic Data and Nuclear Data Tables "Radioactive Decay's Ordered by Energy and Nuclide", Academic Press, Pebruary, 1970.~
Rev. 32, 12/82 12 3-26
SSES-FS AR
- 12. 3-4 M. E. Neck and R. S. Gilbert, >>Summary of X-ray and Gamma Fnergy and Intensity Data", NED0-12037, January, 1970.
- 12. 3-5 C. N. Lederer et al, Table of Isotopes, Lawrence
~
Radiation Laboratory, University of California, March, 1968
- 12. 3-6 G Q. Goldstein, X-ray Attenuation Coef ficients f rom 10 KeV to 100 NeV, National Bureau of Standards Circular 583 (Issued April 30, 1957).
- 12. 3-7 D~K Trubey, >>A Survey of Empirical Functions Used to Fit Gamma-Ray Buildup Factors>>, ORNL-RSIC-10, February, 1966.
12 3-8 N.M. Engle, Jr., "A User's Manual for ANISN: A One Dimensional Discrete Ordinates Transport Code with Anisotropic Scattering>>, Union Carbide Corporation, Report No. K-1693 g 1967.
- 12. 3-9 R. E. Nalenf ant, OAD, A Series of Point-Kernel General-Purpose Shieldinq Programs, Los Alamos Scientific Laboratory, LA 3573, October, 1966.
- 12. 3- 10 E. D. Arnold and B. F. Maskewitz, >>SDC, A Shieldinq-Design Calculation for Fuel-Handling Facilities ORNL-3041 March, 1966.
12 3-11 R.E. Malenfant, >>G~: A General Purpose Gamma-Ray Scattering Program>>, Los Alamos Scientific Laboratory, LA 5176, June, 1973. 12 3- 12 R. E. Selph>>Neutron and Gamma Ray Albedos>> ORNL-RSZC-21, February, 1968. 12m 3 13 D. S. Duncan and A. B. Spear, Grace I - An IBM 704-709 Program presign fog Computing Gamma Rgy Attenuation and Heat ing in Reactor Shields, Atomics 'International (June, 1959) . 12 3-14 D.S. Duncan and A.B. Spear, Grace II An IBM 709 Proaram for Comnutina Gamma Rav Attenuation and Heatina in Cylindrical and gpherical Geometries, Atomics International (November, 1959) .
- 12. 3-15 D.A. Klopp, NAP Nultigroup Time-Dependent Neutron Activatjon prediction Cope IITRI-A6088-21 (January 1966) 12 3-16 E. A. Straker, P. N. Stevens, D. C. Irving, and V. R.
Cain NORSE A Multigroup neutron and Gamma-Ray Nonte Carlo Transport Code, ORNL-4585 (September, 1970) . Rev. 32, 12/82 12. 3-27
SS ES-PS AR 12M317 N. A. Rhoades and F. R. Hynatt, The DOT XII Two-Dimenyiopal Qiscgefe Qrdinates Trgnspogt Code ORNL"TN-4280 (1973)-
- 12. 3- 18 U.S. ~ Nuclear Regulatory Commission, Regulatory Guide 8 8 (Jul'y, 1973) .
- 12. 3-19 H.J. Bell, "OQIGBN - The- ORNL Generation and Depletion Code", Oak Ridge National Laho'ratory, ORNL>>4628 (Hay, 1973)
- 12. 3-20 ORNL RSIC Computer Code Collection DLC-23 CASK 40 Croup geutgon and Gamma-Rag Cross Sygtion Data.
- 12. 3-21 R. G. Jaeqer, et al, Engineering Compendium on Radiation Shielding, Volume I, Springer Verlag, Neo York Inc.,
1968. Rev. 32, 12/82 12 3-28
TABLE 12. 3-7 AREA RADIATION HONITORIÃG SYSTEN UNIT 1 6 COHHON Page I Channel Honitor Description Bldg. Approx. Elev. Range Set Point No Loc. la R/h r) (n R/hr) chan 1 RX Bldg. BB T/22 645' 1-1000 100 Residual heat renoval area Chan 2 RX Bldg. RB T/21 645 ~ 0 01-100 2.5 RCIC punp turbine roon Chan 3 RX Bldq. RB S/21 64 5 ~ 0 01- 100 2.5 HPCI punp turbine .roon Chan 4 RX Bldq. BB S/28 645' 1-1000 15 Radvaste suap area Chan 5 RX Bldg RB R/21 719' 1-1000 15 Contr. rod drive Hvd. Units north Chan 6 RX Bldq. BB R/29 719 ~ 0 1-1000 15 Contr. rod drive Hvd. Units south Chan 7 Off-Gas TB G/25 656' 1-1000 200 BVpass Line Chan 8 RX Bldq.. BB R/21 74 9' 01- 100 2.5 Cleanup recirc. punp access area Chan 9 RX Bldq- RB tV27 719' 1-1000 2.5 CRD Repair Area 10 Chan 10 RX Bldg RB R/27 74 9' 1-1000 200 Puel pool punp roon Chan 11 RX Bldq. RB P/26 779 ~ 0 01-100 15 Sanple Station (1C210) Roon 12 Chan 12 BX Bldg RB U/27 799 ~ 0 01 100 15 Recirculation fan roon 13 Chan 13 RX Bldg. RB P/26 799' 01-100 2 5 Hev Puel Area Rev. 30, 5/82
TABLE 12.3-7 (Continued) AREA RADIATION MONITORING SYSTEM VNZT 1 8 CONNON Page 2 Channel Monitor Description Bldg.. approx. Elev. Range Sct Point No. Loc. (nR/hr) (n R/hr) 14 Chan 14 Spent RX Bldq. fuel pool RB S/27 8).8'. 1-1000 15 15 Chan 15 RX Bldq. RB P/22 81 8' 01-100 2-5 rcfuelinq floor area 16 Chan 16 RX Bldq. RB P/21 670' 01-100 2.5 Access to renote shutdoun panel 17 Chan 17 TB Bldq TB J/26 656' 01-100 50 condensate punps area 18 Chan 18 TB Bldq. TB L/21 676 ~ 0 01-100 2 5 RFPT area k Chan 19 TB Bldg. TB H/25 682' 1-1000 700 A,ir effector roon 20 Chan 20 TB Bldq- TB N/21 69 9 ~ 0 1-1000 200 Peedwater heater
.area 21 Chan 21 TB Reactor Bldq.
recirc TB M/20 729'. 01-100 2-5 punp N.G. area 22 Chan 22 TB Bldg. TB J/26 729' 01 100 2-5 generator bay area 23 Chan 23 TB Bldq TB L/23 762' 01-100 2 5 Heat and vent. equipnent roon 24 Chan 24 TB Bldg. TB K/15 72 9 ~ 0 01-100 2.5 Turbine front end 25 Chan 25 BX Bldg RB T/24 645' 1-1000 100 Residual heat renoval area 26 Chan 26 RX Bldg. RB Q/22 71 9' 1-1000 15 TIP drive area Rev. 30, 5/82
TABLE 12. 3-7 (Continued) AREA RADIATION HONITOBING SISTER UNIT 1 6 CONNON Pago 3 Channel Nonitor Description Bldq.. Approx. Elev. Range Set Point No. Loc. (aR/hr) (a R/hr) 27 'han 27 Adain. Bldg TB N/13 72 9' 01-100 2 5 Access (TB) 28 Chan 28 Adain Bldg ADft N/10 691' 01- 100 0 5 Access (RM) BLDG 29 Chan 29 RQ Bldg. RM K/3 64 6 s 0 1-10PP 2 5 Corridor pers. access area 30 Chan 30 RM Bldg. RM G/8 64 6' 1-1000 .2 5 Opt. surveillance control area 31 Chan 31 RQ Bldq. RM J/12 646 ~ 0~ 1-1000 2 5 Corridor to collection tank 32 Chan 32 RQ Bldq K/12 676 ~ 0 1-1000 2-5 controlled xone shop 33 Chan 33 Rtf Bldg. RM J/9 676' 1-1000 2-5 RM Control Roon Chan 34 BM Bldq. R'M G/6 676' 1-1000 2 5 Storaqe and equipaent area 35 Chan 35 RX Bldg. RB S/29 81 8 ~ 0 01- 100 15 Shippinq cask storage area 36 ~ Chan 36 RX Bldg. RB V/29 670 0. 01-100 0 5 Railroad access area 37 Chan 37 Ctr Ttfr. CTR K/27 806 ~ 0 01-100 0 5 standby qas TMR treataent roon 38 Chan .38 Ctr. Ttfr. CT R N/27 676 ~ 0 0 1-100 0 5 Rad. chea. TQR laboratory Rev. 30, 5/82
TABLE 12.3-7 (Continued) AREA RADIATION HONITORING SISTER UNIT 1 8 CONHON Page 4 Charm No+ 39 40 el NOnitOr Description chan 39 Control Ctr. Tvr. room Chan 40 Admin Bldg. Access Unit 2 Bldg.. CTR TMR TB Approx. Flev. Loc L/29 H/12 729 676'
'. ~
Range (mR/h r) 01- 100 01-100 Set Point (m R/hr) 0 5 0 5 (Railroad Bay) 41 Channel 41 RB P/22 71 9' 1-1000 200 Tip Chamber shield Area Channel 42 RB P/26 818 ~ 0 01-100 Refueling Floor Area 43 Channel 43 CTR L/30 741' 01-100 Observation Deck TNR Channel 44 CTR H/32 74 1 ~ 0 01-100 Document Control Area TMR 45 Channel 45 CTR H/26 74 1 I 0 01-100 Conference Roon TMR Rev. 30, 5/82
TABLE 12.3-7 (Continued) AREA RADIATIOH HONITORIHG SYSTEH UNIT 2 Page 5 Channel Honitor Description Bldg.. Approx. Elev. Range Set Point Ho Loc. tmR/hr) {a R/hr) Chan 1 RX Bldg. Residual heat RB T/31 645'. 1-1000 100 removal area Chan 2 RX Bldg. RB T/30 645' 1-1000 2.5 RCIC puap turbine roon Chan 3 RX Bldg. RB S/30 6'4 5~ 0 1-1000 2.5 HPCI pump and turbine room Chan 4 RX Bldg. RB S/36 645' 1-1000 15 Radvaste suan area Chan 5 RX Bldg. RB R/30 71 9' 1-1000 15 Contr. rod drive Hvd. Units north Chan 6 RX Bldg. RB R/37 71 9' 1-1000 15 Contr. rod drive south Chan 7 Off-Gas TB G/33 656' 1-1000 15 Bvpass Line Chan 8 RX Bldg. RB R/37 74 9 ~ 01-100 2.5 Cleanup recirc pump access area Chan 9 RX Bldg. RB 0/35 74 9' 1-1000 2.5 CRD Repair Area 10 Chan 10 RX Bldg. RB R/38 749' 1-1000 200 Fuel pool puap rooa Chan 11 RX Bldg. P/33 779 ~ 0 01-100 2 5 Sample Station (2C210) Room 12 Chan 12 Recirculation RB U/35 79 9 ~ 0 1-100 15 Pan Rooa 13 Cha n 13 RX Bldg. RB 0/31 799' 01-100 2.5 Nev Fuel Area Rev. 30, 5/82
TABLE 12.3-7 (Continued) AREA RADIATION NONITORING SYSTEN ONIT 2 Page 7 41 Channel 41 RB P/31 719' 1" 100 200 TIP Chamber Shield Area 42 Channel 42 RB P/34 818' 01-100 2.5 Refuelinq Ploor Area Note: All set points are estimated values. Actual set points may vary depending on operational considerations and vill be determined by measured radiation levels. Rev. 30, 5/82
SS ES- PS AR 13 2- - TRAINIHG PROGRAN 13 2. 1 PLANT. QE~~SO~~HEL TRAIN~IG. PROGRAH-The Training Program for the Susquehanna Steam Electric Station is formulated to develop and maintain an organization qualified to assume the responsibility for operation ~ maintenance, and technica 1 considerations for the facility. In order to accomplish these objectives and to provide the necessary control of the overall plan, three separate training programs listed below are utilized:
- a. Initial Plant Staff Training Program b Regualification Training Program, and
- c. Replacement Training The Initial Plant Staff Training Program is designed to produce competent, trained personnel at "all levels of the. plant organization. The programs 'are designed to allow placement of personnel into specific levels based on employee experience and intended position. F The Requalification Training Program provides continuing training for plant personnel commensurate with their area of responsibility.
The Replacement Training Program is designed to supply qualified personnel for the station organization. The Superintendent of Plant may waive portions of the training program for individuals based on their previous .experience and/or gualifications. 13.2. 1. 1 Pro@ram Descrint'ion. 4
- 13. 2. 1. 1 1 In jtia1 Plagt- Staf f Training-Figure 13.2-'1 shows the present schedule'for the various Initial Plant Traininq Programs. Should significant differences or chanqes occur in those courses not yet conducted, the appropriate course outline and description will be revised by amendment.
REV. 30, 5/82 1 3% 2 1
SS ES-FS AR 13.2. 1.1.2- Op~ea+ion~Section- Tgyininc{ Pgoggym-, This program i.s designed for. individuals vho. are to assume
- ~
responsibility'or the licensed and non licensed operator-positions and fulfills the general requirements and qualifications set forth 'in ANSX .,818.1-1971. The program is to allow personnel of varying experience and education 'tructured, to enter the Cold Licensing Traininq Progra~ at, various levels and still fulfill the eligibility reguirements for HRC-cold licensing prior to fuel 'loadinq. 13,2. 1,1 2 1 -Injti.al Cold~Lcense Tj aing~n E C The program is,desiqned for cold license candidates with no formal power plant experience or training. The prog-ram is divided into seven phases to ensure proper administration; documentation, and completeness of training. o Phase I Conventional Power Plant Operator- Experience Program. oo Phase II Personnel. Academic Program for Huclear Power, P1ant.. F oo Phase IXI Basic BMR Technology'o
- o. Phase IV BMR Simulator Training
- o. - Phase V BWR- Observation Training Phase VI Systems, Procedures and On'-The-Job 'Training
- o. Phase VII BMR Refresher, Training ',, l Those plant control operator license candidates with no power, plant experience will participate and qualify in all'seven while those with only a conventional power plant background will.,participate and, qual'ify in Phases II through VII..
'hases, Operators, and other staff members, who will be'old licensed with a nuclear background and/or related acadeiic or technical training will participate and qualify in selected portions of phases II through. VI and all of Phase VII. '-The 'exterit of their participation in Phases II through VI vill be based on, their background and documented, in station training records.
REV 30r 5/82 13&22
SS ES-PS AR o Phage= I Conventional Power Plant Experience P~ro ram The Conventional Pover Plant Experience Phase of the Susquehanna SES Traininq Proqram is desiqned to provide poser plant experience to those license candidates vho lack the minimum power plant experience requirements. This experience vill be provided prior to the start of the formal License Training Program {Phases II-VII), so that hy the time of the Nuclear Regulatory Commission-Licensing Examination, the candidate- vill have had tvo years of power plant experience of which a minimum of one year vill have been nuclear pover plant experience. This program is approximately one year in duration and includes supervised on-the-gob training in major, operator positions (excluding fossil boiler related positions) at a PPSL conventional power plant. Also included in the one year experience program are approximately ten weeks of formal classroom training which includes but is not limited to the following areas: Basic Power Plant Operation Steam Turbine Fundamentals Power Plant Mathematics Basic Thermodynamics and Fluid Hechanics Plant Cycle and Plant Performance Basic Electrical and Plant Instrumentation Basic Print Reading Basic Mater Chemistry Introduction to Nuclear .Power and Nuclear Plant Systems o Phase XI - gcgdem~cPgo~gam fog~uclear-Powe~Plant Personnel This course is conducted by the General Physics .Corporation of Columbia, Maryland. It is designed to refresh basic courses received in high school and to acquaint those personnel, vith little or no nuclear backqround, with nuclear phenomenon and The BWR concept as they apply to practical reactor technology. the course material and the approximate number of classroom hours allotted to each ma ]or topic are as follovs: REV 30, 5/82 13&23
SS BS-PS AR Subiect Classroom. H~ou s First Seqment Mathematics and Classical Physics 200 Review of Introductory Mathematics 16 Exponents and Logarithms 36 Algebra 64 Geometry and Triqonometry 24 Mathematics of Dynamic Systems 20 Classical Physics 40 Second Segment Physics 200 Atomic Physics 24 Nuclear Physics 60 Reactor Core Physics 68 Reactor Operations 48 Third Segment Related Technologies 200 Introduction to Nuclear Pover Plant Chemistry Systems
'828 Health Physics 56 Fundamentals of Electricity and Electronics 48 Nuclear Instrumentation 40 Fourth Segment Nuclear Pover Plant Technology 200 Theory and Application of Nuclear Pover Plant Systems 88 Physics Reviev 56 Overall Nuclear Power Plant Operations 56-800 Cold license applicants, with no previous nuclear experience, be assigned to a Research Reactor Training Course conducted by vill the Pennsylvania State University., This 2-week, course gives the student actual hands-on experience with an open pool nuclear reactor and allows the cold license applicant to obtain at least the minimum of 10 reactor startups necessary to establish cold license eliqibility requirements. The course includes, but is not limited to, the follovinq subject material=
0 Reactor Operations 0 Fuel Handlinq 0 Flux Mapping Normal Reactor Operation R EV 3 Og 5/82 13. 2-4
SS ES- PS AR o Instrumentation Effects o Control Rod Calibration o Laboratory Demonstrations, and o Control Transient Effects o Phase III---Basic. BMR Technoloav-The Basic BUR Technology course is desiqned to impart the details of the BMR nuclear'steam supply system to the operator trainees. The course consists of approximately 5 veeks of classroom lecture on BMR nuclear steam supply system components, fuel description, thermal-hydraulics, radiation monitoring and nuclear instrumentation system operations.'mportant interfaces vith the balance of plant systems are also taught. The lectures are presented by GE BQR Training personnel using conventional classroom techniques. Classes are scheduled for approxmately 7 hours per'ay and suggested study assignments are normally made daily. Progress is measured by veekly vritten and fin a 1 co m pre he nsi ve e xam ina tio ns. It is anticipated that the course material covered vill be as folio ws. Schedule changes and adjustments to course'ontent vill be made as necessary to meet the particular needs of the students Meek 1 Introduction to Course Plant Orientation Reactor Principles Review Reactor Vessel and Internals BWR Thermal Hydraulics Reviev Fuel Description Nuclear Boiler Instrumentation Week 2 Examination 1 Control .Rod Drive Mechanism Control Rod Drive Hydraulic System Rod Control and Information System Rod Pattern Control System Recirculation System Recirculation Plov Control System Reactor Water Cleanup System BE V. 30, 5/82 13. 2-5
SSES-PSAR Source. Range Nonitorinq System Intermediate Range Monitoring System Local Power Range Monitoring -System Averaqe Power Range Monitoring System Week 3 Examination 2 Traversing In-Core Probe System Main'team System Reactor Pressure Control (Electro-Hydraulic 'Cont'rpl) Feedwater Control System Reactor Protection Containment and Related Systems Introduction to Radvaste Systems(Off Gas, Liquid and Solid Radwaste)
'I Week 4 Examination 3 Introduction to Electrical Distribution Reactor Core Isolation System Introduction to Emergency Core Cooling'-System High Pressure Core Spray System Auto Depressurization System Low Pressure Core Spray Residual Heat Removal System and Hot Standby Operation Emergency Core Cooling Systems Integrated- Resp'onse
'Standby Liquid Control System Process Radiati'on Nonitorinq Area Radiation Monitoring Week 5 Examination 4 Performance Monitoring System BWR Materials BQR Chemistry Puel Pool Coolinq System Reactor Refueling Plant Operations Transient Analysis Review Final Examination REV. 30, 5/82 13. 2-6
SS ES-PS AR o Phase IV --BMR Simulator Trainina 4 The BMR simulator course is taught at the General Electric BMR Traininq Center, Norris, Illinois, and is designed to provide the operator trainee with the skills necessary to safely operate a larqe Boilinq Mater Reactor pover plant. The course consists of approximately 12 veeks of classroom lectures, simulator control room exercises, and in-plant oral seminars. This combination of instructional techniques affords the optimum mixture for successful skill training. The final: examination consists of written, control room performance, and plant oral examinations. Lectures and exercises are presented and guided hy qualified, GE BMR Training Personnel. Classroom lectures are scheduled for approximately 8 teaching hours per'ay. Suqgested reading and study assiqnments are made daily; written examinations are given weekly to monitor progress. In addition', at 'approximately the mid-point of the course, oral examinations are given to monitor the progress of each student's'skill acquisition.'he control room portion of the course is normally accomplished on night shifts of 8 hours . Pour hours are spent in the simulator control room (total approximately 112 hours) with exercises and demonstrations guided by the licensed instructor. The other 4 hours are devoted to oral seminars . Each student rotates to appropriate control room operatinq positions, including shift supervisor, so that all personnel have equal opportunity to perform plant evolutions from each operating position. The following is an anticipated'eek-by-week schedule of the course. Schedule changes and adjustments to course content will be made as necessary to meet the particular needs of the students. Meek 1 Introduction to the BMR Training Center Reactor Vessel and Internals Reactor Fuel Nuclear Boiler Instrumentation Control Rod Drive Nechanism Control Rod Drive Hydraulics Reactar Manual Control Recirculation System Recirculation Flow Control Reactor Water Cleanup System Shutdown Coolinq and Head Spray Source Range Nonitoring (SRN) Intermediate Range Monitoring (IRM} REV 30, 5/82 1 3w 2 7
SSES-FS AR Local Power Range Nonitoring (LPRN) Averaqe Power Ranqe Nonitorinq (APRN) Rod Block Nonitor Meek 2 Week l Examination Traversing In-Core Probe {TIP) Rod Worth Minimizer (RWN) 5ain Steam Turbine and Lube Oil System Electro-Hydraulic Control System (EHC) EHC Pressure Control and Loqic Condensate and Feedwater Feedwater Control Circulatinq Water Generator and Auxiliaries Generator Excitation AC Electrical Distribution Diesel Generators and DC Electrical Distribution Reactor Protection System (RPS) Primary and Secondary Containment Week 3 Week 2 Examination Fuel Pool Coolinq and"Cleanup A Off Gas System Liquid Radwaste Water Systems Isolation Condenser Introduction to Emergency Core Coolinq System (ECCS) High Pressure Coolant Infection (HPCI) Automatic Depressurization System (ADS) Low Pressure Coolant Injection {LPCI) Core Spray Emerqency Core Cooling System .Integrated Response Standby Liquid Control Process Radiation Nonitorinq Area Radiation Nonitorinq Reactor Physics Review Week 4 Pre-Start and Functional Checks Reactor Startups Heatups Nanipulation of Auxiliary Systems Power Changes in the Intermediate Range Surveillance Testinq Transfer to Run Node R EV. 30~ 5/82 13 2-8
SSES-PSAR Turbine Warmup and Roll Reek 5 Reactor Heatup and Transfer to Run Mode Turbine Roll Generator Synchronization and Loading Surveillance Testing Continued Loading to 100% Power Operations at Pull Power Tra nsient Analysis Quiz 1 Maneuvering by Plow Control Shutdown 'eactor Discussion on Decay Heat Operation and Removal Plant Problems Drills on Abnormal and Emergency Conditions Meek 6 Pre-Startup and Punctiona'1 Checks Reactor Startups and Heatups Manipulation of Auxiliary Systems Plant Problems Drills on Abnormal and Emergency Conditions Power Changes in the Intermediate Range. Surveillance Testing Transfer to Run Mode Turbine Warmup and Roll Operator Synchronization and Loading Quiz 2 Mid-Course Performance Examination Meek 7 Technical Specificatons Bases Review Review Certification Exam Format and Content Physics Problem Solving Mid-Course Control Room Checks Solid Radwaste Health Physics Review BMR Chemistry'hermal-Hydraulics Process Computer Circuit Breaker Control Fuel Handling and Puel Loading Physics 3 0, 5/82 13 2-9
SSES-FSAR Week 8 Steady-State Operation at 50% Load Surveillance Testing Increase to Full Load Drills on Abnormal and Emergency Conditions Operations at Pull Power Maneuvering by Flow Control Begin Reactor Shutdown Reactor Shutdown and Cooldown Flooding of Reactor Vessel Plant. Problems Reactor Startups and Heatups Scram and Scram Recoveries Week 9 Operation at Full Load Drills in Abnormal and Emergency Conditions. Shutdown to Hot Standby Quiz 3 Plant Startup from Hot Standby to Full Power Reactor Heatup Generator Synchronization and Loading Week 10 Operation at 50% Load Scrams and Scram Recoveries Surveillance Testing Operation at Full Power Drills Individual Student Operations Quiz 0 Transient Analysis Review Week 11 Review and Study Reactor Operator Certification Examination Week 12 Control Boom and Dresden Plant Oral Examination Control Boom Performance Demonstration Senior Reactor Operator Certif ication Examination REV 30'/82 13 2-10
,SS ES-FSAR o, Phase V BQR Observation
~4 ~
Traininn BMR observation training is designed to acguaint the operator, trainee with. the day-to-day routine of an operating BWR. This will involve exposure to plant operating and maintenance evolutions, station record keeping, and procedures. The course consists of approximately 4 weeks of guided observation of an operating BMR. All observation is conducte'd under the guidance of an experienced GE training.-personnel. The course is structured to provide experience in various aspects o f plant operation. The flexibility is achieved. by allowing the course director to adjust the group schedule to'it important plant evolutions. Daily work and observational assignments are made at the beginning of each work. day.. - . The followinq are weekly highlights of a'ypical.BWR observation schedule: Meek 1 Plant Evacuation Procedures/Station Emergency Plan, Health Physics Procedures Electrical Distribution Reactor Instrumentation Control Rods and Hydraulic Drive System Recirc MG set, support systems,'nd controls Main Steam System Controls and Instrumentation Residual Heat Removal System= All Modes Meek 2 Turbine, EHC System, and Turbine. Support Systems. Generator, Generator Excitation, and Generator Support Systems Turbine and Reactor Building Closed Cooling Water System Cir cula tinq and Service Water Systems Fire Protection Systems Core Spray System Meek 3 High Pressure Coolant Injection System Rea'ctor Core Isolation Cooling System Reactor Protection MG sets, Automa tic Depressurazation System Tra versinq In-core Probe System Neutron Monitorinq and 'Associated Control Systems Radioactive Waste Handling Equipment and Procedures Performance of Routinq Plant Equipment Checks REV. 30, 5/82 13. 2-11 Y
SSES-FSAR Meek 4 Instrument and Service.Air Systems Process and Area Radiation Monitoring Systems Fuel Pool Cooling System Standby'iquid Control System Plant Performance Logs Observance of Routine Plant and/or Surveillance Procedures In Progress Review Final Exam and Haik-Through o +Pa~g VI SYSTEMS PROCEDURES and DOTH/-JOB. T8hINING-The systems, procedures, and on-the-gob training phase will be approximately 20 weeks in length of which a minimum. of 8 weeks will he class room instruction. However, the weeks may not be scheduled consecutively due to plant testing and work, load, considerations. This phase will provide cold license candidates with an in-depth study of Susquehanna SES systems and equipment; nuclear characteristics; and Normal, Abnormal, Emerqen'cy and Administrative Procedures and Technical Specifications. Further operational training is accomplished as components, systems, or parts of systems are checked, tested, and placed in routine operation to provide necessary auxiliary support for other syste ms. Instructors for the various Phase VI lectures will be supplied by the Susquehanna staff, other PPSI.,organizations, vendors or consultants. Selections of the particular indivi.dual to "conduct a specific training lecture will be based upon individual availability and knowledge of the subject matter involved The course will consist of, but not be limited to:
- a. Theory and principles of operations
- b. General and specific plant operatinq characteristics
- c. Plant instrumentation and control systems
- d. Plant protection, safety and emergency systems
- e. Normal, abnormal and emergency operating procedures
- f. Radiation control and safety Technical Specifications
- h. Applicable portions of Title 10, Chapter Federal Requlations l, Code of REV 30~ 5/82 13. 2-12
SSES-PSAR
- i. Reactor Theory
- j. Handlinq, disposal and hazards of radioactive materials
- k. Puel handling and core parameters
- l. Administrative procedures, conditions and limitations A comprehensive examination vill be given during this phase to determine student weak areas.
o Phase.VII -= BWR pre License Refresher Tgaini~n,. Prior to the initial NRC Operator Licensing examination, a Pre-License Refresher Course will be conducted. This course vill be presented by PPSL employees or by outside personnel, and will be a summary and review of material presented in previous phases. Xf necessary an update of plant modifications and training to upqrade any identified weak areas will be. presented. 13.2. 1. 1.2. 2 lion-Licensed Ope~ator -Traini ng pgoqram The proqram is designed for non-licensed, operators and is divided into three phases which provide a logical progression from the entry level to final job qualif icat ion
- o. Phase I Academic Training
- o. Phase II Susquehanna SES System'ectures
- o. Phase III Susquehanna SES System'ualificati,on This traininq is progressive and candidates for non-licensed positions must successfully complete the training appropriate to their assiqned job. Phase I *may be exempted bypassing a vritten exam.
0- Phase I: The course consists of basic training in Nuclear Power Plant. Fundamentals. The program is about 160 hours
.long and consists of classroom training or equivalent self-study time. The areas to be covered will include such subjects as math, chemistry, atomic and,nuclear physics, health physics, nuclear instrumentation and reactor operations. Progress is measured by periodic quizzes and exa minations.
REV. 30, 5/82 13 2-13
SS ES- FS AB 0 Phase II The phase consists of basic Susquehanna SES systems and covers, as lectures on applicable, the follovinq areas of each system: General System Description Major Components and Flov Paths Instruments and Controls alarms and Trips Power Feeds Operatinq and Emergency Procedures The phase vill be approximately each week, approximately 80% 0 veeks of the time in length vill be and during spent in class and the remaining 20% vill be spent in the plant tracing systems. There vill be weekly guizzes and a final exam at the end of tQe course. o Phase III This phase systems for vhich they must be completed by operators on the are responsible. This phase will take about 10 weeks to complete.. However, the 10 weeks may not be consecutive due to work-load considerations Operators will be checked out on each system to assure they can operate these systems under normal, abnormal, and emergency situations. The check out vritten test on each system. vill consist 'of an oral 'and/or The Supervisor of Maintenance will receive training Level Health Physics training as described in Subsection 12.5 3.7, III selected training in plant systems operation and 'speciaalized vendor traininq on specific plant equipaent. t
'Foremen will receive additional experience on-.'the-gob during the preoperational test program through the supe'rvision of,
. maint ena nce activities. Station Mechanics and Leaders for the initial, plant staff will generally be selected from other PPGL facilities and will have practical experience in one or more crafts, and vill through their previous experience and/or selection testing demonstrate a hiqh degree of manual dexterity and capability of learning and-applying the basic skills in maintenance I operations. Maintenance personnel vill receive on-the-gob training during the preoperational test proqram by performinq. maintenance activities. Selected personnel will receive specialized. vendor tr'aining on specific equipment or skills such as control rod drive repair and welding. RE V. 30, 5/82 13 2-.14
SSES-PS AR Maintenance personnel requiring access to Radiation cwork Permit Areas will receive Level IX Health Physics training as described in Subsection 12. 5. 3. 7. 13 2. 1. 1.4= Technical Section Trainina Proaram The objective of the initial training program of the Technical Section is to provide competent personnel to support in the safe, efficient operation of the Susquehanna SES. Selected supervisory and professional/technical personnel will attend GE's Design Orientation courses (or other formal instruction with a similar intent) to familiarize them with .the design principles of a BMR. The ma)or topics covered will include BWR components, core desiqn, thermal-hydraulics, process and nuclear instrumentation design and operation and auxiliary systems. 13 2.1.1 4.1 Chemistry Pegsognel. By initial fuel loadinq, in addition to those courses described in Subsection 13.2.1.1.4, selected chemistry supervisory personnel will receive specialized training through a course such as>>BMR Chemistry" offered by GE. The course enables students to complete both radiological and chemical analyses -for process control, waste disposal, effluent monitoring, process and laboratory instrument calibration and evaluation. The course also covers compliance with and =interpretation of chemical and radiochemical aspects of the technical specifications, licenses and plant warranties. The Chemistry Leaders and Chemistry Analysts will receive iz-house traininq as developed by supervisory chemistry or other appropriate personnel, covering topics similar to those in. the >>BMR Chemistry" course. As appropriate, they may also attend vendor-sponsored training sessions to assure understanding and proper operation of laboratory instruments. Progress will be measured through oral and/or written examinations.
- 13. 2. 1~1. 4 2 - Inyfgumentafion 8 Control Personnel By initial fuel loading, in addition to those courses described in Subsection 13.2. 1. 4, appropriate ISC supervisory personnel 1
and selected ISC technicians will attend the GB "Nuclear REV. 30, 5/82 .13. 2-15
SS ES-FS AR Instrumentation" and "Process Instrumentation and.Controls" courses or other formal instruction with similar intent. The "Nuclear Instrumentation" course is broken into classroom and laboratory phases. The classroom phase covers the theory of operation and equipment demonstrations for the GE BIR nuclear process and area radiation monitoring, control rod position information, reactor protection and traversing incore probe systems. The laboratory phase teaches detailed circuitry study, setup, calibration, testing, maintenance and repair for .the various components of these systems and where possible for the overall system. The "Process Instrumentation and Control<. course teaches the theory of operation, setup, calibration, testing, maintenance and repair techniques for the basic instrumentation and control loop components for the GE BWR. Components to be covered include level, temperature, electrical properties, movement, chemical properties, sensinq devices, transmitters, power supplies, signal condi tioninq modules and controllers. Primary instrument control loops will also be studied. ISC technicians will also receive training covering topics such as AC/DC circuit fundamentals, transistor circuits, solid state devices and operational amplifiers and including "hands-on" experience with electrical and electronic circuits and components. As necessary, ISC personnel will attend courses offered by equipment vendors on various plant components. Progress will be measured throuqh oral and/or, written-examinations. By initial fuel loading, in addition to the courses described in Subsection 13.2. 1.1.4, selected Reactor Engineering. personnel will receive traininq through a course such as GE's "Station Nuclear Enqineerinq". The course covers topics like reactor behavior, control rods, shutdown margins, technical specifications and Fuel Barranty Operation Provisions, core flow and thermal limit calculations, fuel failure and PCIONR and water chemistry among others. Proqress will be measured through oral and/or written examinations. REV 30'/82 13 2-16
SS ES- PS AR '13,2,1.1. 5 Health physics Tnainj nH~Hno Haa Selected Health Physics supervisory personnel will receive specialiezed professional traininq in a course such as <<Radiological Enqineerinq<<offered by GE or equivalent. Health Physics Monitor Training Program is described in Subsection 12. 5.3.7. 13.2. 1 1.6 General Fmplo~ee Training-All permanent plant personnel granted unescorted vital area access at the station will be trained in the following areas:
- 1. Appropriate plans and procedures, including applicable plant security and emerqency procedures.
- 2. Radiological Health and Safety in accordance -with-Subsection 12.5.3.7
- 3. Industrial Safety.
- 4. Fire Protection Proqram.
- 5. Quality Assurance Program.
This training will be the responsibility of the Plant Training Supervisor and will be repeated on a two-year cycle. Personnel will be examined in the above areas to determine the effectiveness of general employee training. Temporary Maintenance and Service personnel will be trained in the areas listed to the extent necessary to assure safe execution of their duties. 13 2. 1- 1 7 ~ Fige Saf et'raining" The object of the fire safety training proqram is to provide training for the plant fire brigade, traininq for maintenance and inspection of fire protection equipment and training for the fire protection staff. REV. 30, 5/82 13e 2 17
SS ES-PS AH
- 13. 2. 1 1.7. 1 Fire Briqade - Training In addition to qeneral employee training, individuals. assiganed to fire fightinq duties will receivevill training in order that an effective fire fiqhtinq brigade be available for fire emerqencies. FIre brigade training sessions will be held a minimum of four times per year, with the basic program-;-'heing repeated every t wo years. Tra ining will be. a blend of classroom, sessions, practice sessions and fire' ighting drills. -Pire brigade members will receive instruction on fixed and 'portable .
fire,fiqhhtinq equipment,, fire protection measures of other plant features and will be trained in hands on experience with fire fiqhtinq equipment and,techniques. The local fire departments will be invited and year'. encouraged to participate in'=at least session per ' one'raininq i~I 13,2,1. 1,7,2- Pi~e protection St~af -and Tgaini~n No traininq proqram is planned for the off site fire. protection " ~ engineer. The position description requires that 'the incumbent be a qualified fire protection engineer with suitable'-background
/
experience to meet the gob requirements-. 'A major part of 'the on site fire protection engineer~s training will.be- on fire the gob training and informal discussions with the off site protection enqineer. This training, vill'be augmented. by vendor traininq schools and state fire fighting schools as n'ecessary /to carry out the job responsibilities. The on site fire protection
.engineer will have the responsibility of training or arranging for the traininq of fire briqade personnel, on site fireof the department traininq and traininq of personnel in charge maintenance of fire detection and fire suppression systems..
/
1g 2. 1.2- Coordigation -with "pgeoperational Tests and Fuel Loadi~n
' / Figure 13.2-1 illustrates the relationship of the Plant Staff K
Training to preoperational testing and Tuel.loading. / R EV. 30, 5/82 13 2-18
SS ES-PS AR 13 2 2 ~ROQQI PICQTXON AgQ gggLAC~NENT TBQXMING P R 13.2". 2 1 "Licensed-O~~eat~o gegualification'-P o ram-I II The Requalification. Program for licensed and senior licensed individuals will'.be. established and ready for implementation no. later than 3. months followinq issuance of the station operating license. The program consists of lectures, plant. operational evolutions, simulator activities, drills,.evaluations, self-study,. and tests. A minimum of'"40 hours of simulator .training will be scheduled each year. ,The program is based on a 2 year license renewal cycle with periodic quizzes, 'written tests, and annual simulator and oral examinations administered throuqhout to ensure training effectiveness and technical competency. N 13.2 2.1.1 "Lectures Licensed -operators will be reguired to attend classroom lectures on the f'ollowing subjects annually: Reactor Theory and Principles of Reactor Operation Peatures of Pacility Design General and Specific Plant Operating Characteristics Instrumentation and Control Systems Protection Systems Emergency Core Cooling Systems
,Radiation Control and Safety Technical Specifications Code of Federal Regulations Heat Transfer and Fluid Plow Desiqn, Procedure, License Changes Recent LEBs, Industry Events, Plant Activities General and Emerqency Procedure Reviews Pailing to attend a scheduled lecture, an operator will be required to achieve mastery of this material prior to the examination. This achievement can be accomplished by attending another lecture if scheduled: or by satisfactorily taking and passing a quiz on the subject.
REV 30, 5/82 13 2-19
SS ES-PS AR
- 13. 2. 2.1.2 Plagt Operational Evolutions Each individual shall perform or participate in a combination of at least 10 reactivity control manipulations either in the plant or on the simulator. The followinq control manipulations and plant evolutions are acceptable for meeting the ten reactivity required by 10CPR55, Appendix A. The use of the Technical Specitications should be maximized during the simulator control manipulations. Personnel with senior licenses are credited with these activities if they direct or evaluate control manipulations as they are performed. These items should be signed off hy Shift Supervisor or Instructor. The asterisked items shall he performed annually.
Performance Item (1) Plant or reactor startups to include a range that reactivity feedback from nuclear heat addition is noticeable and heatup rate is established. (2) Plant shutdown. (3) manual control of feedwater during startup and shutdown. {0) Any siqnificant (>10%) power changes in manual rod control or recircula tion flow. {5) Loss of coolant. (a) Inside and outside primary containment. (h) Larqe and small, includinq leak-rate determination. (6) Loss of instrument air. (7) Loss of electrical power (and/or degraded power sources) . (8) Loss of core coolant flow/natural circulation. (9) Loss of condenser vacuum. (10) Loss of ser vice water.
~(11) Loss of shutdown coolinq.
(32) Loss of component cooling system or cooling to an individual component. (13) Loss of normal feedwater or normal feedwater system failure. R EV. 30, 5/82 13. 2-20
SS ES- PS AR (14) Loss of all feedwater {normal and emergency) . (15) Loss of protective system channel. (16) Nispositioned control rod or rods (or rod drops). (17) Inability to drive control rods. (18) Conditions requiring use of standby liquid control system. {19) Fuel cladding failure or high activity in reactor coolant or offqas. (20) Turbine or qenerator trip. (21) Malfunction of automatic control systems(s) which affect reactivity. (22) Nalfunction of reactor coolant pressure control system. (23) Reactor trip. (7Q) Hain steam line break (inside or outside containment). {25) Nuclear instrumentation failure(s). (26) Any reactor power chanqe of 10 percent or greater where load chanqe is performed with load limit control. 13 2. 2. 1. 3 Operator Proof iciencg Evaluations At least once per year durinq the term of an individual's license, he vill be observed and formally evaluated while respondinq to actual or simulated casualties. Zn the case of simulated casualties, a hypothetical situation would be presented followed by a discussion of plant and operator response. The simulator will be used as the ma5or basis for operator proficiency evaluation, actual manipulation of plant controls is not required. A poor performance is defined as not being able to competently and expeditiously perform the specified evolution. This will result in the implementation of a performance Review as specified in Subsection 13. 2. 2.1. 5. All evaluations will be critiqued with the, individual concerned and filed in the indi v idual ' t raininq records. RE V. 3 0, 5/82 13 2-21
SS ZS- FS AR 13.2 2 1 4 Tests (a) Periodic quizzes will be administered during and/or after each lecture series to monitor program ef fectiveness. {b) Comprehensive written tests which are similar in scope and difficulty to the NRC exam will be given periodically and will cover the following topics over a 2 year period:
- 1) Theory and Primciples of Operations
- 2) General and Specific Plant Operating Characteristics
- 3) Plant-Instrumentation and Control Systems
- 4) Plant Protection Systems
- 5) Normal, Abnormal, and Emergency Operating Procedures
- 6) Radiation Control and Safety
- 7) Technical Specifications
- 8) Applicable Portions of Title 10, Chapter 1, Code of Federal Regulations
- 9) Thermal Hydraulics, Heat Transfer, and Fluid Flow Traini nq.
To successfully complete this exam, the license holder must score greater than or equal to 70 percent on each quarterly exam and qreater than or equal to 80 percent average over the two year period. Any license holder who scores less than 80 percent averaqe overall or less than 70 percent on any test will receive accelerated upgrade traininq and a re-examination will be administered within 2 weeks. If the re-examination is failed the license holder shall be removed from license duties immediately and the Performance Review Proqram per 13.2.2.1.6 shall be implemented. 13.2. 2. 1. 5 Performance Review Program The Performance Review Proqram shall be implemented whenever any one of the followinq situations occurs. During such review proqrams the individual shall not perform any license duties until the individual has been properly evaluated and judged competent. {a) The quarterly examination score of less than.70 percent or less than 80 percent average during the 2 year license period. (b) <Poor" rating on operator proficiency evaluation. R EV. 30, 5/82 13. 2-22
SS ES- FS AR (c) Pv'olonqed absence from license duties. The Superintendent of Plant, Supervisor of'Operations, and Manager Nuclear Traininq will meet to determine a course of action necessary to upgrade the individual's performance to an acceptable level. This reviev shall determine the minimum requirements on an individual basis. The nature of the action taken vill be dependent on such factors as examination performance, operatinq perf ormance, observed operational and theoretical understandinq and overall operator competence. Shen receiving less than 80 percent overall average or less than 70 percent on any test, an oral examination may be administered to determine vhether or not an individual may resume licensed duties. However, the individual shall remain on the Performance Review Proqram until a score of greater than 70 percent or areater than 80 percent averaqe is obtained on a vritten examination which specifically covers those areas of the exam where the licensee receives less than satisfactory marks. Management will complete a performance review summary vhich, upon completion, vill be filed in the individual s training folder. 13.2.),t.6 Pgogonged gbsence Prom license Responsibilities In the event a licensed individual is absent from the site for a period of four months or lonqer, he vill not be permitted to resume operational responsibilities until the following criteria have been met: fa) The satisfactory completion of an upgrading program determined'nder the provisions of Subsection 13.2. 2.
- 1) This proqram shall include as a minimum, the review of any facility desiqn, operatinq procedure or license changes which have taken place during the absentee period.
- 2) The individual must receive greater than or equal to 70 percent on a written or satisfactory on an oral exam covering the material in item 1 above.
Mhen an oral exam is used, it shall be administered by the Supervisor of Operations or designated senior licensee. (b) This certification shall be documented in the individual s traininq record. R EV. 30>> 5/82 3& 2 23
SS ES-PS AB
- 13. 2. 2. 1. 7 - Record pete nt ion The Manaqer-Nuclear Training vill be responsible for maintaining license holder requalification training records. Records of the requalification program shall be maintained to document each licensed operator's and senior operator's participation in the requalification program. The records shall contain copies of written examinations administered, the answers given by the licensee. results of evaluations and documentation of any additional traininq administered in areas in which an- operator or senior operator has exhibited deficiencies. Records shall be maintained for the duration of the unit operating license.
13.2. 2.1 8 Licensed Staf f Participation Licensed staff personnel participate in the following areas of the requalif ication program: (a) Complete the quarterly written examination and participate in the lecture series based on the results. (b) Manipulate the controls or supervise the manipulation of controls through 10 reactivity chanqes. (c) Review day-to-day changes in the facility design procedures, and technical specification. (d) Review abnormal and emergency procedures annually. (e) Are evaluated regarding actions to be taken during simulated abnormal and emerqency conditions by a walkthrouqh of the applicable procedure.
- 13. 2. 2. 2 Re fresher Traininq for Nonlicensed Personnel As a minimum, all non-licensed personnel shall receive refresher instruction on administrative, radiation protection, emergency and security procedures once every two years.
13.2. 2.2.1 Refresheg Training for Nonlicensed ~Oerators Nonlicensed operators assigned on shift will participate in a requalification program and be trained, tested, and evaluated on a two year schedule. RZV 30, 5/82 13. 2- 24
SS ES-FS AR 13 2,2 2,2 Refgesh~e Tggining fog Maintenance Personnel A retraininq proqram is provided for maintenance personnel to ensure t.hat they remain proficient in their particular gob.. Retraining in specific areas is provided to the extent necessary for personnel to safely and efficiently carry out their assigned responsibilities in accordance with established policies and proce dur es. Such training may consist of vendor presentations, technical traininq sessions, on-the-gob work experience or programmed instruction. Maintenance personnel are evaluated on an annual basis where individual needs for retraining will be identified.
- 13. 2. 2. 2 3 Refresheg Training fog Technical Section Personnel Refresher 'courses will be provided to maintain an individual's level of expertise equal to or exceeding that, required by his or her job responsibilities.
13.2 2.3 Reolacement Training Replacement traininq is desiqned to supply qualified personnel for all levels of the plant organization. It is the policy of f rom PPGL to promote qualified personnel into job vacancies candidates that are next in the line of promotion. Such individuals" will receive traininq appropriate to the new position. Permanent replacement personnel procured from other sources will meet or exceed the requirements of the vacant position. 13.2.2.3.1 NRC Licensed Ooerator Replacement Throuqh a system of required operator qualification steps, personnel assigned as nonlicensed operators are provided training that prepares them for eventual NRC licensed operator positions. At such time as a need exists for replacement of licensed operators, individual preparation in theory, systems, operating procedures, emergency procedures, and health physics is conducted. Additionally, individual on-the-gob training involvinq manipulation of the nuclear reactor plant controls during day-to-day operation, startups and shutdowns of the reactor or appropriate reactor simulator, is conducted. R R V. 30, 5/82 13. 2-25
SS ES-FS AR Progress is reviewed as the replacement moves through the program. The reviev consists of periodic vritten and/or oral examinations. 13 2. 2.3.2 Non-licensed Operator Replacement Training Replacement traininq is designed to insure fully qualified personnel for all levels of plant operation. To the extent possible, persons who have already achieved the level of training required for a specific gob will be advanced. In all cases the requirements of Subsection 13. 2.1. 1.2.2 or equivalent will be satis fied.
- 13. 2. 2.3. 3 Naintenagge Personnel Replacement Training Replacement training is designed to supply qualified personnel for all levels of the Haintenance orqanization. It is the policy of PPGL to promote qualified personnel into job vacancies for candidates that are next in the line of promotion. Permanent replacement personnel will meet or exceed the requirements of the vacant position by virtue of previous education and experience.
The Maintenance orqanization is specifically intended to provide the opportunity for personnel in lover level gobs to receive on-the-job-traininq that will prepare them for advancement. The same quality of traininq provided for the original staff will be provided to personnel desiqnated to maintenance organization. fill vacancies in the
- 13. 2. 2.3.4 Tgchn ical Sec(ion Personnel Replacement Traini~n Replacement traininq is designed to assure fully qualified personnel for all levels of the Technical 'Section. To the extent possible, persons who have already achieved the level of training required for a specific job will be advanced. In all cases the requirements of Subsection 13.2.1.1.4 or equivalent will be sa tis fied.
13 2.2 4 Records Traininq records are established for each permanent plant employee. These records include, but are not limited to, lecture/annual examination questions and answers, lecture RP V 30r 5/82 13. 2-26
SSES-PS AR attendance records, performance evaluation records, and other records as may be required to adequately document all training received bv station personnel. Training records vill be periodically reviewed in accordance with station procedures.to assess the effectiveness of the training proqram. 13.2.2.5 Responsible Individual The Plant Traininq Supervisor is responsible for the administration and conduct of the Susquehanna SES training proqram. REV 30, 5/82 13 ~ 2 27
SSES-FSAR CHAPTER 14,.0 TABLES Table Number Title 14.2-1 Preoperational Test Procedures 14.2-2 Acceptance Test Procedures 14.2-3 Startup Test Procedures 14.2-4 Test Plateau Schedule - Test Condition Sequence 14.2-5 Control Rod Drive System Tests Rev 23 2/81 14-iii
SSES-FSAR CHAPTER 14.0 FIGURES Fi ure Number Title 14 . 2-1 Integrated Startup Group Organization
- 14. 2-2a Preoperational Test Procedure Standard Format 14.2-2b Startup Test Procedure Standard Format 14.2-3 Initial Test Program Schedule 14.2-4a Unit 1 Preoperational Test Sequence 14.2-4b Unit 2 Preoperational Test Sequence 14.2-5 Sh. 1 Individual Startup Test Sequence 14.2-5 Sh. 2 Individual Startup Test Sequence 14.2-6 Sh. 1 Power Flow Map and Startup Test Conditions 14.2-6 Sh. 2 Power Flow Map and Power Test Conditions Rev 23 2/81 14-iv
SSES-PS AR 14 2 SPECIPIC INFORHATIOR TO BE INCLUDED IH FINAL SAFETY MQLXSIP. ~ORT-As construction'f systems/components is completed, the construction organization relinquishes Jurisdictional control of these systems/components through a formal turnover to PPSL. Eventually all plant systems/components are turned over to PPSL The Initial Test Proqram encompasses the scope of events that commence with system/component turnover and terminate with the completion of power ascension testing. The Initial Test Program is conducted in two separate and sequential subprograms, the Preoperational Test Program and the Startup Test Program. At the conclusion of these subproqrams the plant is ready for normal power operation. Testing during the Initial Test Program is accomplished in five distinct and sequential phases:
- a. Phase I - Component Inspection and Testing Phase
- b. Phase II Preoperational and Acceptance Testing Phase
- c. .Phase XIX Initial Puel Loading Phase Phase IV Initial Heatup and Low Power Testing Phase
- e. Phase V Power Ascension Test Phase Phase I and Phase II- are seguential on a system basis while Phases III, IU and V are seguential on,a plant basis.
'l4-$ .~~1P gg~gt~~g Test ~Pggam Preoperational Test Program is defined as that part of the F
The Initial Test Program that commences with system/co'mponent .turnover and terminates with commencement of nuclear fuel loading. The proqram is subdivided into two phases in which plant equipment and systems are prepared for a higher degree of operability. The phases are:
- 1) Component Inspection and Testing Phase (Phase I)
- 2) Preoperational and Acceptance Test Phase (Phase II)
Component inspection and testing will insure that components and equipment are calibrated and checked, construction work on a particular system has been completed to the degree reguired and Re v. 30, 5/82 14 2-1
SSES-FSAR the system is initially operated and prepared for subsequent testing. After component inspection and testing is complete on a system, formal tests denoted as preoperational or acceptance tests are conducted durinq the Preoperational and Acceptance Test Phase. The Preoperational tests demonstrate, to the extent practicable, the capability of safety-related structures, systems, and components to meet their safety-related performance requirements. The completion of preoperational testing constitutes completion of Phase XI of -the Initial Test Program-Tests similar to preoperational tests denoted as acceptance tests (Table 14.2-2), may be conducted on additional non safety-related structures, systems, and components to demonstrate their capability to perform their nonsafety-related performance requirements. To the extent practicable, the objectives of the Preoperational Test Proqram are to: a0 Verify the adequacy of plant design
- b. Verify that plant construction is in accordance vith desiqn.
ci Demonstr'ate proper sys'em/component response to anticipated transients and postulated accidents
- d. Confirm the adequacy of plant operating and emergency procedures
- e. Familiarize plant staff operatinq, technical, and maintenance personnel with plant systems
- 14. 2. 1.2 Startuo Test Proqram The Startup Test Program is defined as that part of the Initial Test Proqram that commences with the start of nuclear fuel loading and terminates with the completion of power Formal tests, denoted as startup tests, are conducted ascension'esting.
durinq this proqram. These tests confirm the design bases and demonstrate, to the extent practicable, that the plant vill operate in accordance vith design and is capable of responding as designed to anticipated transients and postulated accidents. Startup testinq is sequenced such that the safety of the plant is never totally dependent upon the performance of untested structures, systems, or components. The completion of startup testinq constitutes completion of Phases Initial Test Program. III, IV, and V of the The obgectives of the Startup Test Program are to: R ev.,31, 7/82 14. 2-2
SS ES-FS AH
- a. Accomplish a controlled, orderly, and safe initial core loadinq
- b. , Accomplish a controlled, orderly, and safe initial criticality and heatup n
ce Conduct low power testing sufficient to ensure that design parameters are satisfied and safety analysis assumptions are correct or conservative
- d. Perform a controlled, orderly, and safe power ascension 14 2. 2 ORGANIZATION AND STAPFXNG The Superintendent of Plant Susquehanna, has overall responsibility for the Initial Test Program. The Plant Staff and Integrated Startup Group (ISG) conduct the different phases of the test program. Responsibility for the ISG may be delegated to the Assistant Superintendent of Plant-Outaqes. In addition to these basic orqanizational units the Superintendent of Plant Susquehanna is assisted by two review organizations, the Plant Operations Review Committee (PORC) and the Test Review Board (TRB). The orqanization, authority, responsibility, and degree of participation of each of these organizational units during the Initial Test Proqram are described in the following sections.
14.2.2.1 Plant Staff The Plant Staff consists of the permanent onsite PPGL personnel responsible for the safe operation and proper maintenance of the plant. Chapter 13 describes the Plant Staff organization. This section also establishes responsibilities, reporting relationships, and'inimum qualification reguirements for principal Plant Staff supervisory personnel. The Plant Staff also includes the Startup Test Group which is a temporary group established to prepare for and implement the Startup Test Program. The Startup Test Group Supervisor reports to the Technical Supervisor and supervises the activities of the Startup Test Group. Activities include; preparation and implementation of startup tests; review and analysis of startup test results; preparation of startup test reports; and participation in test planning meetings. During the implementation of startup tests, the Startup Test Directors will report to the Startup Test Group Supervisor. The Shift Technical Advisors, Reactor Engineers and other qualified Personnel will function as the Startup Test Directors during the Unit 1 Startup
'ev.
31, 7/82 14 2-3
SS ES- FS AR Test .Program. Also reporting to the Startup Test Group Super visor is one or more S tar tup Test Engineers. The Plant Staff, is utilized, to the fullest extent practicable, durinq the Initial Test Program. Specific responsibilities of the'Plant Staff durinq, the Initial Vest Program are: Performing selected preventive and corrective ma intenance.
- b. Operating plant equipment.
Co Calibrating instruments, meters. d., Performinq chemical and radiological inspections and tests
- e. Providinq required replacement and spare parts Providinq operator, technician, and maintenance support to the XSG Ensurinq that vendors, consultants, or other temporary personnel assisting the Plant Staff work. in accordance with established project procedures
- h. confirming the adequacy of plant operating and emerqency procedures to the extent practicable.
Authorizinq and ensuring proper documentation, identification, and restoration of temporary modifications mage during the Startup Test Program. Authorizing and monitorinq rework, modification, testing and maintenance during the Startup Test Proq ram.
- k. Coordinating preparation, review and approval of startup test procedures.
Coordinating performance of startup .testing. Coordinatinq review and approval of startup test results.
- n. Planninq and schedulinq Startup Test Program activities.
Rev. 31, 7/82 14 2-4
SS ZS-PS AR
- 14. 2,2,2 Xntegggted Stagggg Ggoup Orqag ization and pesponsibilities The Integrated Startup Grou'p (ISG) is a temporary organizational unit established to augment -the Plant Staff during the Initial Test Program. The ISG is comprised of individuals of various orqanizations (Bechtel, General Electric, PPSL, and others) .
Piqure 14.2-1 shows the orqanizational structure of the ISG. The responsibility and qualification requirements of principal ISG supervisory personnel, the structure of the basic constituents comprising the ISG, andthe responsibilities delegated to the ISG are described '.in the followinq sections. 14.2.2.2.1 XSG Supervisor The ISG Supervisor has overall responsibility for supervising the conduct of the ISG. The ISG Supervisor reports to the Superintendent of Plant - Susquehanna, or the Assistant Superintendent of Plant-Outages, on matters pertaining to the Initial Test Proqram. The minimum qualifications for the ISG Supervisor are one of the following:
\
- a. Graduate of a four-year a ccredited engineering or science colleqe or university, plus five years of experience in testing or operation (or both) of power
~
plants, nuclear facilities, or similar industrial installations. At least two years of this experience should be associated with nuclear facilities; or not, the individual shall have training if sufficient to acquaint him thoroughly with the safety aspects of a nuclear facility; or, b High school qraduate, plus ten years of experience in testing or operation (or both) of power plants, nuclear facilities, or similar industrial installations. At least two years of this experience should be associated with nuclear facilities; or shall have if not, the individual traininq sufficient to acquaint him thorouqhly with. the safety aspects of nuclear facilities. 14.2. 2.2.2 Assistant XSG Supervisor The Assistant ISG Supervisor performs a line function and reports to the XSG Supervisor. The Assistant XSG Supervisor is specifically responsible for supervision of Systems Group Leaders and assumes the responsibilities of the XSG Supervisor in his a bsence.
'ev.
31, 7 j'82 14 2-5
SS ES-PS AR The minimum qualifications of the Assistant ISG Supervisor are the same as the ISG Supervisor and are as described in Subsection 14 2.2 2 1 14.2. 2.2.3 Group Leaders Group Leaders perform line functions and report to the Assistant ISG Supervisor. Group Leaders are assigned a staff of System Startup Enqineers. Group Leaders have overall responsibility for assigned systems.
- 14. 2. 2. 2. 4 I SG Coordinatop The ISG Coordinator performs a staff function and reports to the ISG Supervisor. The ISG Coordinator is responsible for coordinatinq ISG interfacinq activities with Plant Staff, Construction and various prospect support organizations involved in the Initial Test Program.
The ISG Coordinator is respons1ble for all ISG administrative activities, which includes tracking the development, review, approval and revision of all Preoperational and Acceptance Test Procedures. This also includes the development, review, approval and revision of all ISG Startup Administrative manual and Startup Technical Manual Procedures. 1 4,2, 2. 7. 5 I SG Spec iglis gs S uperyi sor The ISG Specialist Supervisor performs a staff function and reports the ISG Supervisor. The ISG Specialist Supervisor is responsible for the coordination and supervision of activities relatinq to Design Change Packages, Material Procurement Expediting, Advance Control Room/Poster Generation Control Complex work coordination, Scoping, and ISC coordination.
- 14. 2. 2. 2. 6 ISG Schedule Super v isor.
The ISG Schedule Supervisor performs a staff function and reports directly to the ISG Supervisor. He is responsible for the development and coordination of all startup schedules. R ev. 31, 7/82 14. 2-6
SS ES-PS AR 14.2.2.2.7 'SG Quality Engineer/Record Control Group Supegyigog The ISG Quality Engineer/Record Control Group Supervisor performs a staff function and reports to the ISG Supervisor. The Quality Engineer/Record Control Group Supervisor is responsible for the coordination and interface of quality matters within and external to the ISG Orqanization. He is also responsible for the controL and review of records associated with ISG System/Component testing. 14 ~ 2.~>.2.8
=2= = GE STO S +~e M na e The General Electric Startup Test Organization Site Manager performs a staff function reporting to the ISG Supervisor during the Preoperational Test Program and to the Superintendent of Plant during the Startup Test program. The General Electric Startup Test Organization Site Manager is responsible for directinq and coordinating activities of the GE field engineers assigned to him for the, conduct of test or surveillance activities an NSSS systems.
- 14. 2. 2. 2.' He soonsibilities Specific responsibilities of the ISG during the Initial Test Program are:
- a. Recommendinq acceptance or refection of system/component turnover to PPGL
- b. Coordinating initial instrument, relay, and meter
. calibration co Coordinating initial diqital and analog control loop checkout
/
Coordinatinq initial eguipment operation e..- Coordinating system cleanliness verif ication af ter turnover
- f. Ensuring that assigned vendors or other consultants perform work in accordance with approved procedures
- q. Authorizing and ensuring proper identification, documentation, and restoration of temporary modifications made during the Preoperational Test Bev. 31, 7/82 14. 2-7
SSES-FSAR Program f for selected systems/components th is responsibility may be assumed by 'the Plant Staff prior to conclusion of the Preoperational Test Program).-
- h. Documenting and reporting design problems identified during the Initial Test. Program until, PPSL permanent plant procedures are implemented -to perform this function, at which time this becomes a. Plant Staff responsibility. Implementation of permanent plant
'procedures may be on a system unit, or plant basis.
Documenting and reporting construction problems identified during the Initial Test Program until PPSL permanent plant procedures are implemented to perform this function, at which time this becomes a Plant Implementation of permanent plant Staff'esponsibility. procedures may be on a system, unit, or plant basis. Authorizing and monitoring rework, modification, and maintenance during the Preoperational Test Program (for selected systems/components this responsibility may be assumed hy the Plant Staff prior to conclusion of the Preoperational Test Program) .
\
Coordinating preparation, review, and approval of component and preoperational test procedures. Coordinatinq performance of component and preoperational testing. Coordinatinq review and approval of component, and preoperational test results.
- n. Planning and scheduling Preoperational Test Program activities.
14,2,2,3 PlantOperation@ geview Committee The Plant Operations Review Committee (PORC) consists of the individuals assigned independent review responsibility in accordance with the requirements of Chapter 13. The responsibilities', reporting relationships, and qualification requirements of PORC members are also described in Chapter 13. During,the Initial Test Program additional responsibilities of PORC include reviewing and recommending approval of startup test procedures prior to testinq and reviewing- and recommending appro va1 of star tup test results followinq testing. R ev. 31, 7/82 14. 2-8
SS ES-PS AR 14.2.2.4 Test Review Board The Test Review Boa d {TRB) is a temporary review organization established specifically for the Preoperational Test Program. Test Review Board members may consist of individuals of various organizations {Bechtel, General Electric, PPSL, or others) . The Test Review Board is responsible for review of preoperational test procedures prior to testing and for review of preoperational test results after testing. The TRB recommends approval to the Superintendent of Plant. The Superintendent of Plant is responsible for the assignment of individuals to the Test Review Board. These assignments may be on a permanent or temporary basis. The TRB Chairman is responsible for the conduct of the TRB and is directly responsible to the Superintendent of Plant. The minimum qualifications of the TRB Chairman are the same as identified in Subsection 14.2.2.2.1.
- 14. g 3 TEST PQOCEDlJQES
\
The Initial Test Program is conducted in accordance with detailed component, preoperational, and startup test procedures. PPSL maintains overall responsibility for test procedure preparation, review, and approval. These activities are completed in a timely fashion to ensure that these procedures are suitable for NRC review at least 60 days prior to their intended use. 14.2. 3. 1 Procedure Pre@aration Component test procedures are initially prepared by designated
.organizatons {Bechtel General Electric, PPGL or others) . The
~
. completed drafts are reviewed by other cognizant organizations
..And approved by the ISG Supervisor. Preop'erational and Startup test procedure drafts are initially prepared by desiqnated orqanizations (Bechtel, General Electric, PPGL, or others) in accordance with the standard format of Figures 14 2-2A 6 B. The completed drafts are then reviewed by coqnizant design organization representatives to ensure that test procedure objectives and acceptance criteria are consistent with current desiqn document requirements. Review comments are resolved between the writinq organization and the cognizant desiqn orqanization representative. The followinq items are the responsibility of the ISG for component and preoperational test procedures and the Plant Staff for Startup test procedures: Hev. 32, 12/82 14 2-9
SSES-FSAR a~ Updating procedure referen'ces to latest revisions. b VerifVing the procedure has been revised to incorporate design changes. co Verifying procedure compatibility with field installation of equipment. d Resolving comments on procedures received from TRB~ PORC or the Superintendent of Plant.
- e. Evaluating reactor operating and testing experiences as supplied by the Manager-Nuclear Support in the development of the procedures.
14 g.~~ Pggcedg~e- R~ei~ew nd ~Approval Following initial preparation the component tests are reviewed by cognizant organizations and sent hack to the XSG for inclusion of comments. The ESG Supervisor then approves the component test procedures. Following initial preparation, the Preoperational and Startup test procedures are processed through a formal review and approval cycle. The responsibility for coordinating this process and for resolving review comments lies with the ISG Supervisor or his designee for preoperational tests and with the Technical Supervisor or his designee for startup tests. Specific review responsibilities are as follows=
- a. For preoperational and acceptance test procedures the Test Review Board, under the direction of the TRB .
Chairman, is responsible for:
- 1. Verifying procedure conformance with the FSAR, environmental technical specifications, and plant operating technical specif ications.
- 2. Ensuring technical adequacy of procedures.
- 3. Recommending approval of test procedures.
4 The Test Review Board is responsible for review of preoperational test procedures prior to testing and for review of preoperational test results after testing. 4 P For the Startup Test Program test procedures the Plant Operations Review Committee, as described in Chapter 13 is responsible for: Rev. 30, 5/82 14 2- 10
SSBS-FS AR
- 1. ' Verifying procedure conformance with the PSAR, environmental technical specifications, and pl'ant operating technical specifications.
- 2. Performinq a nuclear safety review as required by the plant technical specifications.
- 3. Ensuring technical adequacy of the procedures.
- 4. Recommendinq approval of test procedures.
Upon completion of review and inclusion of required changes preoperational and startup test procedures are submitted for approval by the Superintendent of Plant. 14.)~4 - Conducf of Test P~ogam The administrative controls that govern conduct of the Plant Staff and of the Integrated Startup Group during the Initial Test Program are specified by administrative procedures. These administrative procedures, are PPSL controlled and approved documents. A'dministrative 'procedures define tasks to be performed, prescribe methods, and assign responsibilities for performing them. The administrative procedures governing conduct of the Integrated Startup Group are contained in the Startup Administrative Manual which is approved by the Superintendent of Plant. These procedures do not establish the administrative controls of other project groups or organizations except as they interface with the vill Integrated Startup Group. The Startup Administrative Hanual be approved for use prior to start of the Initial Test Program. The administrative procedures governing conduct of the Plant Staff are as specified in Chapter 13. The schedule foris also preparation, review, and approval of these procedures described in Chapter 13. This schedule provides sufficient, time for procedures to be available for use prior to the time they are required to be implemented. Preoperationa'l and Startup testing performed during the Initial Test Program is in accordance vith approved test procedures. The method for preparing, reviesing, and approving these test procedures is detailed in Subsection 14.2.3. Prior to start of testinq, a test director(s) is assigned to eachas procedure.. The test director(s) is the individual designated being responsible for coordinating test performance. Test directors Rev. 30, 5/82 14 2-11
SS ES-FS AH for preoperational tests are assigned from the XSG or the Plant Staff by the ISG Supervisor or his designee. Test directors for startup tests are assigned by the Technical Supervisor or his designee. Specific responsibilities of the test director include but are not limited to= a 0 Verifying test prerequisites are complete and properly documented, except as provided by Subsection 14. 2. 9.2 b Ensuring that required test apparatus/equipment is available and calibrated.
- c. Documentinq test performance on a single copy of the procedure, denoted as the official test copy d Ensuring that test precautions are observed during testing
- e. Adherinq to the detailed instructions of the approved procedure, except as provided by Subsection 14.2.4.3 Ensuring 'test personnel'ave been properly briefed
- q. Documenting and reporting test exceptions The plant operating staff is responsible for the safe and proper operation of equipment during testing. Should an unsafe condition arise, the plant operating staff shall take whatever action is necessary including, but not limited to, stopping the test in order to restore safe plant conditions. During startup testing, the plant operatinq staff is specifically responsible for compliance with operating technical specifications, and compliance with the provimons of the operating license.
Specific test prerequisites are identified in,.each preoperational test procedure. The test director verifies that each prerequisite is completed and properly documented prior to signoff in the official test copy of the procedure. If a prerequisite-in a preoperational test cannot be satisfied, the test director vill institute a procedure modification to the Preoperational Test. As a prerequisite to preoperational testing, proper operation of each alarm loop is verified and listed in an appendix to the test. During the preoperational test, system parameters are varied and interlocks -are tested shich cause alarms to actuate. Ee v. 30 ~ 5/82 14 2- 12
SS ES-FS AR Those alarms which are actuated during the course of the test will be documented in the body of the preoperational test. 1 4. 2. 4. 3 f Procggugg Qgg j, gcgfj,ops Tests are conducted in accordance with approved procedures. If necessary, these procedures may be modified to complete testing. Such procedure modifications are documented on a test change notice form. In addition to generation of a test change notice form for preoperational tests, the test director marks up the ! official test copy of the procedure and initials/dates the chang e. Review and approval for test chanqe notices on preoperational test procedures is provided by the TRB. Review and approval for test change notices on startup test procedures is provided by the PORC. Preparation, review and approval activities are accomplished before or after performance of associated testing based on the folio wing criteria: a) Non-Intent Changes For procedure modifications that do not change acceptance criteria and do preserve the intent of the test, the test change notice may be approved after perf ormance of associated testing. Non-Intent changes for startup tests shall be initialed/dated by an on-shift licensed senior operator in addition to the test director prior to performance of associated changes. b) Intent Changes For procedure modifications that alter the acceptance criteria or the intent of the test, the test change notice is approved before performance of associated test inq. 14 2.4.4 Design Problems In the process of checkout, initial operation, and preoperational or startup testinq design problems may be encountered. Such design problems are formally documented and reported to appropriate design organization representatives for resolution. Typical design problems include: Rev. 31, 7/82 14. 2-13
SSES-FS AH
- a. Errors or discrepancies in approved prospect design.
documents
- b. Items that represent a potential hazard to personnel safety Ce Proposed facility modifications to meet design objectives
- d. Pailure of a tested system or component to satisfy design requirements -or acceptance criteria
- e. Operating problems where operation is in accordance with desiqn xeguirements Design response for all such reported items is mandatory. Should "
the response require a facility modification, the appropriate design documents are revised and issued to the field. Subsequent control of these modifications is described in Subsection 14 2-4 5 14,2,4,5 . Cogtgo3.- of . gewgg~k Nodif~ition~s and- R~eaigs .A comprehensive listing of outstandinq work items is maintained for each system'during the Initial Test Program. This listing is maintained to ensure that identified work is performed. Typical listed work items include:
- a. Incomplete or incorrect equipment installation
- b. Equipment repairs {corrective maintenance)
- c. Approved facility modifications
- d. Hew or additional construction This work is performed by the construction organization, the plant maintenance staff or a contract organization in accordance with approved procedures. In any event, in order to maintain the required controls, formal authorization is required to perform the work. During the Preoperational Test Program, this written authorization is obtained from the ISG through implementation of the appropriate XSQ or Plant Staff administrative procedure.
During the Startup -Test Program, this written authorization is obtained from the Plant Staff through implementation of the appropriate Plant Staff administrative procedure. These administrative procedures, in addition to authorizing performance of the work, specify any retestinq required as a result of the work and document completion of both the work and associated Rev 30, 5/82 )4. 2-14
SSES-PSAR retesting. Closure. of the work list item requires completion of both the specified work and the speci'fied retesting, if required. 14.2.4.6 Test Phase prerequisites Completion of Phase I is a prerequisite of. Phase II for each system. The completion of Phase II on safety-related systems is a prerequisite for commencement of the Startup Test Program with the followinq exception: Startup Testing required to be completed prior to fuel loadinq as indentified in Pigure 14.2-5 may be implemented during Phase II. Completion of each major phase of the Startup Test Program is a prerequisite to starting the succeeding phase. Subsection 14.2. 11 identifies the specific testing scheduled to be conducted during each 'of these phases. A phase is considered complete only after the results of required testing are evaluated, reviewed, and approved, and test exceptions resolved per the requirements of Subsection 14.2.5. 14 2. 5 REVIEW~ EVALUATION~ AND APPROVAL OP TEST RESULTS PPSL has overall responsibility for reviev, evaluation, and approval of test results. The following sections establish the requirements for review, evaluation, and approval of individual test results, major test phase test results, and test plateau test results. 14.2,5.1 Individual Test Results Upon completion of a component test, the System Engineer assembles the test results and submits them to the Group Leader f or approval. Upon completion of a preoperational or a startup test, the test director assembles a test package that includes the official test copy of the procedure and all related documentation. The preoperational test package is submitted to the Test Reviev Board Chairman who disseminates copies of the test package to TRB members responsible for performing an in-depth review and evaluation of test results. Por startup test results the package is submitted to the chairman of PORC. Test discrepancies, deficiencies, and omissions identified Curing testing or durinq review of test results are documented as, test Re v. 31, 7/82 14. 2-15
SS ES-FS AR exceptions. Test exceptions occurring because of design problems are reported to appropriate design organization representatives for resolution per Subsection 14.2.4.4. Followinq TRB or PORC review and resolution of TRB or PORC comments, the chairmen have three options:
- a. Recommend that the entire test be repeated.
- b. Recommend that test results are unacceptable until all or par't of the outstanding exceptions are resolved, in which case the"test, packaqe is returned to the test director for further action.
co Recommend acceptance of test results with or without exceptions, in which case the test package is submitted to the appropriate approval authority for final review and approval. Final review and approval of preoperational test and startup test results is by the Superintendent of Plant. Final review and recommendation for approval of startup test results is by the Plant Operations Review Committee. Approval is by the Superintendent of Plant. r For test results approved with exceptions, each exception will be ~valuated and assiqned a required completion date relative to the different phases of the Initial Test Program. Test exceptions are .resolved by processinq them through the same review and approval cycle as associated test results.
- 14. 2. 5. 2 Ma jor Test. phase Test Result s Commencement of each major test phase of the Startup Test Proqram, requires that outstanding work items be reviewed and the Eollowinq commitments be. satisfied:
Commencement of Initial Fuel Loading requires that the preoperational test results of Figure 14.2-4 be reviewed and approved.
- b. Commencement of Initial Heatup and Low Power Testing requires that the Phase III startup test results be reviewed and approved.
c Commencement of Power Ascension Testinq requires that the Phase IV startup test results be reviewed and approved. R ev. 31, 7/82 14. 2-16
SS ES-PS AR 14,2,5,3 Power Ascension Testing Test Results Testing during the Power Ascension Test Phase is sequenced in distinct test plateaus. Prior to proceeding from one. Plateau to the next, the startup test results of the preceeding plateau are required to be reviewed and approved. 14 2. 6 TEST RECORDS A single copy of each approved procedure, denoted as the official test copy, is used as the official record of the test. Because of. the format of startup test procedures,'here will be one official test copy of a subtest for each Test Condition or plant operatinq condition in which the subtest is implemented. The completed official test records are assembled into a test package at the end of testing. This test package is retained in accordance with PPSL requirements for record retention. 14.2.7 COMFORNANCE OP TEST PROGRAMS HITH REGULATORY GUIDES l The safety-related performance requirements of the safety-related structures, systems, and components identified in Chapter 3 are tested in conformance with the regulatory positions established in the followinq regulatory guides or justification for exceptions is provided. Number Title 1- 20 Vibration measurements on Reactor Internals {Revision 2, Hay 1976) .
- 1. 41 Preoperational Testinq of Redundant On-site Electric Power Systems to Verify Proper Load Group Assiqnments {March 16, 1973) .
1.52 Desiqn, Testing, and Maintenance Criteria fo" Engineered-Safety-Peature Atmosphere Cleanup System Air Piltration and Absorption Units of Light-Hater-Cooled N uclear Power Plants (Revision July 1976) . Testing will be performed on the Control Structure Emergency Outside Air Supply System in accordance with the exceptions taken on Regulatory Guide 1. 52 in Section 3.13. Rev. 31, 7/82 14. 2-17
SS ES- PS AR 1.56 Maintenance of Hater Purity. in Boiling Mater Reactors ( Ju ne 197 3) .
- 1. 68 Initial Test Proqrams for Hater-Cooled January Reactors Power Plants (Revision 1, 1977)
(1)
Reference:
Section C. 1 of the Regulatory Guide. Testinq vill be conducted on safety-related structures, systems, and components identified in Table 14.2-1 as required by 10CFR50 (2)
Reference:
Section C.9 of the Regulatory G uide. The requirements of Preoperational Test results documen tation and. reportinq a re satisfied by the format and content of the completed test procedures; genera tion of additional reports is not contemplated. (3) 'eference: . Appendix A, Section 1. h (10) of the Regulatory Guide. Not applicable because SSES does not use containment recirculation fan for post accident containment heat removal. (4)
Reference:
Appendix A, Section 5.1.1 of the Regulatory Guide. The tvo pump trip is done at Test Condition 3 (approximately 100% core flov and 75% power) . {5)
Reference:
Appendix A, Section S.c.c of the Regulatory Guide. Demonstration of the operability of liquid radioactive vaste system is provided in the preoperational test program. No additional testing is necessary during the power-ascension test phase.
- 1. 68. 1 Preoperational and Initial Startup Testing of Feedwater and Condensate systems for Boiling Mater Reactor Power Plants (Revision 1, January 1977).
Testing may be limited by the availability of auxiliary steam. Rev. 31, 7/82 14. 2-18
SSES-PSAR 1 68 2 Initial Startup Test Program to Demonstrate Remote Shutdovn Capability for Mater-Cooled Nuclear Pover Plants (January 1977) .
- 1. 70 Standard Format and Content of Safety Analysis Reports for Nuclear Power Plants (September 1975) .
- 1. 80 Preoperational Testing of Instrument Air Systems (June 1974) . ~
The Instrument Air System is not safety related. However, the various components in the Instrument Gas System vill be tested to verify that they fail as designed per the statement in Section 3.13. The movement of affected valves will be verified as part of the test associated with each respective valve's corresponding system test. The action and flow of decay air is not an essential criteria of operation in relation to the affected valves. The valves are to fail with loss of qas to a safe position. Hhether decaying pressure vill h old some or all of the valves (except for those on the affected line) in normal operating positions is not of critical importance.
- 1. 104 Overhead Crane handlinq Systems for Nuclear Power Plants (Pebruar y, 1976) .
Exceptions for testing of the cranes are. outlined in Section 3. 13.
- 1. 108 Periodic Testing of Diesel Generators Used as Onsite Electric Pover Systems at Nuclear Power Plants (Auqust 1977) .
The testing of diesel generators will conform to Regulatory Guide 1. 108 per regulatory position 20 ao Since sequence of events capability was not part of the desiqn, testing will also take the same exceptions as outlined in Section 3.13.
- 1. 140 Design. Testing and maintenance criteria for normal ventilation exhaust system air filtration and absorption units of light-water-cooled nuclear power plants (Revision 1) .
Preoperational testing vill comply with regulatory position C.5. Rev. 31, 7f'82 14. 2-19
SSES-FS AR 14 2 8 UTXLIZATXON OP REACTOR OPERATING AND TESTING PXPEQIENCE IN THE DEVELOPMENT OF THE TEST PROGRAM The Manager-Nuclear Support is responsible for ensuring that reactor operatinq and testinq experiences of similar power plants are made known to the ISG and the Plant Staff during the Initial Test Proqram. The primary sources of experience information are NBC License Events and experiences of 'industry contacts. This information will be sorted and reported for a period of two years orior to fuel load on the first unit. The Manager-Nuclear
., Support is addressed in Subsection 17.2. 1.
14.2.9 'TRIAL USE Og PLANT OPERATING AND EMERGENCY PROCEDURES The adequacy of Plant Operating and Emergency Procedures will be confirmed by trial-use during the Initial Test Program. Those procedures that do not require nuclear fuel are confirmed adequate to the extent practicable furing the Preoperational Test Program. Those procedures that require nuclear f uel are confirmed adequate to the extent practicable during the Startup Test Program. The plant operating staff is responsible for confirmation of operatinq and emergency procedures. The Superintendent of Plant ~ ;,'i.. responsible for ensurinq that comments/changes identified during confirmation are incorporated in finalized procedures. It is not intended that preoperational test procedures explicitly incor porate or. ref ere nce plant oper ating and em er gene y procedures. These tests are intended to stand on their own since they are not necessarily compatible with configurations and conditions required for confirmation of facility operating and emerqency procedures. Startup test procedures will incorporate and reference plant operatinq and emergency procedures to the ex ten t prac tica 1.
- 14. 2. 10 I(ITILL CRUEL LOADING A$ D I NIT IAL CRITICALITY Initial fuel loading is accomplished in accordance with startup test procedure, ST-3 Fuel Loading. Initial criticality is accomplished in accordance with startup test procedure ST-4, Pull Core Shutdown Marqin. These procedures comply with the general quidelines and. regulatory positions contained in'Regulatory Guide 1.68 (Revision 1 January 1977). Test abstracts establishing the
~
objectives, prereguisites, test method, and acceptance criteria for these procedures are presented in Subsection 14.2.12. Rev. 31, 7/82 14 2- 20
SSES-FS AR 14 ~ 2. 11 TEST PROGRAM SCHEDULE The Preoperational Test Program is scheduled for 15 months duration on the Unit 1 and Common components and for 12 months duration on the remaininq Unit 2 components {see Figure 14.2-4a and 14.2-4b) . The subsequent Startup Test Proqrams are scheduled for six months on each unit. The Preoperational Test Program sequential test schedules presented on Fiqures 14.2-4a and 14.2-4b offer one possible plan for an orderly and efficient proqression of the proqram. Mhile these sequences may be preferred, numerous alternatives exist. The schedule will be updated periodically at the jobsite to reflect construction status, manpower availability, a nd the required test prerequisites. The safety-related structures, systems, and components will be preoperationally tested. The Preoperational Test Procedures are scheduled to be developed from September 1977 to January 1979. The schedule of Unit 1 and Unit 2 Startup Tests is presented in Figure 14.2-5. This schedule establishes the required testing as a function oX test condition. The test conditions are described on Fiqure 14.2-6. All testing is assigned to a specific test condition for convenience even thouqh some testing, as identified in fiqure 14.2-5, is performed outside the bounds of the assigned test condition. Not all subtests of a Startup Test are performed at each assigned test condition. Startup testing will be divided into three Najor Test Phases, and, within the Power Ascension Test Phase into distinct test plateaus. The testing included in each Major Test Phase and test plateau is described in Table 14.2-4. Even though this basic order of testing is required, there is till considerable flexibility in sequencing the startup testinq specified to be conducted at each plateau. Detailed startup testing schedules, commensurate with the requirements of this schedule, will be developed at the job site. 14 2. 12 INDIVIDUAL TEST DESCRIPTIONS The individual preoperational tests to be conducted on safety-related structures, systems, and components are listed in Table 14.2-1. The abstracts of these preoperational tests are contained in Subsection 14.2.12.1 in numerical order. The Test Proqram procedures are listed in Table 14. 2-3. The'tartup abstracts of Startup Test procedures are contained in Subsection
- 14. 2. 12. 2 in numerical order. The abstracts identify each test by title and number, describe the test objectives, specify the test prerequisites, provide a summary description of the test method, and establish the test acceptance criteria.
Rev. 31, 7/82 14. 2-21
SSES-FSAR
- 10. 2. 12. 1 pgeogerational Test Procedure Abstracts QP2,1) 125 Volt DC System Preoperationa1 Test Test Objective To demonstrate the ability of the 125 Volt dc system to perform the followinq:
The batteries can endure a complete discharge, based on their ampere hour ratinq, without exceeding the battery bank minimum voltaqe Iimit. (Performance Test)
. B. - The batteries can provide reliable stored energy to selected loads, indicated in Table 8. 3-6, in the, event of a desiqn hase accident. (Service Test)
C. The battery charqers can deliver their rated output. D The battery chargers can fully charge their associated batteries .from design minimum charged state (i.e., after the service test) simultaneously providinq power to the distribution panels for normal station loads. -;.';...,"~..E. That .the alarms operate and annunciate at their specified abnormal condition. F. The reliab'le 125V DC power is delivered to the ESF DC distribution panels. Ppere guisites Construction is complete to the extent necessary to perform this test and the system is turned over to the ISG. Required calibration and operation of instruments, protective devices, and breakers is verified. 080V AC Power, Resistor Load Bank, Battery Room Ventilation and Emergency Eyewash is available
,'and/or in service.
Test method The Battery Performance Test is manually initiated by connectinq the battery bank to "the resistor load bank and discharqinq the batteries at a constant current,. for a specified period of time. The Battery Service Test is manually initiated by connectinq the battery bank to the resistor load bank and simulatinq, as closely as possible, the load-"the batteries will supply during a desiqn base accident. Then the battery charger is connected to the batteries and the distribution that they can charge the batteries while simultaneously panels.to'erify providinq power to- the normal plant loads. The battery charqer is also connected to the resistor load bank and current is increased to its maximum rating with the charger isolated from its associated battery bank. Alarms are simulated and verified to be operated properly. Re v. 31, 7/82 10 2- 22
SS ES- PS AR Acceptance criteria - The batteries can satisfactorily deliver stored enerqy for the specified amount of time as required for the Performance and Service Test. The battery chargers can deliver rated output and can charge their associated battery bank from minimum voltage to a fully charged state in a specified amount of time while simultaneously supplying normal plant loads. The alarms operate at their engineered setpoints and annunciate in the Control Room. /F4.1$ 4.16 kV System Preoperational Test Test Objective To demonstrate the proper operation and load-carrying capability of .breakers, switchgear,'ransformers, and cables. Also to demonstrate proper operation of protective devices, relaying and logic, transfer and trip devices, permissive and prohibit interlocks, and instrumentation and alarm s. Prereguisites Construction is completed to the extent necessary 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 including 125 volt dc systems are operable. Test rtethod The 4. 16 KV system is energized. Required controls are operated or simulated signals are applied to verify proper operation of protective devices, relaying and logic, transfer and trip devices, permissive and prohibit interlocks, instrumentation and alarms, breakers, switchgear, transformers and cables. Acceptance Criteria - The system performance parameters are in accordance with applicable desiqn documents. QP5.1) 480 Volt System Pgeoperational Test Test Objective To demonstrate the capability of the 480 Volt Load Centers and 480 Volt No)or Control Centers systems to provide electrical power to connected 480 Volt Load Centers and Motor Control Centers by demonstratinq the prope'r operation of breakers, transfer and trip devices, relaying a nd logic, permissive and prohibit interlocks, instrumentation and alarms, motor-generator sets, and automatic transfer switches. Preregui~ites Construction is completed'o the extent necessary to perform this test and the system is turned over to the ISG. Required electrical power supply systems are available to energize the 480 Volt system. Required instruments and protective relays are calibrated and controls are operable. Test method Peeder breakers are opened and closed by operating or simulatinq controls. Voltaqes on the bus being fed are measured to verif y breaker operations, relaying and logic, R ev. 31, 7/82 14. 2-23
SSFS-FS AH permissive and prohibit interlocks and alarms. Signals are applied to verify alarms and instrumentation. Buses are de-enerqized and energized to verify automatic transfer, switch transfer ~ and re-.transfer and motor-generator set operation. Acceptanre CX;itegia The system performance parameters are in accordance with applicable design documents.
/Pl'.3,1} Fire Protection Water Systems Test Objective - To demonstrate the proper operation of the Fire Protection Water System. The test will specifically demonstrate the f ollowinq:
For Unit <<1 testing: Automatic and manual operation and reliability of the 1) fire pumps OP511 and OP512.
- 2) Yard Loop Integrity and ability to provide water any flow path to yazd fire hydrants. 'hrough
- 3) Hose Stations in Unit 1 and common are operational. and water is available to the stations.
- 4) Automatic and manual operation of the Unit one and common sprinkler systems.
='or Unit <<2 testing:
- 1) Hose stations in Unit 2 are operational and water is available to the stations.
- 2) Automatic and manual operation of the Unit 2 sprinkler systems.
Prerequisite Construct'ion is complete to the extent necessary to perform t'his test and the system is turned over to XSG. acquired instruments are calibrated and controls are operational. The river water makeup system, instrument air system, and the required electrical power supplies are available. Test Nethod The operating modes are initiated manually and, where applicable, automatically. Fire pump per formance is determined for OP511 and OP512. Automatic and. manual initiation of the individual sprinkler systems are conducted. Flow tests are conducted on end of line f ire hydrants. Flow verif ication is established at the hose stations. Required controls are operated or simulated signals are applied to verify proper operation and proper alarm annunciation locally and remotely. Rev. 31, 7/82 14. 2-24
Acceptance Cgiterga The system performance parameters are in accordance with applicable codes and design documents. QP13,2} Carbon Dioxide Pire Protection System Test Objective To demonstrate the proper operation of the CO fire extinguishing system. The test will specifically demonstrate the following:
- 1) The CO2 storage tank and refriqeration system operate automatically to maintain the concentration of CO2 in the tank.
- 2) The proper operation of the CO2 automatic flooding systems.
- 3) The proper operation of the manual spurt C02 systems.
Prerequisite Construction is complete to the extent necessary to perform this test and the system is turned over to ISG. Required instruments are calibrated and controls are operational. The required electrical power supplies are available. Test method The operating modes are initiated manually and, where applicable, automatically. Required dampers and ducts close off the hazard area. The timers for CO2 discharge agree with design criteria. The required controls are operated or simulated signals and are applied to verify system interlocks and alarms. Acceptance Cgiteria System performance parameters are in accordance with applicable codes and design documents. QP13. 3Q Fire and Smoke Detection Systems
=
Test Objective To demonstrate the proper operation of the Smoke Detection System and related alarms. Pire'nd Prerequisite Construction is complete to the extent necessary to perform this test and the system is turned over to ISG. The required instruments are calibrated and controls are operational. The required electrical power supplies are available. Test method The fire and smoke detector system required controls and instruments are operated or simulated signals are applied to ensure proper operation of interlocks and alarms. Acceptance Criteria The system performance parameters are in accordance with applicable codes and design documents. Be v. 31, 7/82 14. 2-25
SS ES-FS AR Test Objective To demonstrate proper operation of the tkalon Fire Protection system and related alarms. Prerequisite - Construction is complete to the extent necessary to perform this test and the system is turned over to ZSG. Required instruments are calibrated and controls are operable. Required electrical power supplies are available. Test Method The operatinq. modes are initiated manually and automatically. The required controls are operated or simulated siqnals are applied to verify system interlocks and alarms. Acceptance Criteria The system performance parameters are in accordance with the applicable codes, and design documents. (P14.1) Reactor Buildinq Closed Cooling Water System RKeopergtigQg], Test objective To demonstrate the Reactor Building Closed Cooling Water System functions as designed. Prerequisite Construction is comple'te to the extent necessary 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. The Service Mater System, Instrument Air System and 'a makeup water source for the RBCCM System are available. Test Method The system operation is initiated manually and .the performance of the pumps is determined. Required controls are
~"
operated or simulated siqnals are applied to verify; automatic chanqe of Service Mater flow from RBCCM System with changes in the closed cycle water temperature; and system interlocks and alarms. Acceptance Criteria The system performance parameters are in .-',':" accordance with the applicable design documents. (P16.1) RHR Service Water Svstem Preooerational Test Test Qbjectiye To demonstrate the capability of RHB Service Mater System to provide cooling water to connected components/systems and the ability of the system controls to alarm when abnormalities occur in the system and to operate in accordance with design intent. Pgegeguisites Construction is complete to the extent necessary 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. The R ev. 32, 12/82 14. 2-26
SS ZS- FS AR spray pond and a make-up water source to it are available. RHR Emerqency Service Water is required to conduct the flow balancing test. 'Fest Method System operation is initiated manually and where applicable automatically. The system is operated in the system design modes and RHR service water pump performance is determined. Required controls are operated or simula ted signals are applied to verify automatic loop/valve aliqnments, system interlocks and alarms. Acceptance Criteria The system performance parameters are in accordance with applicable design documents. QP17,1$ Instrument ac power System Preoperational Test Test Objectives To demonstrate the ability of the 120V Instrument AC Power System to perform the following: A. That full load power is delivered to the four class 1E electrically independent ESP load groups. That full load power is delivered to the two non-class 1E distribution panels azd that their automatic transfer switches shift load to their emergency sources upon loss of their normal sources, and back to normal power when it is restored. C. That the alarms operate and annunciate upon loss of power. D. That the four class 1E ESP distribution systems are electrically isolated from each other. Pxereguisites Construction is complete to the extent necessary to perform this test and the system is turned over to the ISG. The alarms operate properly, and 480V AC power and resistor load bank are available. Test Method The four class 1E ESP distribution=panels are energized by manually closing their re'spective feeder breakers. A resistor load bank is connected to each distribution panel and current is increased to full load while maintaining required voltage of the three other distribution panels still energized. The remaininq panel is de-energized to show that it does not affect the operation of the other three distribution panels.- the (This is performed for all four distribution panels.) Also, undervoltaqe alarms are checked when each panel is de-energized. The two non-class 1E distribution panels are also energized b y manually closinq their respective feeder breakers. A resistor load bank- is connected to each distribution panel and current is increased to full load. The automatic transfer switch normal supply breaker is manually opened to simulate a loss of normal R ev. 31, 7/82 14..2- 27
SS ES-7S AR power and the output voltage of the distribution panel is monitored to verify that the supply voltage switched from normal to emerqency in a specified time period. The emergency supply breaker, is opened and the output voltage of the distribution panel is monitored to verify that output voltage is not present. The emezqency supply breaker is closed and the normal supply breaker is closed to restore normal power..Output voltage is monitored to verify that supply voltage switched from emergency to normal in the specified period of time. The 'non-class 1E distribution panel undervoltaqe alarms are verified when both normal and emergency supply" b'reakers in the automatic transfer switches are opened. Acceotance C:rigeria That reliable 120V AC Power, at design load, is supplied to all instrument buses. That loss of normal supply to the automatic transfer switches causes a shift, in a specified time period, to the emergency supply and vice-versa when normal supply voltage is restored. That the four class 1E distribution panels are electrically isolated from each other and that loss of power alarms operate and annunciate in the Contxol Room A/23 1) Diesel guyl
\
Oil System preoperationgg Test Tegt. objectivye - To demonstrate that the diesel fuel oil system is capable of supplying fuel oil to connected plant equipment. Prerequisite - Construction is complete to the extent necessary to perform this test and the system is turned over to the ISG. Required instrumentation is calibrated and controls are operable. Required electrical power supply systems are available. The diesel oil storage tank is at its normal operating level. Test Method - System operation is initiated manually. The performance of the diesel transfer pumps is determined and the diesel day tank capacity is verified. Simulated siqnals are applied to verify system interlockp and alarms. Acceptance Criteria The system performanco parameters are in accordance with the applicable design documents. QP24.1$ Diesel Generator System preoperational Test Test Objective To demonstrate system reliabi'lity, proper voltaqe and frequency regulation under transient and steady-state conditions, pxoper loqic correct setpoints for trip devices, and proper operation of initiating devices and permissive and prohibit interlocks. Startinq, cooling, heating, ventilating, lubricating and fueling auxiliary systems will also be tested to demonstrate that their performance is in accordance with design. Rev. 31, 7/82 14. 2-28
SS ES- PS AR Pregeguisiteg Construction is complete to the extent necessary to perform this test and the system is turned over to the ISG. Required instruments are calibrated and controls are operable. Emergency service, water, Diesel Building HGV, 125 Volt dc Power, and Instrument Air are available. The diesel oil day tank is filled and a make-up source is available. Test Method - System operation is initiated manually and diesel generator capability to start and attain rated voltage within the specified time are verified. Diesel qenerators are loaded to the rated load and the performance is determined. Required controls are operated or simulated signals are applied to verify automatic start, sequential loadinq, D-G protection, load rejection capahility and other system interlocks and alarms. Reliability is demonstrated throuqh 69 consecutive v'alid start. tests of station diesel qenerators, with a minimum of 23 valid start tests per individual diesel generator. Acceggagce Criteria The system performance parameters are in accordance with the applicable design documents. tP25. 1) Primary Containment Instrument Gas System Preoperational Test Test Objectives - To demonstrate that the Containment Instrument Gas s yst em fu nc tions as des iqn ed. Prerequisite Construction is complete to the extent necessary 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, the Reactor Building Closed Coolinq Rater System and Instrument Air System are available. Test Method System operation is initiated manually to determine the performance of compressors, moisture separators, dryers and filters. Required controls pre operated or simulated signals are applied to verify; instrument air system backup, isolation on primary containment isolation signal, and other system interlocks and alarms. Acceptance Criteria - The system performance parameters are in accordance with the applicable desiqn documents. QP28,1} ESSQ Pumphouse HSV System Preoperational Test Test objective To demonstrate the capability of ESSN Pumphouse Heating and Ventilating System to maintain the required ambient temperature inside the ESSH Pumphouse. Pgegequisite - Construction is complete to the extent necessary to perform this test and the system is turned over to the ISG. Rev. 31, 7/82 14. 2-29
SSZS- FS AR Required instruments are calibrated and controls are operable. Required electrical power supply systems and the Instrument Air System are available. Test Method System operation is initiated manually and the fan air flow, damper operation, heater operation and ambient conditions inside the pumphouse are determined. Required controls are operated or simulated signals are applied to verify fan(s) automatic starts with associated pump starts and system interlocks and alarms. Acceptance Cgitegia The system performance parameters are in accordance with the applicable desiqn documents. (P28. 3) Diesel Generator Building Heating and Ventilation System preoperationag Test Test Ohjective - To demonstrate the capability of the system to maint ain the required ambient tern pe ratures inside the diesel generator building. Prereguisite - Construction is complete to the extent necessary 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, the Instrument Air System and Control Structure Chilled Mater System are available. Test Method System operation is initiated manually and fan air flow, damper operation, heater operation and ambient temperatures inside the diesel generator buildinq are determined. Regulred controls are operated or simulated signals are applied to verify fan automatic starts with associated D-G starts and system interlocks and alarms. Accep+ance Criteria The system performance parameters are in accordance with applicable design documents. QP30,jg Control Structure HCV system Preoperational Test Test Objective - To demonstrate the operability of the Control Structure HCV System and its interlocks inside the control structure buildinq to demonstrate this system's'bility to maintain a positive pressure above atmospheric during normal operation and high radiation signal when the emergency outside air supply mode i.s runninq. To demonstrate the ability of the Control Structure HCV to isolate before chlorine reaches the isolation dampers when chlorine is detected in the outside air intake. Prerequisite Construction is complete and the system is turned over to the ISG. Required instruments are calibrated and controls are operable. The Contxol Structure Chilled Mater Rev. 31, 7/82 10. 2-30
SSES-PS AR System, Instrument Air System and turbine building vent are available. Required electrical power supply systems are a va ila hie. Test Nethod The system operation is initiated manually and fan performance, damper operations and heating element operation are determined. The differential pressures with respect to outside atmosphere are measured. Required controls are operated or simulated signals are applied to verify the emergency filter operation on hiqh radiation signal, automatic recirculation on high chlorine signal, system manual isolation and other system interlocks and alarms. Acceptance Criteria The system performance parameters are in* accordance with the applicable desiqn documents. QP3g,g) Control Structure Chilled pater System Preoperational Test Test Objective To demonstrate the ability of the Control Structure Chilled Mater System to 'provide chilled water flow to Control Structure Heating/Ventilating Units and Control room floor and computer room floor cooling units. Prereguisite, Construction is complete to the extent necessary to perform this test and the system is turned over to the ISG. Required instruments are calibrated and controls are operable. The Service Mater System, Emerqency Service Mater System, and Instrument Air System are available. Required electrical power supply systems are available. Test method The system is operated to demonstrate chiller operation and chilled water pump performance. Required controls are operated or simulated signals are applied to verify automatic alignment of the system under emergency conditions (start of emerqency condenser water recirculation pump) and other system interlocks and alarms. Acceptance Criteria The system performance parameters are in accordance with the applicable design documents. QP34,1$ Reactor Building HSV ac@stem preopergtj,onal Test Test objective - To demonstrate the capability of the Reactor Building HSV System to maintain the required thermal. environment inside the reactor building. Prerequisite~ Construction is complete to the extent necessary to perform this test and the system is turned over to the ISG. Required instruments and controls are operable. The Instrument Air System is available. Required electrical power supply systems and Reactor Building Vent are available. The Reactor Building ventilation flow balancing, High Efficiency Particulate Re v. 31, 7/82 14. 2-31
SS ES- FS AR Air (HEPA) filter and charcoal absorber efficiency, and in-place leak tests are completed. Test Method - The system is operated to measure the fan performance and determine the capability to maintain the Reactor Building at negative pressure within the required thermal environment and areas of qreater potential contamination at a lower pressure than the rest of the building. Required controls are operated or simulated signals are applied
'to verify the system isolation on LOCA and/or high radiation signal, and other system interlocks and alarms.,
Acceptance Criteria The system performance parameters are in accordance with the applicable design documents. -'A&34. 2} Reactor Bhilding Chilled Mater System Preoperational Test Test Objective To demonstrate that the Reactor Building Chilled Mater System provides the required cooling water to connected coolers under normal and emergency conditions. Prerequisite - Construction is complete to the extent necessary to perform this test and the system is turned over to the ISG. Required instruments are calibrated and controls are operable. The Reactor Buildinq Closed Coolinq Mater System, Service Mater System, Instrument Air System, Make-up Demineralizer Mater System and required electrical power supply systems are available. Test Method The system is operated to demonstrate the chiller and chilled water pump operation. Required controls are operated or simulated signals are applied to verify system isolation, automatic valve aliqnment, equipment operation under emergency
-,c:ondition and system interlocks and alarms.
p'cceptance Criteria The system performance parameters are in accordance with the applicable design documents.
)P45,1) Peedwateg System preoperational Test Test objectives The general objective of this test is to demonstrate proper operation of the Feedwater System. This will be accomplished to the extent possible utilizing the Auxiliary Boilers as a steam supply. The test will specifically demonstrate: ~
- 1) All RFP and RFPT instruments have been calibrated in accordance with the vendor's instruction manuals and inst rumen t da ta sheets.
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- 2) All RFP and RFPT alarm and trip points have been set properly.
Rev. 31, 7/82 14. 2-32
SS ES- PS AR
- 3) - All recorders, indicators,,annunciators, and computer inputs function correctly.
Preregui sites
- 1) Construction is complete to the extent necessary to perform this test and the system is turned over to the ISG
- 2) The Service Mater System is operational.
- 3) The Hain Turbine Lube-Oil System is filled and operational.
- 4) The Instrument Air System is operational.
- 5) The Computer is operational to the extent necessary to verify inputs from the feedwater system.
- 6) The 480 volt motor control centers necessary for this test are operational.
- 7) The 250 volt DC control centers necessary for this test are operational; ~
- 8) RPPT A~ B, and C Lube-Oil reservoirs are filled.
Test Nethod Normal and emergency responses of the lube oil and turbine trip systems are, verified following simulation or process manipulation of the controlling variable. Acceptance Criteria
- 1) Interlocks of, the reactor feed pump turbine (RPPT) and of the alternate and emergency lube oil pumps and their corresponding alarms function as designed.
- 2) All abnormal conditions providing trip signals to the RPPTs function as designed.
(P45.2l Feedwater Control Svstem Preotierational Test Test Qbgectiyes - The qeneral objective of this test is to demonstrate proper operation of the Peedwater Control System. This will be accomplished to the extent. possible without actually pumpinq water with the feed pump turbines. The test will specifically demonstrate:
- 1) All feedwater control instruments have been calibrated over their full ranqe in accordance with the vendors instruction manuals and instrument data sheets.
Re v. 31, 7/82 14. 2-33
SS ES- FS AR
- 2) All feedwater alarm and trip points have been set properly.
- 3) All recorders, indicators, annunciators, and computer inputs function correctly.
- 4) Interlocks to the main turbine, recirculation system, and feed pumps function correctly.
Feedwater control signals to the start-up regulatinq valve and turbine-dri ven feed pumps function correctly vith simulated inputs and step commands oriqinatinq from their respective control stations. Prereguisites - The prerequisites for this test are as follows: Construction of the system is complete to the extent required to conduct this test and the system is turned over to the ISG. The 125 Volt DC system is operational. The Instrument AC system is operational.
- 4) The 24 Volt DC system is operational.
- 5) Panel 1C651 annunciator is energized.
Test Method Various level, flov, pressure, and speed signals will be simulated and the proper responses vill be verified. Acceptance Criteria The reactor, main steam, and feedvater pressure and flow indicators, recorders, computer inputs, and trip points respond within designed tolerances.
- 2) Speed requlation re'sponse of each RPP Turbine is within des ign limits.
- 3) The response of the startup regulating 'valve is vithin design tolerances.
Chanqes in the control mode, selection of control channels, or integrity of incoming signal do not produce adverse changes in the controlled variables. ~$ 49. 1~ Residua~ Heat Removal System ~>reo~erationa l Test Test Objective - To demonstrate that the Residual Heat Removal System (RHRS) delivers cooling water as designed for each of the following system modes of operation: shutdown coolinq, Rev. 31, 7/82 14. 2-34
SSES-FSAR suppression pool spray, low pressure coolant injection (LPCI), suppression pool cooling, and fuel pool coolinq. Demonstrate operability of interlocks and isolation valves provided for overpressure protection from the reactor coolant system. Testing will include demonstratons of proper operation of initiating devices, correct logic, proper operation of bypasses, proper operation of prohibit and permissive interlocks, and proper operation of equipment protective devices that could shut down or defeat the operation or functioning of such feature..
'I Pregeguisites Construction is complete to the extent necessary 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 and the Instrument Air Systems are available. Reactor pressure vessel, suppression pool, fuel pool, and fuel pool skimmer surge tank are filled up to required level to provide enough suction head to the BHR pumps. Makeup water sources are available. Test Method The operatinq modes of the system are initiated manually and ~where applicable, automatically., RHR pump performance is determined for each operating mode. Control devices are operated or simulated signals are applied to verify valve alignment, LPCI mode operation for low reactor water level and high drywell pressure, and other system interlocks and alarms. Acceptance Criteria The system performance parameters are in accordance with applicable engineerinq design documents. gP50,1$ Beactor Core Isolation Coolinq System Preoperational Test Test Objective To demonstrate the capability of the Reactor Core Isolation Coolinq (RCIC) System to deliver water to the reactor pressure vessel. Prereguisites Construction is complete to the extent necessary to perform these tests and the system is turned over to ISG. Required instruments are calibrated and controls are operable. Required electrical power supply systems and the Instrument Air System are available. Suppression pool and condensate storage tank are filled to provide enouqh suction head to RCIC pump and reactor pressure vessel is available to receive water. Auxiliary steam is available for RCIC turbine operation. Part of the RHR system will also be available to provide a suction flov path for RCIC pump Vest Method The system operation is'nitiated manually and automatically. The system is operated to determine the R ev. 31, 7/82 14. 2-35
SS ES-FS AR performance parameters for the RCIC turbine and pump and the barometric condensate pump. Control devices are operated or simulated signals are applied to verify automatic valve alignment (system isolation), turbine trip and start modes, and other sys te m inter locks a nd alarms. Acceptance Criteria The system performance parameters are in accordance with applicable engineering design documents. Test Objectives To demonstrate the ability of the Core Spray System to accept water from both the suppression pool (normal) and the condensate storage tank (backup) and deliver flow at adequate pressure to the reactor pressure vessel in an acceptable spray pattern. Prerequisites Construction is complete to the extent necessary to perform these tests and the system is turned over to the ISO. Power and control voltage is available for the motors, valves and instruments associated with this system. Reguired instruments are calibrated and controls are operable. The suppression pool and condensate storage tanks are filled to the required level. The. reactor pressure vessel head. is removed and the. vessel can accept water. The condensate transfer system is available. Test Method The normal system operation is initiated automatically by simulating a Design Base Accident. The pumps are started and the appropriate valves and instruments are operated to ensure that water flow is established to the reactor pressure vessel. System logic, interlocks, and alarms are verified to be in accordance with design intent and system flows and pressures are verified to ensure that they are adequate to inject water into the reactor pressure vessel via the core spray spargers. The system is operated manually through the test line back to the suppression pool. Also, the system is manually lined up to accept water from the condensate storage tank and deliver core cooling water to the reactor pressure vessel. Acceptance Criteria,a That the core spray system can deliver cooling water at design flow and pressure to "the reactor pressure vessel within a specified period of time for-'arious simulated operating conditions. JP51. 1A} Core Saga)( System Pattern preo~egatio~nl Test Test Objective To demonstrate the ability of the Core Spray System to deliver a proper spray pattern at rated'nd runout conditions. This procedure shall also verify satis factory "physical response of system components within the reactor pressure vessel. The system discharge line restriction flow R ev. 31, 7/82 14. 2-36
SS ES-FS AR orifices shall be verified as being properly sized such that runout flow does not exceed system de'sign values. Prereguisites Construction is complete to the extent necessary to perform this test and the system is turned over to the ISG. Power and control voltage is available for the'motors'alves and instruments associated with this system. Required instruments are calibrated and controls are operable. The suppression 'pool is filled to the required level. The reactor pressure vessel head is removed and the vessel can accept water. The condensate transfer system i.s available. Test Method System operation shall be manually initiated, monitored and controlled such that vessel injection is achieved in accordance with test objectives. Acceptance Criteria The Core Spray System can deliver cooling water at desiqn flow with an acceptable spray pattern to the reactor pressure vessel. Durinq this test photographic records shall be made, no system abnormalities shall be observed, restriction flow orifices shall be properly sized, and free route from the core spray junction box vent holes shall be verified. (P52. 1) High Pressure Coolant Injection System Preoperational Test Test objective To demonstrate that the High Pressure Coolant Injection System (HPCIS) delivers coolant water to the reactor. Pregeguisites Construction is complete to the extent necessary to perform this test and the system is turned over to ISG. Required instruments are calibrated and controls are operable. The suppression pool and condensate storage tank are filled to provide the required suction head to the HPCI pump. The reactor pressure vessel head is off and the vessel is ready to receive water from the HPCI system. Required electrical power supply systems, Standby Gas Treatment, required ventilation systems and Instrument Air System are available. The Auxiliary Boiler or another source of steam supply is available to run the HPCI t urbine. Test Method System operation is initiat'ed manually and where applicable automatically. Reactor water low level and drywell high pressure signals are simulated to verify HPCI turbine automatic functions. System isolation is verif ied by operating required controls and or simulated signals. Steamline high differential pressure signals are simulated to verify automatic functions. Limited turbine and pump operation {depending upon auxiliary steam conditions) and automatic valve alignment are demonstrated. Containment isolation valves are functionally tested. Required controls are operated or simulated signals are applied to verify interlocks trips and alarms. Rev. 31, 7/82 14. 2-37
SS ES-7S AR Acceptance Criteria The system performance characteristics are in accordance with applicable design documents. Test Objective To demonstrate the operation of the system with demineralized water. Demonstrate operability of inst rumentation, controls, interlocks, and alarms. Verify operability of heaters, air sparqers, and heat tracinq. Conduct test firings of squib-actuated valves, and demonstrate design injection capability. Tests should be conducted as. appropriate to verify redundancy and electrical independence. Prereguisites Construction is complete to the extent necessary to perform this test and the system is turned'over to the ISG. Required instruments are calibrated and controls are operable. The reactor vessel is available to receive water injected from the Standby Liquid Control System. Required electrical power supply systems and a source of demineralized makeup water are a va ilah 1 e. Test. Method System operation is initiated manually. Demineralized water is used for testing the system. The pumps are run taking suction from the'standby liquid storage tank and the test tank. Squib valves are fired and the rate of demineralized water injection into the reactor vessel from each pump is measured. Required controls are operated or simulated signals are applied to verify interlocks and alarms. Acceptance Cgitegja The system performance characteristics are in accordance with the applicable design documents. gP54,1) Bpergency Service Mater System Preoperational Test Test Oh]ective To demonstrate that the Emergency Service Mater System provides a supply of cooling water to the plant emergency equipment, to demonstrate the ability to start the ESM pumps from the remote shutdown panel, to demonstrate the ability of an ESM pump to start automatically when the associated diesel-generator unit starts, to demonstrate the proper operation of system automatic valve transfer schemes, and to demonstrate the proper operation of spray pond components. Pgereguisites Construction is complete to the extent necessary 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. The spray pond is filled to provide enough suction head for the ESM pumps, and a makeup source to the spray pond is available. The RHR service water system is in operation. Re v. 31 ~ 7/82 14. 2-38
S SES- PS AR Test Method The system is 'started manually and automatically throuqh the associated diesel generator start siqnal. Pump flow paths are established and pump flows are measured for each loop. Plow balancing of the RHR Service Water System and Emergency Service Water System is performed. Proper operation of the line break detection system is verified. Required controls are operated and simulated siqnals are applied to verify interlocks and alarms. Acceptance Criteria The system performance parameters are in accordance with the applicable design documents. Test Objective - To demonstrate the operation of the Control Rod Drive System including control rod drive hydraulic system and CRD mecha nis ms. Prereguisites Construction is complete to the extent necessary 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. The condensate storaqe tank is filled to provide enough suction head to the CRD pump. The TBCCW System and Instrument Air System are available. The Reactor Manual Control System is operational to the point required for continuing with this test. Initial couplinq and ventinq is completed. Test Nethod System operation is initiated manually and the svstem flow and pressure control stations are adjusted. CRD pump performance parameters are measured. Control rod drives are exercised to verify, position indication and insert/withdraw speeds. Scram tests are conducted and scram times are measured for each control rod drive. Required 'controls are operated or simulated signals are applied to verify system 'interlocks and alarms. R od bu ffer per f ormance is also tested. 0 Acceptance Criteria System performance parameters are in accordance with the applicable design documents. QP56. 1AQ Reactor manual Control System Preoperational Test Test Objectives To verify the operation of the Reactor Manual Control System, includinq relays, control circuitry, switches, rod blocks, indicatinq lights and control valves. Prereguisites Construction is complete to the extent necessary to perform this test and system is turned over to the ISG. Required instruments are calibrated and controls are "operable. Required electrical power supply systems are available. Rev. 31, 7/82 14. 2-39
SS ES- FS AR Tc.st Nc./had System inteqrated operation i'nit Controls are operated and simulated siqnals are applied t.o iaterl manually. verif y: rod blocks, alarms and intr rlocks of the reartor mode switrh; proper operation of the rorl position information sy tern; <<nd rorl drift alarm circuit directional control valvr. time sequence for insert and withdraw commands. Appar pgaLicr. (:gigc gga - The system performanc>> par<<metr rs <<re in acrordanre with the applicable desi qn documents. Tegt. ghgc.ctj,yr.s - To demonstrate and verify the opera ti.on of the~ Borl Sr qu~nre Control Systr m ~ i.nclud inq the Bod Pattern (:ont(oiler hand i t. a.,sociated external test rirruitry. Pl:r.gc.gui.;it~~s (: on.=truction is complete to the r xtr~nt necessary to>>erform this test and ystc m i.. turned over to th". TSG. Pr quirerl instrumr nt.- arc ra]ibraterl anrl c:ontrols ~re opr rablr.. Required elc ctrical pover supply systems are available. Test. gr.thorl The Bod Pattern Controller vill be tested <<nd verif ic.rl to operate correctly in thr!>>Self Test>> mode. All BSCS 0 pet' tor display functions and rontrols as well <<s.thr ability of. the B SCS to suh titutc rod position <<lata wi.ll be demonstrated ind vr rifir d. Syst<<ms oper<<tions of all rontrol. ro<l vithdrav and insr r t h lock anrl forcerl .,inq1 e match rorl motion vt.ll. he verified
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hy co nductinq rod movements under the control. of both sequence >>A>> a nrl Arrr Litapc:r! ('.gjtr.gaia The System performance par<<metr! rs are in <<rcnrdance wit.h t hc> appl icablr. desir)n rlocuments. gp!h. 1C) god WoLgb gipigggc~r Qyz~tom err,opegatgona1 Test Truest Ohgr ctive. Tn rlemonstrate anrl verify the opera tion of, the Borl Worth Ni nimizr!r System, inrlurlinq the ability of thc. sy. tern to>>rovicl<< insert and vithrlrav hlock.. helow lov power set point, when thr rontrol rorl insert/withdrav sequenres are not vt.thin pre-set sequences, anrl the ability to provide visual dispilays and alarm, h<<tvc~~n lov power setpoint and low power alarm point. @genic guigjtc.s
- Construction is complete to the extent necessary to perform this test and system .is turned over to thr. IS(:.
Requirerl instrument. are calibraterl and controls are opeable. Rr quired elr.ctrical power supply systems are available. Test gc.t hod The Bod Worth Minimizer will he tested anrl veri fied to operate under various acceptable and non-acceptable rorl posit.ion modes, while demonstratinq rod blocks and alarms for low povr r in tr rlorks. Be v. 31 ~ 7/A 2 14. 2-40
SS ES- PS AR Acceptance Criteria The system performance parameters are in accordance with the applicable desi qn'ocuments. JP57,1) Oninterrugtable AC Pokey System Pgeoperational Test Test Objective To demonstrate the ability of the Uninterruptable AC Pover System to perform the f ollowing:
- 1) That full load pover is supplied to the distribution panel
- 2) That the static transfer switch will automatically shift load from the preferred to the alternate source upon loss of the preferred source
- 3) That the static transfer svitch will automatically shift load from the preferred source to the alternate source vhen the preferred source becomes overloaded and shift back to the preferred source when the overload condition is cleared
- 4) That loads can manually be switched from preferred to alternate source and vice-versa
- 5) That alarms operate and annunciate at their specified abnormal condition Prereguisites Construction is complete to the extent necessary to perfor'm this test and the system is turned over to the ISG.
Required calibration and operation of instrument, protective devices and breakers is verified. 480V AC Pover, 250 V DC Pover, and Resistor Load Bank are available. 'Pest method The Uninterruptable Power Supply is energized by manually closinq the 250 V DC preferred breaker (inverter) and the 480 V AC Alternate Breaker (Voltag'e Regulating Transf ormer) . With the static transfer switch in normal mode, the load is increased by use of the Resistor Load Bank vhile the voltage and current is monitored. The current is gradually increased above normal ratinq until the automatic transfer svitch shifts the overload to the alternate source. Then the load .is slowly decreased to clear the overload and to verify that the automatic transfer svitch shifts the load back to the preferred source. A loss of the preferred source is simulated to verify that the automatic transfer switch vill shift the load to the alternate source. Then vith both sources available the transfer switch is manually switched from the preferred to alternate source and vice versa by means of the bypass mode and normal mode pushbuttons. Alarms are either simulated or functionally checked throughout the above procedure. AccePtance Criteria That reliable 120 V AC Poser, at design load is supplied to the distribution panel. That the automatic transfer switch vill shift loads from the preferred to the Rev. 31, 7/82 14. 2-41
SS ES-'PS AR alternate source with neqliqable power interruption upon loss of preferred source. That the automatic transfer svitch vill shift load from the preferred to the alternate source in an overloaded condition and back to the preferred source vhen the overload condition is cleared and, that the load can manually be shifted from the preferred to the alternate source and vice-versa that alarms operate at their enqineered set points and annunciate in the control room. QP58. 1) Reactor Protection System Preoperational Test Test Objective To demonstrate the proper operation of the Reactor Protection System (RPS) in all combinations of logic and to demonstrate redundancy, electrical independence, mode svitch operation, and safe failure on loss of power. Pgereguisites Construction is complete to the extent necessary 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. The Control Rod Drive System preoperational test is completed to the extent necessary to perform this test. Test Method Inteqrated system operation is initiated manually to verify N-G set performance and electrical independence. Required controls are operated or simulated signals are applied to verify: sensor relay-to-scram trip actuator response time, the ability to scram CRDs in conjunction vith the CRD hydraulic system, scram reset delay time, mode svitch operation, and system interlocks and alarms. Acceptance Criteria System performance is in accordance with the applicable desiqn documents. P59,1} QP59. 1 Pgxmggy P xm A Cgntaxnment Sggtem Preopegatzonal gest Test objective To demonstrate the operability and isolation capability of the Primary Containment System. Containment isolation valve functional tests vill be performed. To test the vacuum breakers and show proper operation of the controls and actuators, which vill demonstrate the ability to limit the drywell and suppression pool internal and differential pressures. Prereguisites Construction is complete to the extent necessary to perform this test and the system is turned over to the ISG. Required instruments are calibrated and controls are operable. The suppression pool is filled with demineralized water to the required level and the hotvell is available. The Containment Instrument Gas System, Instrument Air System and required Rev 31 ~ 7/82 14 2- 42
SSES-FS AR electrical power supply systems are available. All primary containment isolation valves are operable. Test Method The suppression pool cleanup system will be tested for proper operation; the primary containment isolation system non-isolation will have signals simulated with the valves in the position, to verify the primary containment isolates when an isolation signal is received. Valve closure times are verified for those valves specified in the PSAR in the various system preoperational tests. The test method is described in the General Test Statement.. Vacuum breakers will be actuated to show proper directional movement when permissives are available to control circuitry. I 7 Acceptance Criteria The Suppression Pool Cleanup System functions are as desiqned. The Primary Containment isolation functions are designed when appropriate isolation signals are present. TP 2. 14 Nuclear Boiler System Level Instrumentation Verification Test Test Objective - To demonstrate that the nuclear boiler level instruments function as desired. Prereguisites Construction is complete to the extent necessary 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. A method to raise and lower the reactor vessel water level is available. Test method The actual reactor vessel water level will he changed to verify level switch trip points, indicating functions and alarms. Acceptance Cgiteria The system performance parameters are in accordance with the applicable desi qn documents. (P59,.2) Containment Intearated Leak Rate Test
'Pest Objective To demonstrate that the total leakage from the containment does not exceed the maximum allowable leakage rate (La) at the calculated peak containment internal pressure (Pa),
as defined in 10 CFR50, Appendix J. Prerequisities Construction of the primary containment, including installation of all portions of mechanical, fluid, electrical, and instrumentation systems penetrating containment is complete. Type B and Type C local leakage rate instruments is satisfactorily complete. Required test equipment and Rev. 31, 7/82 14 2- 43
SS ES-FS AR data acquisition systems are operable. Systems required to support the ILRT are operational. Test Method The test shall be conducted in accordance with the requirements of Subsection 6.2.6 of the FSAR. Acceptance Criteria Acceptance criteria for this test are in accordance with the requirements of Chapter 16 of the FSAR. QPS9,3) Pgimgrg Contginment Isola tion Valve Timin~ Test Objective To demonstrate that containment isolation valves receivinq an automatic isolation signal meet the 'clo'sing time requirements as stated in Table 6.2-12. t Pre-requisites Construction is complete to the extent necessary and the various systems are turned over to the ISG. Required instruments are calibrated and control schemes have been checked and are operable. The required electrical power supply systems are available. Test Method Each valve receiving an automatic isolation signal will be closed (opened) by simulating the isolation signal of the interlock relay co'ntacts. Upon,'initiation of the simulated signals, the valve(s) will be timed from their pre-isolation to their post-isolation position. Acceptance Crit'.ria - Valve receiving automatic isolation siqnals close (open) within the required time noted in FSAR Table 6.2-12. (P60. 1) Containment Atmosphere Circulation System Preoperational Test Test Objective - To demonstrate the capability of the Containment Atmosphere Circulation System to cool and circulate air inside the Containment. Prerequisites - Construction is complete to the extent necessary 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. The Reactor Building Chilled Mater System or an 'alternate cooling water supply is available. Test method The system operation is initiated manually and flow for each fan is determined. Required controls are operated or simulated signals are applied to verify; automatic start of standby units and other system interlocks and alarms. No heat loads are simulated during the test. Acceptance Criteria The system performance is in accordance with the applicable design documents. 8 ev. 31, 7/82 1'4 2-44
SS ES- PS AR (p61,1> React. or Water Cleanup Svstem Preonerat ional Test Test Objectives To demonstrate the operability of the Reactor Water Cleanup and Filter Demineralizer System. In particular the followinq items are to be demonstrated:
- 1) The ability of individual components, instrumentations, alarms and interlocks to function properly.
- 2) Verify proper system performance by verifying all flov paths, flov rates and component performances to be in accordance vith design specifications.
I
- 3) The ability of the system and filter to isolate by simulatinq each sensor to its trip point.
- 4) Verify the RWCU system containment isolation valves vill respond properly to all control signals and closinq times are w it bin required speci ficat ions.
- 5) The ability of the filter/demineralizer valve and pump operatinq sequence to operate properly.
Prerequisites Construction is complete to the extent necessary to perform this test and the system is turned over to the ISG. The Reactor vessel is filled to provide enough suction head to the React'or Mater Cleanup Recirculation Pumps. The Reactor Building Closed Coolinq Water System, Instrument Air System, condenser hotwell or Liquid Radvaste Collection System, and the HWCU Precoat System are available. Required electrical power supply systems are available. Test,(ethos System operation is initiated manually. Pump flow and filter and demineralizer differential pressures are determined. Precoat and backwash cycles are tried. Controls are operated or simulated signals are applied to verify system isolation upon initiation of the respective HSSS isolation relay, other system interlocks and alarms. Acceptance Criteria The system performance parameters are in accordance with the applicable desiqn documents. QP64,1) Reactor recirculation System Preoperational Test Test Objectives To demonstrate the operability of the Reactor Recirculation components and the system. Prereguisites. Construction is complete to the extent necessary 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. The Reactor Buildinq Closed Coolinq Water System, is available. The Rev. 31, 7/82 14. 2-45
SS ES- FS AR reactor vessel is filled with demineralized water to the reguired level. Test Method System operation is initiated manually. The system is tested by individual and integrated operation of .M-G sets, pumps, and valves. Performance of the N-G sets, recirculation pumps, and get pumps are determined to the extent possible during this test. Required controls are operated, or simulated signals are applied to verify interlocks and alarms. Acceptance Criteria The system performance parameters are in accordance with the applicable design documents. I TP g,16 Reactor Igtegnglq Vibgation gnd Ensgection Test Objective - The test objective is to detect damage excessive wear, loose parts, or other evidence of'nacceptable vibration which could result from assembly errors or undesirable deviations from the previously qualified prototype plant construction. This test is a quality assurance measure which experimentally confirms the absence of excessive vibration of core support structures, get pumps, lower plenum components, and other major internal structures. The test is conducted without fuel and is not intended to be a test of fuel or incore instrument vibration. However, the specified test conditions, without fuel present, provide a level of vibration excitation of major internal structures which is at least as high as that measured in normal power operation.
/
Prereguisites To the extent necessary to perform this test all reactor internals components are installed except as follows. The core matrix is empty; there are no fuel assemblies, incore instrumentation tubes, or neutron source rods. Control blades are 'withdrawn or not installed. Fuel support castinqs are installed. 2.< The dryer assembly need not be installed.
- 3. One or both of the access hole covers on the shroud support plate must remain unwelded until after the test to provide access for inspection. Temporary closures must be provided.
The reactor vessel is closed, filled, and ready for pressurization. The recirculation pumps are operable. The RHR system pumps are operable to provide necessary temperature rise. Clean-up system heat exchanqers are operable for temperature control. Rev. 31, 7/82 14 2-06
SS ES- FS AR Test Method A visual inspection is, made before and after the required maximum allowable speed pump'uns. These flow runs include 35 hours of two-loop operation and 14 hours each for loops A and B. These hours may not be sequential, but they must be between the initial and final inspections. I Acceptance Criteria '- Initial and final inspection results are accep table. QP69,1} Liquid Radwaste Collection System Preoperationaal Test Test Objective To demonstrate the capability of the Liquid Radwaste Collection System to collect liquid waste. Prereguisites Construction is complete to the extent necessary to perform this test and the system is turned over to the ISG. Required instruments are calibrated and controls are operable. Reguired electrical power supply systems are available. Liquid Radwaste Collection System and storage tanks are available. Test Method Sump pumps are operated and performance characteristics are determined. Level controls are operated to verify pump starts and alarms. Liquid radwaste discharge valves from primary containment are verified to close upon containment isolation signal . Acceptance Criteria The system performance parameters are in accordance with the applicable design documents. (P70. 1) Standby Gas Treatment System And Secondary Containment Isolation Pgeopegationgg Test Test Objective To demonstrate the capability of the Standby Gas Treatment System (SGTS) to function as designed. Prereguisites Construction is complete to the extent necessary 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. The Reactor Building Heatinq and Ventilation System, SGTS vent, and Instrument Air System are available. Test Method System operation is initiated manually and where applicable automatically. Required controls are operated or simulated signals are applied to verify secondary containment isolation and start of SGTS. SGTS performance is determined by measurinq secondary containment pressures, system pressures and fan flow rates. System interlocks and alarms are verified. acceptance Cgitygia The system performance parameters are in accordance with the applicable design documents. Rev. 31, 7/82 14 2-47
SS ES- PS AR gp73,1} Conta j,nm~et Atpospgeggg Contgo~ System Pgeopegational Test Test Objective To demonstrate the operabi1ity of the purge upply and. exhaust systems, and to show the valves work according to the designed permissives and interlocks. Prerequisites Construction is complete to the extent necessary to perform this test and the system is turned over to the ISG. Required instrumentation are calibrated and controls are operable. Required electrical power supply system are available. Test Method - The system valves will be operated to demonstrate proper operation. Simulated siqnals are applied to verify interlocks and alarms. 4 Acceptance Criteria The ssystem performance parameters are in accordance with the applicable desi qn documents. QP73.2} Contajnmegt Hydrogen Recombiner Pgeoperationgl Test Test Objective To demonstrate the operability of the hydrogen recombiners (actual process is not demonstrated at this," time) . Prerequisites Construction is complete to the extent necessary to perform this test and the system is turned over to the ISG. Re'quired instrumentation is calibrated and controls are operable. Required electr'ical power supply system is available. Test Method The Hydrogen Recombiner System will be operated to the extent practical. Acceptance:- Criteria - The system performance parameters are in accordance with the applicable desiqn documents Test Objective To demonstrate the Containment Oxygen-Hydrogen Analyzer System to analyze containment hydrogen and oxygen content. Prereguisites Construction is complete to the extent necessary to perform this test and the system is turned over to the ISG. Required instrumentation is calibrated and controls are operable. Required electrical power supply system is available. Test Method The oxygen and hydrogen analyzers are utilized to determine the containment atmospheric analysis. Acceptance Cgitegia- The system performance parameters are in accordance with the applicable design documents. Rev. 31, 7/82 14 2-48
SS ES- PS AR Test gbgectiye To demonstrate the ability of the + 24 Volt DC System to perform the follovinq:
- 1) That the batteries can ensure a complete discharge, based on their ampere-hour. rating, =without exceeding the battery bank minimum voltage limit. (Performance Test)
- 2) That the batteries can provide reliable stored energy to their design loads as indicated in Table 8.3-8 in the event of a Desiqn Base Accident.
.3) That the battery chargers can deliver their rated output.
- 4) That the battery chargers can fully charge their associated batteries from design minimum discharge (i.e., a fter the service test) while simultaneously providing power to the distributed panel for normal station loads.
- 5) That alarms operate and annunciate at their specified abnormal condition.
- 6) That reliable + 24 Volt DC is delivered to the distribution panels.
Pregeguisites Construction is complete to the extent necessary to perform this test and the system is turned over to the ISG. Required calibration and operation of instrument protective devices and breakers is verified. 120 V AC, Resistor Load Bank, Battery Room Ventilation and Emergency Eyewash is available and/or in service. Test Method The battery performance test is manually initiated by connecting the battery bank to the Resistor Load Bank and discharqinq the batteries at a constant current for a specified period of time. The Battery Service Test is manually initiated by connecting the battery bank to the Resistor Load Bank and simulating, as closely as possible, the load the batteries will supply during a Design Base Accident. Then the battery charger is connected to the batteries and the distribution panels to verify that they can equalize charge the batteries while simultaniously. providing power to the normal plant loads. The battery charger is also connected to the Resistor Load Bank and current is increased to its mximum rating with the charger isolated from its associated battery bank. Alarms are simulated and verified to operate Properly. Rev. 31 ~ 7/82 14 2-49
SSES-FSAR Criteria The batteries can satisfactorily deliver
"'cceptance stored energy for the specified amount of time as required for the performance and service tests. The battery 'chargers can deliver rated output, and can charqe their associated battery" bank from minimum voltaqe to a fully charged state. in a specified amount of time while simultaneously supplying normal plant loads.
The alarms operate at their engineered setpoints and annunciate in the control room. gP76.1) Plant Leak Detection System Preoperational Test Test Objective To demonstrate the operability, of the'Plant Leak Detection System. Prereguisites - Construction is complete to the extent necessary 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 N~t hod Sump levels will be varied (if practicable) or simulated signals are applied to level sensors to verify the leak detection system alarms. Accept..ance Criteria The system performance parameters are in accordance with the applicable desiqn documents. Test objective To demonstrate the capability of the post Accident Sampling System (PASS) to function as designed. Prereguisites Construction is complete to the extent necessary to perform this test and the system is turned over to ISG. Required instruments are calibrated and controls are operable. Required electrical power supply systems are available. Test Method Control switches will be manipulated and proper relay and indicating light operation will be verified. Response of valves will be checked functionally (i.e. voltage used as an indication that the valve is open or closed.) The system will then be operational checked by taking actual samples. Acceptanre Criteria Control switches and associated =interlocks function properly and the system shall be capable of obtaining a sample in less than one hour from initiating the sampling operation. (p78. 1l Source Ranae Monitorina Svstem Preonerational Test 'gest Objective To demonstrate the operability of the Source Range Monitorinq (SRM) System. Rey. 32, 12/82 14 2-50
SSES-PSAR Prerequisites - Construction is complete to the extent necessary to perform this test and the system is turned over'to the ISG. Required reactor internals'are installed, instruments are calibrated and controls are operable. Required electrical power supply systems are available. Test Method - Source Range Monitor Detector insert/retract drive mechanisms are operated to verify proper operation. Required simulated siqnals are applied to verify SRM channel trips, i ndica ting ligh ts a nd ala rm s. Acceptance Crit'eria The system performance parameters are in accordance with the applicable design documents. gP78,$ ) Intermediate-gange monitoring System preoperationgg ~est Test Objective - To demonstrate the operability of the Intermediate Range Monitoring (IRMj System. Prereguisites Construction is complete to the extent necessary to perform this test and the system is turned over to the ISG. Required reactor internals are installed, instruments are calibrated and controls are operable. Required electrical power supply systems are available. Test Method Intermediate Range Monitors detector insert/retract 'drive mechanisms are operated. Required simulated signals are applied to verify IRM channel trips, rod blocks, indicating 1 ig h ts a nd ala r ms. Acceptance Criteria - The system performance parameters are in accordance with the applicable desiqn documents. (P78.3) Average Power Ranqe Neutron Monitoring System Test objective To demonstrate the operability of the Average Power Range Neutron Monitorinq (APRM System) including LPRM's, Recirc. flow bias signals and Rod Block Monitor. Prerequisites Construction is complete to the extent necessary to perform this test and the system is turned over to the ISG. Required reactor internals are installed. Instruments are calibrated and'controls are operable. Required electrical power supply systems are available. Test Method Each LPRM is checked from detector to its end function. Required input signals are simulated-to verify LPBM channel trip lamps, remote meters and alarms. Required signals from the LPRM System are simulated to each APRM channel to verify trip functions, indicatinq meters, lights and alarms. Each flow transmitter is checked from flow element to its end function. Rev. 32, 12/82 14 2-51
SSES-PSAR Signals are simulated'to verify flow inducted trips, remote meters and alarms. Required siqnals from the LPRH and flow bias systems are simulated to each RB5 channel to verify trip functions, indicating liqhts, and alarms. Acceptance Criteria The system performance parameters are in accordance with the applicable desiqn documents. gP78.4} Traversing I@core probe System preoperationag Test Tegt objective To demonstrate the. proper operation of the Traversing In-Core Probe System. Specific objectives are to Remonstrate the following:
- 1) Manual and automatic Operation.
- 2) Proper operation of all interlocks, overrides and automatic func tion s.
- 3) Proper operation of all indications and alarms.
- 4) Simulated operation of the shear valves.
- 5) Proper interface between the TIP system and process computer.
PlelPguisites - Construction is complete to the extent necessary to perform this test and the system is turned oVer to the ISG. LPRt1s are installed inside the reactor vessel and required instruments are calibrated and controls are operable. TIP tracinq X-Y recorder and purqe system are available. Test Method system operation is initiated manually. The indexer interlock, shear valve control and monitoring, ball valve control and monitorinq, squib circuits and purging operations are verifieR. Required controls are operated or simulated signals are applied to verify interlocks external to the system and system alarms. Acceptance Criteria The system performance parameters are in accordance with the applicable desiqn documents. fP79. 1 6 P79. 2I) Area Radiation Monitorinq System Preoperational Tegt Tegt oh/ective- To demonstrate the operability of the Area Radiation Nonitorinq System. Pgegeguisites - Construction is complete to the extent necessary to perform this test and the system is turned over to the ISG Required instruments are calibrated and required electrical power R ev. 32, 12/82 14 2-52
SS ES-FS AR supply systems are available.' 'The required radioactivity sources with known strengths are available. it Test Method - The radioactive sources are used or simulated signals are applied to verify area radiation monitor channel trips, indicatinq lights, and alarms. Acceptance Criteria The system performance parameters are in accordance with the applicable.'desiqn'ocuments. (P79.2A-H) Process Radiation Monitoring System Preoperational I Tegt= 'h Test Ohjective To demonstarte the operability of the Process Radiation Monitorinq System. k Pregeguisites Construction is complete to the extent necessary to perform this test and the system is turned over to the XSG. Required instruments are calibrated and required electrical power supply systems are available. The required radioactivity sources with known strenqths are available. Test Methorl - The radioactive sources are used or simulated-siqnals are applied to verify process radiation monitor channel trips, locatinq lights, interlocks, and alarms. Acceptance Criteria The system performance parameters are in accordance with the applicable desiqn documents. gP80. 1) Reactor Non-nuclear Instrumentation System Preoperat ional Test Test Ohgective To demonstrate that the Reactor Non-nuclear Instrumentation System functions as designed. Pregeguisites-- Construction is complete to the extent necessary to perform this test and the system is turned over to the ISG. Required instruments are calibrated and the controls are operable. All relays that are initiated from reactor vessel level and pressure sensors are placed in the untripped condition. Test Me.thod Simulated signals are applied to instrument loops and trip functions, indicatinq functions and alarms are verified. Arceptance Criteria - The system performance parameters are in accordance with the applicable desiqn documents. (P81,1) Fuel Handlina Svstem Preonerational Test T~st Ohgect.iye To demonstrate that the refueling platform, refuelinq grapple and the reactor servicing tools function as designed. Bev. 32, 12/82 10. 2-53
SSES-FSAR Prereguisites Construction is complete t'o the extent necessary 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. The fuel pool or reactor cavity are available to test the fuel grapple. The Reactor Hanual Control System is available to test the refuelinq platform interlocks. Test Method - The ref uelinq platform travel speed and interlocks with the Reactor, Manual Control System are verified. All servicinq tools are tried for proper operation. Load tests for the. fuel qrapple are performed and the fuel grapple is operated at designated speeds. System alarms are verified by operating the controls or simulatinq the required siqnals. Acceptanc".e Criteria - The system performance parameters are in accordance with the applicable design documents. (P83.1A) Hain Steam Nuclear Steam Supply Shutoff System Preooerational Test Test Objectives The qeneral objective of this test is to demonstrate the ppoper operation of the Nuclear Steam Supply Shutoff System.'pecific objectives are to demons'trate the f ollowinq: {1) The ability of the Main Steam .Isolation Valves (MSIV s) to ~ close on receipt of the appropriate signals. (2) The ability of the Main Steam drip leq drains to function properly. (3) The ability of the valve isolation logic to function properly. (4) The ability of the. steam jet air ejector steam supply valves to function properly. pgeg~guisit.eg Construction is complete to the extent necessary to perform this test and the system is turned over to ISG. Required instruments are calibrated and controls*are operable. Required electrical power supply systems, Instrument Air- System, and the Containment Instrument Gas System are available. Tegt Method The Main Steam Isolation Valves are exercised and functionally checked for closure by their logic circuit trips, loss of control powor and loss of normal air supply using their charged accumulator. The Nuclear Steam Supply Shutoff System isolation logic is signals to isolate tested the RHB by verifyinq System, the it sends appropriate RMCU System and the Main Steam drains. The Main Steam Line Drip Leg Drain Valves and the Rev. 32 '2/82 14 2-54
SSES- PSAR Main Steam Line branch valves are functionally checked for proper opera tion. Acceptance Criteria The system performance parameters are in accordance with the applicable desiqn documents. {P83. 1B) Main Steam Relief Valves/Automatic Depressurization System Qgeop erat j.o nial Test Test Objectives To demonstrate the proper operation of the Main Steam Safety Belief Valves to operate correctly in the safety and. automatic depressurization modes. Prer~guisites Construction is complete to the extent necessary to perform this test and the system is turned over to ISG. Required instruments are calibrated and controls are operable. Required electrical supplies are available and the Containment Instrument Gas System is available. Test Method The Automatic Depressurization System is functionally checked for proper in automatic and manual modes. Fach Safety/Relief valve is verif ied operational when any one of its control solenoids is energized. The Remote Shutdown Panel operation is also demonstrated. Valves are also checked for the followinq: fail close on loss of air, loss of power, and full stroke operation. The acoustic Monitor System is functionally
~
- tested to verify proper operation.
Acceptance Cgit.er ia The system performance parameters are in accordance with the applicable documents., A(83.1C} Nain Steam Leakage Control System Preoperational Test ~ ~ Test objectives To demonstrate the proper operation of the Main Steam Isolation Valve Leakage Control System to collect steam lines by operation of its air blowers, heaters, and motor operated valves. Prereguisites - Construction is complete to the extent necessary to perform this test and the system is turned over to ISG. Required instruments are calibrated and controls are operable. The required electrical power supply systems are also available. Test Method The Main Steam Isolation Valve Leakage Control Svstem interlocks are verified, and the system is initiated
<<, manually and checked for proper operation.
Acceptance Criteria The system performance parameters are in accordance with the applicable design documents. A/83,1DQ Naj,n Steam peak Qetection System Preoperational Test R e v. 32, 12/82 14 2-55
SSES-FSAR Test Objectives To demonstrate the proper operation of the Steam Leak Detection System to monitor area temperatures and give isolation signals to the Nuclear. Steam Supply Shutoff system isolation loqic. Prerequisite s Construction is complete to the extent necessary to perform this test and the system is turned over to the ISG. Required instruments are calibrated, controls are operable, and electrical power supplies are available.'est Method The Main Steam "Leak Detection System is functionally tested to verify the ability of thet'o area temperature monitors to monitor changes in temperature and give isolation signals into the Nuclear Steam Supply Shutoff System logic. Acceptance Criteria The system performance parameters are in accordance with the applicable design documents. Test objective To demonstrate the capability of the 250 volt dc system to provide dc power to connected buses. prereguisites Construction is complete to the extent necessary 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 and a load resistor bank are available. The Battery Room Ventilation system is also a va ila hie. Test. Me t hod The system is operated and a load capacity test is conducted for the battery with the battery charger disconnected.
.Required controls are operated or simulated signals are applied
',:;.,:~",. to verify battery charqer perf ormance, system interlocks and alarms. Arceptance Criteria The system performance parameters are in accordance with the applicable desiqn documents. gP9$ .1} Reactor Buildinq Crane Preoperational Test Test Objective The general objectives of this test are to demonstrate the followinq:
- 1) The performance of the reactor building crane' components.
- 2) Establishment of baseline data for all functional.
corn pon en ts.
- 3) That- all warninq signals are working per design intent..
Re v. 32, 12/82 14. 2-56
SS ES-PS AR
- 4) The capability of the crane to operate in a designated area in accordance with design requirements.
Pregegnisites Construction is complete and the system is turned over to the ISG. Required electrical power supply systems are available and controls are operable. Required loads are available to perform load testing of this crane. Construction phase static load testinq {125% of rated load) is completed. Test Nethod - The liqhtinq system for the crane is energized and observed for proper operation. The bridge and the trolley are speed-tested in both directions. Current and voltage readings are taken in both directions. The proximity'switches are tested for both the bridge and the trolley including trolley movement restriction switches in zones A, B, and C. The main hoist and the auxiliary hoist are speed-tested traveling up and traveling down. Current and voltage readings are taken in both directions. All limit switches are tested. A loss of power situation is created for both hoists to check the brakes ability to hold without power. An overspeed test is simulated for each hoist. The main hoist load limit switch is also tested. The above listed tests are run from the pendant pushbutton control system. Operability of the crane is also demonstrated from the cab and by radio control. The anticollision system is tested and the crane power source is verified. Acceptance Criteria The system performance parameters are in accordance with the applicable desiqn documents. OBJFCTIVE; To supplement load testing of the reactor building overhead crane. PRERPQUTSXTES: Construction is complete to the extent required to perform the test, and the crane is available for service. TFST METIIOD.
- 1. Brakinq capability of the main and auxiliary hoist under rated load is verified {all brakes operational).
- 2. The ability of each individual main and auxiliary hoist brake to stop and hold rated load while lowering at rated speed is tested.
R ev. 32, 12/'82 14. 2-57
SSES-PSAR 3 The capa'bility of limitinq movement of the main 'hook to 1/32" and the auxiliary hook to 1/16" in both. raise and lower direction at rated load is tested from a complete standstill over an averaqe of ten successive movements.
- 4. Voltage and current of all crane, motors is recorded while runninq at rated load and rated speed.
5 The capability of the main hoist to limit an uncontrolled drop at rated load and rated speed to less than 1/2<<hook movement is verified. "
- 6. Simultaneous bridge and trolley movement at'ated load and the ability of the zone proximity switches to restrict crane movement within safe limits is also verified.
All crane parameters are within design limits. Test oh/ective To demonstrate that the plant systems are capable of operatinq on an inteqrated basis in normal and emerqency modes, to demonstrate that adequate power supplies for the class ZE equipment will exist, and to assure that optimum tap settinqs have been selected f or transformers supplying power from o ff site sources to class IE busses. Prerequisites Requir'ed system preoperational tests have been completed and plant systems are ready .for operation on an integrated basis. Te~t Method Emergency Core Coolinq Systems (RHR 6 Core Spray) are lined up in their normal standby mode. The plant electrical ..system is lined up per normal electrical system lineup (For Unit this lineup may be different than the lineup for two unit operation) . Loss of coolant accident signals are initiated with and without a loss of offsite power. Voltages and loads are adjusted, as practical, to simulate the anticipated ranges of variations. Proper response of the electrical distribution system, diesel qenerators, and ECCS pumps will be verified. Acceptance Criteria Systems performance parameters are in accordance with the applicable desiqn documents.
- 14. 2. 12 2 Startuo Test Proaram Procedure Abstracts All those tests comprising the Startup Test Program (Table 14.2-
- 3) are discussed in this section. For each test a description is provided for -test purpose, test prerequisites, test description and statement of test acceptance criteria, where Bev. 32, 12/82 14 2-58
SS ES-PSAR applicable. Additions, deletions, and changes to these discussions are expected to occur as the test program progresses. Such modification to these discussions will be reflected in amendments to the FSAR. In describing the purpose of a test,, an attempt is made to identify those operating and safety-oriented characteristics of the plant which are being explored. Where applicable, a definition of the relevant acceptance criteria for the test is. qiven and is designated either Level 1 or level 2. A Level 1 criterion normally relates to the value of a process variable assigned in the design of the plant, component systems or associated equipment. Zf a Level 1 criterion is not satisfied, the plant will be placed in a suitable hold-condition until resolution is obtained. Tests compatible with this hold-condition may be continued. Following resolution, applicable tests must be repeated to verify that the requirements of the Level 1 criterion are now satisfied. 'I A Level 2 criterion is associated'ith expectations relatinq to the performance of systems. If a Level 2 criterion is not satisfied, operatinq and testinq plans would not necessarily be altered. Investigations of the measurements and of the analytical techniques used for the predictions would be started. For transients'involvinq oscillatory response, the criteria are specified in terms of decay ratio (defined as'he ratio of successive maximum amplitudes of the same polarity). The decay ratio must be less than unity to meet a Level criterion and 1 less than 0. 25 to meet Level 2. ggT-g} Chemjcgl gnd gggjoghemgggl Tepee Objectives The principal objectives of this test are a) to secure information on the chemistry and radiochemistry of the reactor coolant, and b) to determine that the samplinq equipment, procedures and analytic techniques are adequate to supply the data reguired to demonstrate that the chemistry of all parts of the entire reactor system meet specifications and process r equ ire me nt s. Specific ob electives of the test program include documentation of radwaste liquid discharge, documentation of baseline piping radiation levels, determination of steam quality, evaluation of the Condensate polishing system, and evaluation of the Reactor Water Cleanup system. Data for these purposes is secured from a variety of sources: plant operating records, regular routine coolant analysis, radiochemical measurements of specific nuclides, and special chemical tests. Rev. 32, 12/82 14 2-59
SS ES-PS AR Ppereguisites The required preoperational tests have. been completed. Xnstrumentation has been checked or calibrated as appropriate. Test Met:hod"-- Prior to fuel loading, chemical samples are taken to ensure that reactor coolant and Fuel Pool Cooling anddetermine Cleanup System sample stations are functioning properly and to initial concentrations. reactor Additionally, subsequent to fuel heatup, and at each major power level loadinq, durinq change, a complete set of samples are taken to verify that all plant sample stations are functioning properly and to determine the chemical and radiochemical quality of reactor water and reactor feedwater, and performance of f ilters and demineralizers. Acceptance Cgiterjg Level 1 Chemical factors defined in the Technical Specifications and Fuel Warranty must be maintained within the limits specified The activity of gaseous and liquid effluents must conform to license limitations. Materthequality must be known at all times and should remain within quidelines of the Mater Quality Specifications. Level 2 Not applicable. tST-21 Radiation Measurements gest ghjectiyes The objectives of this test are (a) to determine the background radiation levels in the plant environs prior to operation for base data on activity buildup and (b) to monitor radiation at selected power levels to assure the protection of personnel during plant operation. Prepegnisites-- The required preoperational tests have been completed; the Superintendent of Plant has reviewed and approved
'he test procedures and initiation of testing. Instrumentation has been checked or calibrated as appropriate.
,. 'Test Method A survey of natural background radiation at selected locations throughout the plant will be made prior to fuel loading. Subsequent to fuel loading, during reactor heatup
.;and at power levels of approximately 25%, 60% and 100% of rated
';.'".,power, gamma radiation level measurements and, where appropriate, thermal and fast neutron measurements will be made at selected
;locations throuqhout the plant.
Acceptance Cgitegia Level 1 The radiation doses of plant
'oriqin and the occupancy times of personnel in radiation zones shall be controlled consistent with the guidelines ofin the standards for protection aqainst radiation outlined 10CPR20.
Level 2 The radiation doses of plant origin shall meet the following limits dependinq upon which Radiations Zone the ..'.:radiation base survey point is located: Rev. 32, 12/82 1Q. 2-60
SSES-PSAR Lj,glt I 0.5- mRem/hr. II III 2.5 mRem/hr. 15 m Rem/hr. IV 100 m Rem/hr. Note: All areas desiqnated Radiation Zone V have potential radiation doses of 100 mRem/hz. -
'Readings taken in Zone V during the Startup Test Proqram may be less than 100 mRem/hr; however, since Zone V is defined. in terms of potential levels, there are no Acceptance Criteria for Zone V base survey points'.
(ST-3'l A Fuel Loadina Test Ohjective The objective of this test is to achieve the full and proper core complement of nuclear fuel assemblies throuqh a safe and efficient fuel loading evolution. Prereguisites The required preoperational Tests have been completed. In. addition, prior to starting this test procedure, the following prerequisites vill be met:
- a. Fuel and Control Rod inspections vill be complete.
- b. Control Rods will be installed and tested.
- c. Reactor vessel water level will be established and minimum level prescribed.
- d. The standby liquid control system will be operable and in readiness.
- e. Fuel handlinq equipment will have been checked and dry runs completed.
- f. The status of protection systems, interlocks, mode switches, alarms, and radiation protection equipment will be prescribed and verified.
- q. Mater quality must meet required specifications.
The following prerequisites vill be met prior to commencing actual fuel loading to assure that this operation is performed in a safe manner: The status of all systems required for fuel loading will be specified and will be in the status required. b At least three movable neutron detectors sill be calibrated and operable. At least three neutron detectors will be connected to the hiqh flux scram trips. They will be Rev. 32, 12/82 14 2-61
SSES-PSAR located so as to provide acceptable signals during fuel loading. ci Source range monitoring Nuclear instruments will be checked with a neutron source prior to fuel loading or resumption of fuel loadinq if sufficient delays are incurred.
- d. The status of secondary containment vill be specified and es ta bl ished.
- e. Reactor vessel status vill be specified relative to internal component placement and this placement established to make the vessel ready to receive fuel.
- f. The hiqh flux trip points vill be set for a relatively low power level.
Neutron sources vill be installed near the center of the core and at other specified locations. Test Net:hod Before the first fuel assembly is taken from the fuel pool and inserted into the reactor, core components (fuel support castings, blade guides, control rod drives, etc.) will be installed, tested'and/or verified. This procedure begins with the steps required to assemble and load neutron sources, includes the activities necessary to monitor neutron population using specially constructed fuel loadinq chambers (PLCs), and culminates with the insertion of fuel assemblies into the reactor core. Puel loadinq continues until the core is fully loaded, verifieR and ready to perform subsequent Startup Tests. Control rod functional tests, subcriticality checks, and shutdown margin demonstrations will be performed periodically during the .loadinq; .Acceptance Criteria Level 1 The partially loaded core must be subcritical by at least 0.38%4k/k with the analytically determined, highest worth rod fully withdrawn. f ST-01 Pull Core Shutdown Mar@in Test Objective The purpose of this test is to demonstrate that the reactor will be subcritical throughout the first fuel cycle with any sinqle control rod fully withdrawn. Pgereguisites The followinq prerequisites vill be complete prior to performinq the full core shutdown margin test: a) The predicted critical rod position is available b) The Standby Liquid Control System is available Rev. 32, )2/82 10 2-62
SS ES-PSAR c) Nuclear instrumentation is available with neutron count rate of at least three counts per second and signal to noise ratio greater than two to one d) Hiqh-flux scram trips are set conservatively low e) Instrumentation has been checked or calibrated as appropriate Test Method This test will be performed in the fully loaded coze in the xenon-free .condition. The shutdown margin test will be performed by withdrawing the control rods from the all-rods-in confiquration until criticality is reached. 'If the highest worth rod will not be withdrawn in sequence, other rods may be withdrawn providing that the reactivity worth is equivalent. The difference between the measured K ef~and the calculated K ef f for the in-seguence critical will be applied to the calculated value to obtain the true shutdown margin. Acceptance criteria Level 1 The shutdown margin of the fully loaded, cold (68~F), xenon- free core occuring at the most reactive time durinq the cycle must be at least 0.38%4k/k with the analytically stronqest rod (or its reactivity equivalent) withdzawn. If the shutdown marqin is measured at some time durinq the cycle other than the most reactive time, compliance with the above criterion is shown by demonstrating that the shutdown margin is 0.38%6k/k plus an exposure dependent correction factor which corrects the shutdown margin at that time to the minimum shutdown margin. Level 2 Criticality should occur within +1.0%Bk/k of the predicted critical. tST-51 Control Rod Drive System Tegt ghjectiye The objectives of the Control Rod Drive System test are; a) to demonstrate that the Control Rod Drive (CRD) System operates properly over the full range of primary coolant
'temperatures and pressures from ambient to operatinq, and b) to determine the initial operatinq characteristics of the entire CRD System.
~ ..': pregeguisites.
'ompleted.
The required preoperational tests have been Test Method The CRD tests performed during the startup test
.program are designed as an extension of the tests performed during the preoperational CBD system tests. Thus, after it is verified that all control rod drives operate properly when installed, they are tested periodically during heatup to assure that there is no significant binding caused by thermal expansion Be v. 32, 12/82 10. 2-63
SSES- PS AB of the core components. A list of all control rod drive tests to be performed during startup testing is given in Table 14.2-5. Acceptance Criteria - Level 1 Each CRD must have a normal withdraw time greater than or equal to 40 seconds. il The mean scram time of all operable CRDs must not exceed the values specified in the plant technical specifications. (Scram time is measured from the time the pilot scram valve solenoids are deenergized.) The mean scram time of the three fastest CRDs in a two by two array must not exceed the values specified in th'e plant technical specifications. (Scram time is measured from the time the pilot scram solenoids are deenerqized) Level 2 - Each CRD must have a normal insert speed of 3.0 k 0.6 inches per second indicated by a full 12-foot stroke in 40 to 60 seconds. With respect to the control rod drive friction tests, if the differential pressure variation exceeds 15 psid for a continuous drive in, a settling test must be performed, in which case, the differential settling pressure should not be less than 30 psid nor should s troke. it vary by more than 10 psid over a fu'll (ST-6) SRN Performance and Control Rod Seauence Test Objectives The objective of this test is'o demonstrate that the operational sources, SRM instrumentation, and rod withdrawal sequences provide adequate information to achieve criticality and increase power in a safe and efficient manner for each of the specified rod withdrawal sequences. Prereqiiisit~s The required preoperational tests have been ,completed. Test method The operational neutron sources will be installed and source ranqe monitor count-rate data will be taken during rod withdrawals to. critical and compared with stated criteria on signal and signal count-to-noise count ratio. A withdrawal sequence has been calculated which completely specifies control rod withdrawals from the all-rods-in condition to the rated power configuration. Each sequence will be used to attain cold criticality. Movement of rods in a prescribed sequence is monitored by the Rod North Minimizer and rod sequence control system, which will prevent out of sequence withdrawal Acceptance Criteria Level 1 There must be a neutron signal count-to-noise count ratio of at least 2 to on the required 1 Rev. 32, 12/82 14 2-64
SSES-PSAR operable SRMs. There must be a minimum count rate of 3 counts/second on the required operable SRMs. The IRMs must be on scale before the SRMs exceed the rod block set point. t ST-7) Reactor Mater Cleanuo Svstem Tegt Obgertiyes The objective of this test is to demonstrate specific aspects of the mechanical operability of the Reactor Mater Cleanup System. (This test, performed at rated reactor pressure and temperature, is actually the completion of the preoperational testing that could not be done without nuclear heating) . Prer~guisites The required preoperational tests have been completed. Instrumentation has been checked or calibrated as a ppr opria te. Test method Mith the reactor at rated temperature and pressure nrocess variables will be recorded during steady state operation in three modes as defined by the System Process Diagram: Blowdown, Hot Standby, and Normal. Additional system configurations'ill also be aligned to verify proper performance of the bottom head flow and temperature indicators. Acceptance Criteria Level 1 Not applicable. Level 2 The temperature at the tube side outlet of the non-reqenerative heat exchanqers fNRHX) shall not exceed 130~P in the blowdown mode and 120~P in the normal mode. The pump available NPSH will be 13 feet or greater during the hot standby mode defined in the process diagrams. The cooling water flow to the NRHX's shall be limited to 6'5 above the flow corresponding to the heat exchanger capacity (as determined from the process diagram) and the existing temperature differential across the heat exchangers. The cooling water outlet temperature shall not exceed 1800P. During two pump operations at rated core flow, the bottom head temperature as measured by the bottom drain line thermocouple should be within 30oP of the recirculation loop temperatures Bottom head flow indicator PI-1R610 shall indicate within 25 gpm of RMCU flow indicator PI-8609 when total system flow is thru the bottom head drain. Rev. 32, 12/82 14 2-65
SSES-PSAR Test Objectives The objectives of this test are to demonstrate the ability of the Residual Heat Removal (RHR) System to: 1} remove heat from the reactor system so that the refueling and nuclear system servicing can be performed and 2) condense steam while the reactor is isolated from the main condenser. Prereguisites - The required preoperational tests have been completed. Instrumentation has been checked or calibrated as appropriate Test ge.thod The suppression pool cooling mode and shutdown coolinq mode will be used to measure the RHR heat exchanger capacity. Data will be obtained to determine the heat transfer rate with rated flow on both sides of the heat exchanger. Por the suppression pool cooling mode test, attempts'ill be made to establish a larqe temperature differential between the service and suppression pool water bv extended RCIC or relief valve operations. (An ideal demonstration of the RHR heat exchanger capacity would consist of measurinq the heat transfer rate in the shutdown coolinq mode with the reactor at 50 psig or less. Unfortunately, the decay heat load is insignificant during the startup test period. Use of this mode with low core exposure results in exceedinq the 100~P/hr cooldown rate of the vessel.) The shutdown cooling mode will be demonstrated after a trip or a cooldown from Test Condition 6. The RHR system steam condensinq mode is used to condense steam while the reactor is isolated from the main condenser and reactor
'vessel water level is being maintained by RCIC. This test will demonstrate system operability and stability.
Acceofance. Criteria Level 1 The transient response of any system-related variable to any test input must not diverge. Level 2 The RHR system shall be capable of operating in the
"'steam condensing, suppression pool cooling and shutdown cooling m'odes at the heat exchanger capacities indicated on the process diagrams. Both simultaneous operation of RHR loops and single loop operation shall be tested in the steam condensing and shutdown coolinq modes. Each RHR loop shall be tested independently in the suppression pool cooling mode. System-s related, variables may contain oscillatory modes of response. In thes'e cases, the decay ratio
...'*must for each controlled mode of response be less than or equal to 0.25. The time to place the RHR heat exchangers in the steam condensing mode with the RCIC usinq the heat exchanger condensate flow for suction shall average one half hour or less. Rev. 32, 12/82 1Q- 2-66
SS ES- PSAR Test Objectives The objective of this test is to determine actual reference leg temperature and recalibrate instruments necessary-if Pregeguisites The required preoperational tests have been completed. All system instrumentation is installed and calibrated. Test method At rated temperature and pressure under steady state conditions, the reference leq temperature vill be measured and compared to the value assumed during initial calibration. the difference of the tvo temperatures exceed the Acceptance If Criteria, then the instruments vill be recalibrated using the measured va lue. Acceptance Criteria Level 1 Not applicable Level 2 The difference between the actual reference leg temperature(s) and the value(s) assumed during calibration shall be less than that amount which vill result in a scale end point error of 1% of the instrument span for each range. Test gbgectives - The objective of this test is to adjust the Intermediate Ranqe Monitor System to obtain the desired overlap incompleted. with the SRM and APRM systems Pregequisites The required preoperational tests have been gest method Initially the IRM system is set durinq the Preoperational Test Program. SRH-IRM and IRM-APRM overlap is verified the first time sufficient neutron flux conditions arise. After the APRM calibration, the IRM gains vill be adjusted as necessary to optimize the IRM overlap with the SRHs and. APRMs. Acceptance Cgj,tegj,g Level 1 Each IBM channel must be adjusted so that overlap with the SRMs and APRHs is assured. t ST-11k LPRM Calibration gegt objectives The objective of this test is to calibrate the Local Pover Range Monitorinq System. prereguisites The required preoperational tests have been completed. Instrumentation for calibration has been checked. Test method The LPRM channels vill be calibrated to make the LPRM readings proportional to the neutron flux in the water gap at the chamber elevation. Prior to this calibration, LPRM Rev. 32, 12/82 10 2-67
SSES-FSAR response to control rod movement is verified. Calibration
! factors will be obtained through the use of either an off-line or a process computer calculation that relates the LPRM reading to averaqe fuel assembly power at the chamber height.
Acceptanre Criteria - Level 1 Not applicable. Level 2 Each LPRM will be within 10% of its calculated value. (ST-12) APRM Calibration Test Objective - The objective of this test is to calibrate the Averaqe Power Ranqe Monitoring (APRM) system. prereguisites The required preoperational tests have been completed. Instrumentation Xor calibration has been checked. Test method. A heat balance will be made after initially achievinq power level associated with each test plateau. Each APRM channel readinq will be adjusted to be consistent with the core thermal power as determined from the heat balance. During heatup a preliminary calibration will be made by adjusting the APRM amplifier gains so that the APRM readings agree with the results of a constant heatup rate heat balance. The APRMs should be recalibrated in the power range by a heat balance as soon as
.adequate feedwater indication is available.
Acceptance Criteria Level 1 The APRM channels must be calibrated corn to read equal to or greater than the actual core thermal power. Level 2 Not applicable.
,', (ST-13k NSSS Process Computer Test Objective The objective of this test is to verify the NSSS performance of the process computer under plant operating conditions.
prerequisites The required preoperational tests have been pleted. Test Method - The Dynamic System Test Case will be run to verify that the results of NSSS performance calculations are correct. Acceptance Criteria Level 1 Not applicable. Level 2 (1) The MCPR calculated by an independent method and the process computer either: .:Re v.,32, 12/82 14 2-68
SS ES- FS AR a.'revalueinbythemore same fuel assembly than 2% or, and do not differ in
- b. For the case in which the MCPR calculated by the process computer is in a different assembly than that calculated by the independent method, for both assemblies, the NCPR and CPR calculated by the tvo methods shall agree within 2% for. the same assembly.
(2) The maximum LHGR calculated by the independent method and the process computer either: Are in the same fuel assembly and do not differ in value by more than 2%, or For the case in which the maximum LHGR calculated by the process computer is in a different assembly than that calculated by the iindependent method, for both assemblies, the maximum LHGR and LHGR calculated by the tvo methods shall agree within 2g for the same assembly. (3) The MAPLHGR calculated b'y the independent method and the process computer either: Are in the same fuel assembly and do not differ in value by more than 2%, or
- b. For the case in which the MAPLHGR calculated by the process computer is in a different assembly than that calculated by the independent method for both assemblies, the MAPLHGR and APLHGR calculated by the tvo methods shall agree within 2% for the same assembly.
(4) The LPRM calibration factors calculated by the independent method and the process computer agree to vithin 2%. Test Objective The objectives of this test are to verify the proper operation of the Reactor Core Isolation Cooling (RCXC) system at the minimum and rated operating pressures and flow ranges, and to demonstrate reliability in automatic mode starting from cold standby vhen the reactor is at power conditions. Prereguisites The reguired preoperational tests have been completed. Initial turbine operation (uncoupled) must have been performed to verify satisfactory operation and over-speed trip. Instrumentation has been installed and calibrated. Rev. 32, 12/82 14 2-69
SS ES- FS AB Test Method- The RCEC System is desiqned .to be tested in two ways: (1) by flow injection. into a test line leading to the Condensate Storage Tank (CST), and. (2) by flow injection directly into the reactor vessel. The earlier set of CST injection tests consist of manual and automatic mode starts at approximately 150 psig and near rated reactor pressure conditions. The pump discharge pressure during these tests is throttled to be approximately 100 psi- above the reactor pressure to simulate the largest expected pipeline pressure drop. This CST testing is done to demonstrate general system operability and stability. Reactor vessel injection tests are also done which consist of manual and automatic mode starts near rated reactor pressure and automatic mode start at approximately 150 psig reactor pressure conditions to demonstrate operability and stability. After all final controller and system adjustments have been determined, a defined set of demonstration tests must be performed with that one set of adjustments. Two consecutive
. reactor vessel injections startinq from cold conditions in the:
automatic mode must satisfactorily be performed to demonstrate
'system reliability. Followinq these tests, a set of CST injections starting from cold conditions in the automatic mode are done to provide a benchmark for comparison with future surveillance tests. {>>Cold>> is defined as a minimum three days without any kind of RCIC operation.)
After the manual start portion of certain of the above tests is
,- completed, and while the system is still operatinq, small step distrubances in speed and flow command are input (in manual and automatic mode respectively) in order to demonstrate satisfactory stability. This is to be done at both low (above minimum turbine speed) and near rated flow initial conditions to span the RCXC operating range. During testinq at 150 psig, this is done only near rated flow initial conditions.
,A demonstration of extended operation of up to 2 hours (or until pump and turbine oil temperature is stabilized) of continuous running at rated flow conditions is to be scheduled at a
. convenient time during the Startup test program.
t Arceptance Cgitegia Level l The averaqe pump discharge flow must be equal to or greater than the 100% rated value in 30 seconds or less from automatic initiation at any reactor pressure between 150 psiq (+15, -0) (10.5 kg/cm>) and rated. The RCXC turbine shall not trip or isolate during auto or manual start tests Rev. 32, 12/82 14. 2-70 4
SS ES-FSAB Note: If any Level 1 criteria are not met, the reactor will only be allowed to operate up to a restricted power level defined by 14.2-7 until the problem is resolved. Also consult the 'iqure plant Technical Specifications for actions to be taken. Level 2 In order to provide an overspeed and isolation trip avoidance margin, the transient start first and subsequent speed peaks shall not exceed 5$ above the rated RCIC turbine speed. The speed and flow control loops shall be adjusted so that the decay ratio of any RCIC system related variable is not greater than 0. 25. The turbine gland seal condenser system shall be capable of preventing steam leakage to the atmosphere. The delta P switch for the RCZC steam supply line high flow isolation trip shall be calibrated to a differential pressure corresponding to less than or equal to 300% of the maximum required steady state flow, with the reactor assumed to be near the pressure for main relief valve actuation.
/ST-15} HPCI System Test Object:iye The objective of this test is to verify the proper operation of the High Pressure Coolant Injection (HPCZ) system at the minimum and rated operating pressures and flow ranqes, and to demonstrate reliability in automatic mode starting from cold standby when the reactor is at rated pressure conditions.
Prereguisites The required preoperational tests have been Initial turbine operation {uncoupled) must have been ""; completed. performed to verif y satisfactory operation and over-speed trip. Instrumentation has been installed and calibrated. Test Mei:hod The HPCI system is designed to be tested in two ways: '1) by flow injection into a test line leading to the Condensate Storaqe Tank (CST), and (2) by flow injection directly into the reactor vessel. The earlier set of CST injection tests consist of manual and automatic mode starts at approximately 150 psiq and near rated reactor pressure conditions. The pump discharqe pressure during these tests is throttled to he approximately 100 psi above the reactor pressure to simulate the largest expected pipeline pressure drop. This CST testinq is done to demonstrate general system operability and stability. Reactor vessel injection tests are also done which consist of manual and automatic mode start near rated reactor pressure to demonstrate operability and stability. Bev 32, 12/82 14 2-71
SSES-PSAR After all final controller and system adjustments have been demonstration tests must be determined, a defined set of performed with that one set of ad justments. Two consecutive reactor vessel injections startinq from cold condidtions in the automatic mode must satisfactorily be performed to demonstrate system reliability. Following these tests, a set of CST injections startinq from cold-conditions in the automatic mode {"cold" is defined to a minimum three days without any kind of HPCI operation) are done to provide a benchmark for comparison with future surveillance tests. After the manual start portion of certain of the above tests is completed, and while the system is still operatihg, small step . disturbances in speed and flow command are input {in manual and automatic mode respectively) in order to demonstrate satisfactory stability.: This is to be done at both low (above minimum 'turbine speed) and near rated flow initial conditions to span the HPCI operatinq range...During testing at 150 psig this i's done only near rated flow initial conditions. A continuous runninq test is to be scheduled at a convenient time during the Startup Test Program.. This demonstration of extended operation should be for up to 2 hours or until steady turbine and pump conditions are reached or until limits on plant operation are encountered. Pump flow testing will also be verified since auxiliary boiler supply is insufficient to fully test the sytem during the Preoperational Test Program. Acceptance Cgiterga Level 1 The average pump discharge flow must be equal to or greater than the 100% rated value in 25 seconds or less from automatic initiation at any reactor pressure between 150 psiq {+15, -0) (10.5,kg/cm~) and rated. The HPCT turbine shall not trip or isolate during auto or manual star t tests. Level 2 In order to provide an overspeed and isolation trip avoidance margin, the transient start first peak shall not come closer than 15% (of rated speed) to the overspeed trip, and subsequent speed peaks shall not be greater than 5% above rated turbine speed. The speed and flow control loops shall be adjusted so that the decay ratio of any HPCI system related variable is not greater than 0.25. The turbine qland seal condenser system shall be capable of preventing steam leakage to the atmosphere. Rev. 32, 12/82 14. 2-72
SSES-FS AB The delta-P switch for the HPCI steam supply line high flow isolation trip shall he calibrated to actuate at no greater than 300% of the maximum required steady state flow, with the reactor assumed to be near the pressure for main relief valve actuation. t ST-16) Sel e c ted Process Tem @erat ur es Test Objectives The objective of this procedure is to establish the proper setting of the low speed limiter for the recirculation pumps to avoid coolant temperature stratification in the reactor pressure vessel bottom head region. Prereguisites The required preoperational tests have been completed. System instrumentation has been calibrated. Test Qetbod-- Durinq initial heatup while at hot standby conditions, the bottom drain line temperature, recirculation loop suction temperature and applicable reactor parameters are monitored as the recirculation flow is slowly lowered to minimum stable flow Utilizinq this data it can be determined whether coolant temperature stratification occurs when the recirculation pumps are on and if so, what minimum recirculation flow will prevent it. Monitoring the preceedinq information during planned pump trips will determine if temperature stratification occurs in the idle recirculation loops or in the lower plenum when one or more loops are inactive. Acceptance Criteria gevyl 1 The reactor recirculation pumps shall not be started nor flow increased. unless the coolant, temperatures between the steam dome and bottom head drain are within 145~F. The recirculation pump in an idle loop must not be started unless the loop suction temperature is within 50oF of the active loop. T.eyel 2 Not Applicable. (ST-171 Svstem X" Fxvansion M P Test Objectives The purposes of this test are to demonstrate that reactor recirculation, main steam inside containment, and those piping systems identified in Table 3.9-33 respond to thermal expansion consistent with stress analysis results. (Note that this test now includes piping previously contained in ST-38.) Prereguisit~es Instrumentation has been installed and calibrated. Rev 32, 12/82 14. 2-73
SSES-FSAR Test Nethod Hanger positions of major.eq'uipment and piping in the Nuclear Steam Supply System and auxiliary systems in the reactor drywell are recorded prior to initial heatup and after a, planned cold shutdown. During intitial heatup, a visual inspection is made at an intermediate reactor water temperature to assure components are free to move as designed. Adjustments are made as necessary. Devices for measurinq continuous pipe deflections are mounted on main steam, recirculation and other selected lines. Notion durinq heatup is compared with calculated values. Acceptance Criteria - Level 1 There shall be no obstructions which will interfere with the thermal expansion of the main steam and recirculation piping systems. Piping systems identified in Table 3.9-33 will not be restrained against thermal expansion except by design intent. The measured displacements at the established transducer locations on the main steam and recirculation systems shall not exceed the allowable values calculated for the specific points. Level 2 The measured displacements.at the established transducer locations on the main steam and recirculation systems shall not exceed the expected values calculated for the specific points. The measured displacements at the established transducer locations on the piping systems identif ied in Table 3.9-33 shall be within the acceptable ranqe calculated for the specific poin ts.
/ST-'18} TIP Uncertainty Vegt. Objectives The objective of this test is to determine the uncertainty of the TIP system readings.
Pregeguisites System installation completed and required preoperational tests completed and verified. Instrumentation has been 'calibrated and installed. Vest Method The TIP uncertainty consists of a random apoise component and a qeometric component, the geometric component heing due to variation in the water gap geometry and TIP tube orientation from TIP location to location. Neasurement of these -components is obtained by takinq repetitive TIP readings at a sinqle TIP location, and by analyzing pairs of TIP readings taken at TIP locations which are symmetrical about the core diagonal of fuel loading and control rod symmetry. The random noise uncertainty is determined from successive TIP runs made at the common location (32-33) with each of the TIP machines making six runs at index position 10. The TIP data will be obtained by simultaneous operation of the Process computer OD-Rev. 32, 12/82 14 2-74
SSES-FSAR 2 program which provides 24 nodal TIP values for each TIP traverse. The standard deviation of the random noise is derived by taking the square root of the average of the variances at nodal levels 5 through 22, where the nodal variance is obtained from the fract,ional deviations of the successive TIP values about their nodal mean value. The total TIP uncertainty is determined by performing a complete set of TIP traverses as required by Process Computer program OD-
- 1. The total TIP uncertainty is obtained by dividing the standard deviation of the" symmetric TIP pair nodal ratios by the square root of 2. The nodal TIP ratio is def ined as the nodal BASE value of the TIP in the lower right half'f the core divided hy its symmetric counterpart in the upper left half.
The qeometric component of TIP uncertainty is obtained by statistically subtracting the random noise component from the total TIP uncertainty. The TIP data will be taken with the reactor operating with an octant symmetric rod pattern and at steady state conditions. One set of TIP data will be taken at approximately 50% power and at least one other set at 75% power or above. The acceptance criteria for this subtest uses the >>average uncertainties>> for all data sets. Therefore additional performance of the subtest may he scheduled and the previous values of uncertainty will be used in the averaqinq to determine the acceptability of the results. Ac:ceptance Cgiterga - /eve/ l Not applicable Level 7 The total TIP uncertainty {including random noise and geometrical uncertainties} obtained by averaging the uncertainties for all data sets must be less than 6.0%. NOTE: A minimum of two and up to six data sets may be used to meet the above criteria. /ST-19$ Core Performance Test Objectives The objectives of this test are a) to evaluate the core thermal pover and b) to evaluate the following core performance parameters: 1) maximum linear heat generation rate {NLHGR), 2) minimum critical power ratio (NCPR) and 3) maximum average planar linear heat generation rate {HAPLHGR). Pregeguisites The required preoperational tests have been completed. Test Method The core performance evaluation is employed to determine the principal thermal and hydraulic parameters associated with core behavior. These parameters are: R ev. 32, 12/82 14. 2-75
SSES-PSAR Core flow rate Core thermal power level MLHGR MCPR MAPLHGR Prior to the verification of the Process Computer in ST-13, an independent method will be used to calculate these parameters. After the successful completion of ST-13 'he pr'ocess computer vill be used. Acceptance Criteria Level 1 The Maximum Linear Heat Generation Rate (MLHGR) of any rod during steady-state conditions shall not exceed the limit specified by the Plant Technical Specifications. The steady-state Minimum Critical Pover Ratio (MCPR) shall not exceed the limits specified by the Plant Technical Specifications. \ The Maximum Averaqe Planar Linear Heat Generation Rate (MAPLHGR) shall not exceed the limits specified by the Plant Technical
.. Specif ications.
Steady-state reactor power shall be limited to the rated MMT and values on or below the licensed analytically determined pover-f..low line. V
. Level 2 Not applicable.
(ST-20>- Steam Production Verification
, Test Objective - The objective of this test is to demonstrate
'-; that the NSSS is providing steam sufficient to satisfy all appropriate warranties. Prereguisites Required preoperational tests have been completed. All required instrumentation is installed and calibrated. gest Method A NSSS steam output performance test of 100 hours of continuous operation at the warranted steam output will be performed. Acceptance Cgitepia-- Level 1 The NSSS parameters as determined by usinq normal operating procedures shall be within the appropriate license restrictions. Each NSSS shall be capable of supplying 13,432,000 pounds per hour of steam of not less than Rev. 32, 12/82 14. 2-76
SSES-PSAR 99.7% quality at a pressure of 985 psi~ at the outlet of the second main steam line isolation valve, as based upon a final feedvater temperature of 380oP, measured as near the reactor pressure vessel as practicable, and a control rod drive feed flow of 39,000 pounds per hour at 80oP. The reactor feedvater flow must equal the steam flow less the rod drive feed flow. Thermal-dynamic parameters are consistent with 1967 ASHE Steam tables. Correction techniques for conditions that differ from the preceeding vill be mutually agreed to prior to the performance of the test. Level 2 Not applicable.
<ST-21) Core K Power-Void
~ 0 Node Response 9 2 Test Objectives The objective of this test is to verify the stability of the core power-void dynamic response.
Prerequisites - The required preoperational tests have been completed. Instrumentation has been calibrated. Test Method The core pover void loop mode that results from a combination of the neutron kinetics and core thermal hydraulic dynamics is le'ast stable near the natural circulation end of the rated 100 percent power rod line. A fast change in the reactivity balance is obtained by moving a very high worth rod only 1 or 2 notches and by simulating a failure of the pressure regulator. Acceptance Criteria Level 1 The transient response of any system related variable to any test input must not diverge. -Level 2 Not applicable. (ST-22) Pressure - Reau 1 at or Test Objectives-- The objectives of this test are to demonstrate the takeover capability of the backup pressure regulator upon failure of the controllinq pressure regulator and to demonstrate smooth pressure control transition between the control valves and bypass valves vhen reactor steam generation exceeds steam flov used by the turbine. Prereguisites The required preoperational tests have been completed. Instrumentation has been checked or calibrated as appropriate. Test Net.hod - The pressure set point vill be decreased rapidly and later increased rapidly by about 10 psi and the response of the system vill be measured in each case. It is desirable to accomplish the set point chanqe in less than second. At specified test conditions the load limit setpoint vill be set so 1 R ev. 32, 12/82 14 2-77
SS ES-PSAR that the transient is handled by control valves, bypass valves and both. The backup requlator vill be tested, by simulating a failure of the operating pressureThe regulator so that 'he backup regulator takes over control. response of the system will be measured and evaluated. Acceptance Criteria Level 1 The transient response of any pressure control system related variable to any test input must not diverge Level 2 a) Pressure control system related variables may contain oscillatory modes of response. In these case , the decay ratio for each controlled mode of response must be less than or equal to 0. 25 vhen operatinq above lover limit of the automatic load folloving range. b) When in the recirculation manual mode, the pressure response time from initiation of pressure setpoint step change to the turbine inlet pressure peak shall be (10 seconds. c) Pressure control system deadband, delay,'tc., shall be small enouqh that steady state limit cycles (if any) shall produce steam flow variations no larger than +0.5 4 percent of rated steam flow The normal difference betveen regulator set points must be small enouqh that the peak neutron flux and/or peak vessel pressure remain below the scram settings by 7.5 percent and 10 psi respectively, fo r the Regula tor Failure Test performed at Test Condition 6. tST-23k Feedwater System Test Objectives The objectives of this test are a) to demonstrate acceptable response to the feedwater control system for reactor water level control, b) to demonstrate stable reactor response to subcoolinq changes, i e., loss of feedvater heating, c) to demonstrate the capability of the automatic core flow
. runback feature to prevent low vater level scram following the trip of one feedwater pump, and d) to demonstrate the maximum feedpump runout capability is compatable with licensing assumptions.
'rer~guisites The required preoperational tests have been
'completed. Instrumentation has been checked or calibrated as appropriate.
Tegt Method At Test Condition {TC) 1 with the vater level being automatically controlled using the lov load, valve and the Hev. 32, 12/82 1 4 2-78
SSES-,PSAR recirculation system in Manual, +5 inch step changes in the water level setpoint vill be made to demonstrate proper response and operability of the feedvater system at lov reactor power. At Test Conditions 2 3 and 6, vith one feedvater pump in manual
~
and the others in auto, a +5% change in the manually controlled feed pump will be made. The, response of the feedwater system to these steps will he analyzed and compared to the applicable acceptance criteria. The recirculation system vill be in manual for these tests. At Test Conditions 1, 2, 3, 4, 5 8 6 vith the
~
recirculation system in..manual, +5 inch changes in the vater level setpoint will be made to demonstrate proper response and stability of the feedwater system. At TC 6, this test vill also be done with the recirculation system in auto. At approximately 80$ power, a simulated loss of power to the extraction steam bleeder-trip valves vill be initiated vhich vill result in the most severe restriction of extraction steam to one feedwater heater string. Recordings of th'e transient'vill be as analyzed and compared to the predicted response and acceptance criteria. At Test Condtion 6, one feedvater pump vill be tripped to demonstrate the capability to avoid a scram and prevent a lov reactor water level trip due to the loss of one feedwater pump. A maximum feedvater runout capability test will be done to demonstrate that the actual capability is compatible vith licensinq assumptions. Acceptanre Criteria Level 1 The transient response of .any level contxol system-related variable to any test input must not d iverqe. For the feedvater heater loss test, the maximum feedwater temperature decrease due to a single failure case must be less h ., e
~
than or equal to 1000P. The resultant HCPR must be greater than the fuel thermal safety limit. The increase in heat flux cannot exceed the predicted Level 2 value by more than 2%. The predicted value will be based on the, art'ual test values of feedvater temperature change and power
~
level. The feedvater flow runout capability must not exceed the assumed value in the PSAR. Level 2 Level control system-related variables may contain oscillatory modes of response. In these cases, the decay ratio for each controlled mode of response must be less than or equal to 0. 25 Pev. 32, 12/82 14 2-79
SSES-FSAH The open loop dynamic flow response of each feedwater actuator {turbine or valve) to small (<10%) step disturbances shall be: (1) Maximum time to 10% of. a step disturbance 1. 1 sec. (2) Maximum time from 10$ to 90% of a step disturbance l. 9 sec (3) Peak overshoot (% of step disturbance) <15K The averaqe rate of response of the feedwater actuator to large ()20'5 of. pump flow) step disturbances shall be between 10 percent and 25 percent rated feedwater flow/second. This average response rate will he assessed by determining the time required to pass linearly through the 10 percent and 90 percent response poi nts. The increase in heat flux cannot exceed the predicted value referenced to the actual Feedwator temperature change and the initial power level. h scram must be avoided from lov water level with at least a 3 inch marqin followinq a trip of one of the operating feedwater Dumps+ l ST-241~ A Tu rhine
~
Valve Surveillance Test Ahjectives The objective of this test is to demonstrate acceptable procedures and maximum power levels for periodic urveillance +estinq of the main turbine control, stop, intercept and bypass valves without producinq a reactor scram. Prerequisites The required preoperational tests have been completed. Instrumentation has been checked or calibrated as a ppropriate. Test Nethod Starting at 45 to 65% power, and continuing at proaressively higher power levels, each turbine control, main stop and intermediate stop valve will be closed individually and t he response of the reactor will be observed. The margin to scram for reactor pressure and neutron flux and the margin to main steam line isolation will be plotted for each tested power level. 'hese plots will be used to determine the maximum power level at which turbine valve surveillance testinq can be performed. The test of the control, main stop, intermediate stop and bypass valves are performed near the predicted highest power level to demonstrate that the Acceptance Criteria are satisfied. Rate of. valve strokinq and timinq of the close-open sequence vill be such that minimum practical disturbance is introduced and that PCIOMH li mi ts a re not e xc ceded. Acceptance Criteria Level 1 Not applicable. Level p Peak neutron flux must remain at least 7.5% below the Neutron flux .cram trip value. Peak vessel pressure must remain
,Rey. 32, '2/82 14 2-80 4..'-;,
at least 10 psi below the high pressure scram setting. Peak steam flow in each line must remain at least 10$ below the high flow isolation trip setting. peak simulated heat flux must remain at least 5% below its scram trip point.
/ST-25) pain Stgam Isolation Valves Test objectives The objectives of this test are (a) to functionally check the main steam isolation valves (MSIVs) for proper operation at selected power levels, (b) to determine reactor transient behavior durinq and following simultaneous full closure of all MSIVs, (c) to determine isolation valve closure t ime and (d) to determine the maximum power at which a single valve closure can be made without a scram.
Preregui~ites The required preoperational tests have been completed. Instrumentation has been checked or calibrated as appropriate. Test L!ethos The Main Steam Isolation Valves {MSIVs) are operated durinq this test to verify their functional performance and +o determine closure times. While functionally testing the operation of the HSIVs, the time necessary for closinq each individual valve will be noted. The fastest MSIV will then be tested +o determine what power level an MSZV can experience fast closure without causinq a scram. All MSIVs will later be used to demonstrate a full isolation subsequently leading to a scram. (The Nuclear Steam Supply Shutoff System (NSSSS) logic will be used to ini tiate the full isolation) . The acceptability of the fast criteria (3 seconds) is determined by utilizing the full stroke time without dealy extrapolated from measured stroke times between 10% closed and 905 closed. The acceptability of the slow criteria (5 seconds) is determined by utilizinq the full stroke time with delay extrapolated for the final 10% of stroke. The positive chanqe in vessel dome pressure occurring within 30 seconds after closure of all MSIVs must not exceed predicted values by more than 25 psi. The positive change in heat flux followinq closure of all MSIVs shall not exceed predicted values by more than 2% of rated value. Fol lowinq the closure of all MSIV's, the reactor must scram. The. averaqe of the closure times for the fastest, MSIV in each ,steam line, exclusive of delay, shall not be less than 3. 0 second s. Closure time for any MSIV, includinq delay, shall not be greater t ha n 5. 0 second s. Rev. 32, 12/'82
SSES-PS AR Closure time for the fastest MSIV shall be. greater than or equal to 2.5 seconds. Feedwater control settinqs must prevent flooding the main steam lines durinq the full isolation test. The time delay between the close initiation signal and the extrapolated initial valve movement from 100% open for any MSIV shall be less than or equal to 0.5 seconds. Level. 2 The positive change in vessel dome pressure occurring vithin the first 30 seconds after the closure of all MSIVs must not exceed the predicted values. Predicted values vill be referenced to actual test conditions of initial power level, scram timing and dome pressure and vill use beginning of life n ucl ear data. The positive change in heat flux occurring within the first 30 seconds after the closure of all MSIVs must not exceed the nrehicted values. Predicted values will be referenced to actual test conditions of initial pover level, and dome pressure and vill use beqinninq of life nuclear data. If water level reaches Level 2 setpoint during the MSIV full
. closure test RCIC shall automatically initiate and reach rated
'"lov.'" ~
"",'-,':<<"Diirinq the NSIV full closure test, the relief valves must reclose oroperly (without any detectable leakage) following the pressure [ transient. During full closure of individual MSIVs, peak vessel home pressure must remain at least 10 psi below the flow biased scram sett inq value. Durinq full closure of individual MSIVs, peak neutron flux must remain at least 7.5% below its scram value. Durinq full closure of individual MSZVs, steam flow in individual lines must remain at least 10% helow the high flow isolation trip sett ing. Durinq full closure of individual MSIVs, the peak simulated heat
-,. flux. must remain at least 5% less than its scram value.
sT-26> R l Valves Relief Tegt. Qhjectiyes - The objectives o5 this test are to verify that the relief valves function properly, reseat properly after operation and contain no malor blockages in the relief valve discharge pipinq. R ev. 32, 12/82 10. 2-82
SS ES-FS AH Pregeguisiteg The required preoperational tests have been rompleteÃ. Instrumentation has been checked or calibrated as appropriate. Factory test results on SHV flow and operating times have been reviewed. Test Method Testing done at 250 psiq reactor pressure consists of cycling each relief valve to verify proper operation. The transient monitorinq system will be used to record the results of this test. The data collected will compare the operation of individual relief valves against the operation of all relief valves. During relief valve operation, core power and therefore steam generation rate is maintained constant. The pressure control system will close the bypass valves an amount proportional to the relief valve steam flow to maintain constant reactor pressu e. This bypass valve motion will be monitored and a comparison of the response for each relief valve operation will be made. If differences exist, it could suggest a partial obstruction of the relief valve or its tailpipe. Tailpipe temperature will be recorded to verify the relief valve has properly reseated. Reactor variables will also be recorded to verify system stability during opening and closing each relief valve-Testing done at rated reactor pressure consists of manually operatinq each relief valve at rated reactor pressure. The decrease in Main Generator output will be monitored during the operation of each relief valve to provide an indication of relief
.valve flow. By comparison of the generator output response for .each'relief valve operation, any flow obstruction in the valve or its tailpipe can. be identified. Each valve will be opened for approximately 10 seconds to allow for variables to stabilize.
Reactor variables will also be recorded to verify system stability durinq openinq and closing each relief valve. hccentance Criteria Level l There should be a positive indication of steam discharge during the manual actuation of each valve. Level 2 pressure control system-related variables may contain oscillatory modes of response. In these cases, the decay ratio for each controlled mode of response must be less than or equal to 0. 25. The temperature measured by thermocouples on the discharge side of the valves shall return to within 10~F of the temperature recorded before the valve was opened. During the low pressure functional tests, the change in bypass valve position for each SRV opening shall be greater than or equal to a value corresponding to the average change minus 10% of one bypass valve. ,:P ey. 32; 12/82 14. 2-83
SS ES- FS AR Durinq the rated pressure tests, the change in NMe for each SRV oponinq shall be greater than or equal to a value corresponding to the average chanqe minus 0.5% of rated HMe. /ST-27) Turbine Trig hand Generator Load Reaction Test Objertiyes The objective of this test is to demonstrate the response of the reactor and its control systems to protective trips in the turbine and qenerator. Prereguisites The required preoperational tests have been completed. All instrumentation has been calibrated. Test Me.t.hod At Test Condition 3, a turbine trip will be manually initiated by depressing the Turbine Trip pushbutton in the main control room. At Test Condition 6, a generator load rejection will be manually initiated by remotely opening the qenerator synch onizinq breaker from the control room. During hoth transients, reactor water level, pressure, neutron flux and simulated heat flux will be recorded and compared to predicted results and acceptance criteria. At approximately 24% power, a qenerator load rejection within bypass capacity will be manually initiated as described above. This will demonstrate the ability to ride through a load rejection within bypass capacity without a scram. During all 3 transients, main turbine stop, control and bypass valve positions and reactor water level will be recorded and compared to the acceptance criteria. Acreotance Criteria Level 1 a) For Turbine and Generator trips there should be a delay of no more than 0.1 seconds followinq the beginning of control or stop valve closure before the beginning of bypass valve opening. The bypass valves should be opened to a point corresponding to greater than or equal to 80 percent of full open within 0.3 seconds from the beqinninq of control or stop valve closure motion. h) Peedwater system settinqs must prevent flooding of the steam line followinq these transients. c) The positive change in vessel dome pressure occurring within 30 seconds after either generator or turbine trip must not exceed the Level 2 criteria by more than 25 psi. Rev. 32, 12/82 14. 2-84
SS ES- FS AR d) The positive chanqe in simulated heat. flux shall not exceed the Level 2 criteria by more than 2%%d of rated value. Level 2 a) There shall be no NSIV closure in the first 3 minutes of the transient and operator action shall not be required in that period to 'avoid the NSIV trip. b) The positive chanqe in vessel dome pressure and in simulated heat flux which occur within the first after the initiation of either qenerator or 30'econds turbine trip must not exceed the predicted values. (Predicted values vill be referenced to actual test conditions of initial pover level, dome pressure, scram timing, and the time from the start of stop/control valve motion to start of control rod motion, and vill use beginning of life nuclear data. ) c) For the Generator trip within the bypass valves capacity(initial thermal power values less than or equal to 25 percent of rated) the reactor shall not sera m.
', [ST-28) Shutdown from Outside the Main Control Room Tegt. Objective The objective of this test is" to demonstrate that. the reactor can be shutdown, maintained in a hot shutdown condition, and cooled down from outside the main control room.
Also, the adequacy of the Emergency Operating Procedures vill be verified. Pregeguisites - The required preoperational tests have been Instrumentation has been checked or calibrated as E completed.
'1,~' a ppropria te.
i' Yes't Method While operatinq at approximately 20% power synchronized to the grid with normal electrical system alignment, the reactor will be scrammed and the NSIV's will be closed from inside the main control room. The control room vill then be I evacuated, and reactor level and pressure vill be controlled from outside the main control room. The Shutdown Cooling mode of RHR vill be placed into service vith coolinq water supplied from the ultimate heat sink. During this demonstration, some supervisory and operatinq personnel vill remain in the control room to protect non-safety-related equipment from unnecessary damage if conditions arise and to assume control of the plant if warrant. A test will be run to demonstrate that the reactor can conditions be scrammed and isolated from outside the control room. , '.."".,'; ","-."..'= ~-..'; Rev., 32, 12/82 14- 2-85 lf 4,'I
SS ES- PS AR Acregt'anre Crjtegia Level 1 Not applicable. Level 2 During a simulated control room evacuation, the reactor must be brought to the point vhere cooldown is initiated and under control, and the reactor vessel pressure and water level are controlled usinq equipment and controls outside the control room. The test is deemed successful when reactor pressure is less than 98 psiq fpermissive setpoint) and the RHR shutdown
! coolinq mode has been put in operation.
The reactor must be capable of beinq scrammed and isolated from outside the control room. (ST-291) Recirculation Plow Control System The objectives of this test are: a) To demonstrate the flow control capability of the plant over the entire pump speed range, including individual local manual, combined Master Manual Operation and Automatic Load Pollovinq. To determine that all electrical compensators and
'L b) controllers are set for desired system performance and stability.
Pregeguisites The required preoperational tests have been
.completed.
All instrumentation has been calibrated. Test Net.hod At Test Conditions 2, 3, 5 and 6, the stability of the recirculation flow control system is demonstrated by performinq step chanqes in recirculation pump speed vhile in the manual mode. This testing is also done in the auto mode at Test Conditions 3. 5 and 6. Step changes in recirculation pump speed -;,, are done alonq the 100% rod line to demonstrate operability and stability in the auto mode and to set the lover limit of auto mode operatio.n. Acceptance Cgiteri,a J,evel 1 The transient response of any system-related variable to any test input must not diverge. 2 - A scram shall not occur due to recirculation flow '.evel control maneuvers. The APRH neutron flux trip avoidance margin shall be greater than or equal to 7.5X ynd the simulated heat flux trip avoidance marqin shall be greater than or equal to 5% when the power maneuver effects are extrapolated to those that vould occur along the 100'0 rated rod line. R ev. 32, 12/82 10 2-86
SSES-FSAR 7he decay ratio of any oscillatory controlled variable must be less than or equal to 0.25. Steady state limit cycles (if any) shall not produce turbine steam flov variations greater than +.5% of rated steam flow. In the scoop tube reset functions, the speed demand meter must aqree with the sPeed meter within 6% of rated generator speed, alonq the 100'5 rated rod line.
~ST-30~Rec'ulat on S. Y stem Test Objectives The objectives of this test 'are:
- a. Obtain recirculation system performance data during pump trip, flow coastdovn, and pump restart.
- b. Verify that the feedvater control system can satisfactorily control water level vithout a resulting turbine trip and associated scram.
- c. Record and verify acceptable performance of the recirculation two pump circuit trip sytem.
't Verify the adequacy of the recirculation runback to mitiqate a scram.
P. ~ Verify that no recirculation system cavitation will occur in the operable region of the power-flow map.
,Prerequisites The required preoperational tests have been rompleted. Instrumentation has been checked or calibrated as a ppropriate.
Test Method - Sinqle recirculation pump trips vill be made at Test Condition (TC) 3 and TC-6. These trips will be initiated by trippinq the M-G Set Drive Notor Breaker from the control room. Reactor Parameters vill be recorded during the transient and - analyzed to verify non-divergence of oscillatory responses, adequate marqins to RPS scram set points, and capability of the feedwater system to prevent a high level trip. The capability to restart the recirc. pump at a high power level vill also be demonstrated. At TC-3, both recirculation pumps RPT breakers will be simultaneously tripped using a temporarily installed test switch. The data gathered vill be used to demonstrate acceptable Pump coastdown perf ormance prior to high power turbine trips and generator load re sects. Appropriate conditions will be simulated at TC-3 to demonstrate the proper operation of the recirculation pump runback circuits. This is done prior to an actual planned feed pump trip at rated pover. R ev. 32, 12/82 14 2-87
SSES-PSAR Goth the jet pumps and the recirculation pumps vill cavitate at conditions of high flow and lov power where HPSH demands are high and little feedwater subcoolinq occurs. However, the recirculation flov vill automatically runback upon sensing a decrease in feedwater flov. The maximum recirculation flov is limited by appropriate stops which vill run back the recirculation flow from the possible cavitation region. At TC-3, it. will be verified that these limits are sufficient to prevent operation where recirculation pump or jet pump cavitation occurs. Acceptance. Criteria Lyvgl 1 The response of any level related variables durinq a single pump trip must not diverge. The two pump drive flow coastdovn transient, during the f irst 3 seconds of an RFT trip, must fall vithin the specified bounds. Level 2 The reactor shall not scram during the one pump trip. The APRN margin to avoid a scram shall be at least 7.5% during the one pump trip recovery. The reactor water level marqin to avoid a high level trip shall be at least. 3.0 inches during the one pump trip. peak simulated heat flux must remain at least 5X belov its scram trip point. Runback loqi" shall have settings adequate to prevent f r ec i rcu la t ion pum p opera t ion in a reas o pote n tia 1 ca vita tion.
,.7he recirculation pumps shall runback upon a trip of the runback
';:,; circuit.
/ST-31) Los@ of Tggbine-Generator aHQ Offsite Power Test obgec".tives The objectives of this test are to demonstrate that the required safety systems vill initiate and function properly vithout manual assistance, the electrical distribution and diesel generator systems vill function properly, and the HPCI and/or BCIC systems will maintain water level turbine-generator if necessary during and offsite a simultaneous loss of the main power.
Preregiiisites The required preoperational tests have been completed. Instrumentation has been checked or calibrated as
~ ppropriate.
>est t1ethod - Mith the unit synchronized to the grid at approximately 30% power, the main turbine-generator vill be manually tripped immediately followed by a manual trip of the unit~s offsite power source breaker, both trips initiated from the control room. To ensure a full simulation of the loss of all R ev. 32, 12/82 14 2-88
SSES-PSAR o f f site power to Unit 1 during Unit 1 testing, all Unit 1 and Common loads vill be transferred to Unit Auxiliary and Startup 1 Busses and appropriate breakers racked out to prevent automatic transfer of the loads to Unit 2 sources. During Unit 2 testing, to ensure a full simulation of the loss of all offsite pover to Unit 2 while minimizing the impact on Unit 1 operations, all Unit 2 loads vill be transferred to Unit 2 Auxiliary and Startup busses, all Unit l and common loads vill be transferred to Unit 1 Auxiliary and Startup Busses, and appropriate breakers will be racked out to prevent automatic transfer of Unit 2 loads to Unit 1 sources Reactor water level and the operation of safety systems will be monitored to verify that the acceptance criteria are satisfied. The- proper response of the electrical distribution system vill be checked. The l.oss of offsite power condition will be maintained for at lea .t 30 minutes to demonstrate that necessary eguipment, cont.rois, and indication are available folloving station blackout to remove decay heat from the core using only emergency power supplies and distribution system. Ac:ceptance Cgitegia Level l All'safety systems such as the Reactor Protection System, the diesel-generator, RCIC and HPCI must function properly without manual assistance, and HPCI and/or ACMIC system action, if necessary, shall keep the reactor water level above the initiation level of Core Spray; LPCI and ADS Level 2 Not applicable.
/ST-3>l Containment atmosphere gnd gain Steam gunnel Cooling Test Object.iye The objective of this test is to verify the ability of the dryvell coolers/recirculation fans and the reactor buildinq portion of the main steam tunnel coolers to maintain desiqn conditions in the dryvell and reactor building portion of the mainsteam tunnel, respectively, during operating conditions and post scram conditions. This test also demonstrates that containment main steamline penetrations do not overheat adjacent concrete.
C Preroguisites The required preoperational tests have been 'completed. Instrumentation has been checked or calibrated as appr'opriate.- Test Method During heatup, at test conditions 2 and 6, and followinq a planned scram from 00% power, data vill be taken to ascertain that the containment atmospheric conditions are within des ig n limits. Acceptance Criteria Level 1 not applicable Rev. 32, 12/82 14 2-89
SSES-FS AR Level 2 The qeneral drywell area is maintained at an average temperature less than or equal to 1350F, with maximum local
+emperature not to exceed'150~F.'he area beneath the reactor pressure vessel is maintained at an average temperature less than or equal to 135<F ~ maximum local temperature not to exceed 165~P, with minimum local temperature above 100~P.
The area around the recirculation pump motors is maintained at an average tempera+ure less than or equal to 'l28oF, with maximum local temperature not to exceed 135~P. The inside base of the shield wall in the HPV skirt area is maintained at temperatures greater than 100oF. The reactor buildinq portion of the mainsteam pipeway is maintained at or below 120~F. The concrete temperature surroundinq the main steamlime
,penetrations is maintained at less than 200~P.
)ST.-33} Piping Steady State Vibration Test objectives The objectives of this test is to demonstrate
+hat steady state vibration levels on reactor recirculation, -main steam inside containment, and those piping systems identified in Table 3.9-33 are within acceptable limits. (Note that this test now includes piping previously contained in ST-40. Also note that dynamic transient vibration testinq previously contained in
.:+his test have been merqed into ST-39.)
~i'-:"i~."=:-."-'" Prepreguisites Instrumentation has been installed and calibrated.
7est Method Devices for measuring continuous vibration are mounted on main steam and recirculation lines and vibration during steady state operation is compared with calculated values. Acceptance (:gitgrga Level l The measured amplitude {peak to
' -,neak) of each remotely monitored point on the main steam inside containment and reactor recirculation lines shall not exceed the allowable value for that point.
Level 2 The measured amplitude {peak to peak) of each remotely monitored point on the main steam inside containment and reactor recirculation lines shall not exceed the expected value for that point. The vibratory response of. non-remotely monitored systems or portions of systems indentified in Table 3.9-33 shall be judged to be within acceptable limits by a qualified test engineer. Rev. 32, 12/82 14 2-90
SSES-PSAR The. maximum measured amplitude of the piping response for each remotely monitored point on systems identified in Table 3.9-33 shall not exceed the acceptable value for that point. f ST- 34>Con t r ol 8 od Seau en ce Exc ha na e fThis test number vas previously assigned to the RPV Internals Vibration test which is nov performed during the Preoperational Test Program. The test description for the RPV Internals Vibration test is now in TP2. 16 which follovs the abstract for P64.1 ) Test Objective The objective of this test is to perform a representative sequence exchange of control rod patterns at the power level at vhich such exchanges vill be done during plant operation and demonstrate that core limits and PCIOMR threshold limits will not. be exceeded. Prereguisites - Instrumentation has been checked or calibrated as appropriate. Test NethoB The control rod sequence exchange begins on the desiqn flov control line with core flov near minimum. Control rods vill be inserted as necessary to increase the margin to 3ocal core thermal limits. Core power is maintained above the low power setpoint of the Rod cnorth Minimizer and Rod Sequence Control System and belov the power vhich vill keep fuel assembly nodal power at the PCIOMR threshhold. The exchanqe is performed in accordance vith the plant operating procedure RE-TP-009. Data taken during the exchange will be reviewed to verify that the Acceptance Criteria vere satisfied. Acceptance Criteria peyel l Completion of the exchange of one rod pattern for the complimentary pattern with continual satis faction of all licensed core limits constitutes satisfaction ~ of the requirements of this procedure. t,evel 2 All nodal povers shall remain below their PCIOMR threshold limit durinq this test.
/ST-35$ Becigculagjon System Plow Calibration Test Ohjertiyes The objective of this test is to perform a complete calibration of the installed recirculation system flov instrumenta tion.
Prereguisites The required preoperational tests have been completed. Instrumentation has been checked or calibrated as a ppropriate. Test Method During the testing program at selected operatinq conditions vhich allov the recirculation system to be operated at Bev. 32, 12/82 14. 2-91
SS ES-PSAR speeds required for rated flov at rated power, the jet pump flos instrumentation vill be adjusted to provide correct flow indication based on the jet pump flow. After the relationship between drive flov and core flow is established. the flov biased APBM/RBM system sill be adjusted to match this relationship. Acceptance Cgiteria geyel 1 Not applicable. t.eyel g Jet pump flov instrumentation shall be adjusted such that t.he jet pump total flov recorder vill provide a correct core flow indication at rated conditions. The. APRM/RRM flov-bias instrumentation shall be adjusted to function properly at rated conditions. Test. Qhjectiyes The objective of this test is to verify that the performance of the Reactor Building Closed Cooling Mater (RBCCM) ~ the Turbine Buildinq Closed Coolinq Mater (TBCCW), and Service Mater Systems are adequate with the reactor at rated temperature. Prereguisites The required preoperational tests have been completed. Instrumentation has been checked or calibrated as a ppropriate. Test Method Mith the reactor operatinq at 100% poser, data sill be obtained to verify that the heat exchanger outlet temperatures are within design values. Acceptance Criteria level l Not applicable. Level 2 The Service Mater pump discharqe header temperature is less than 9SOP. The RBCCM Heat Exchanger RBCCM outlet temperature is at 100o + 5oP. The TBCCM Heat Exchanger TBCCM outlet temperature is at 100> + 5~p. (ST-37l ~ Gaseous Radwaste
~
System Test Objectives .The objective of this test is to demonstrate that the Gaseous Badwaste System operates within the Technical Specification and design limits durinq a full ranqe of plant pover operation and to demonstrate the proper operation of the containment nitrogen inertinq system during plant operation. Prereguisites. The required preoperational tests have been completed. Instrumentation has been checked or calibrated as appropriate. In addition, the 100% power trip testing shall have R e v. 32, 12/82 14. 2-92
SSES-PSAR been completed or 120 effective full power days shall not have elapsed prior to performing the nitrogen inerting test. Test Met:hod The test will consist of collecting data and Performinq quantitative analysis of the off gas system influent and effluent to determine if the Performance is acceptable per desiqn and Technical Specification. Por the nitrogen inerting system, the proper nitroqen concentration will be verified by the as installed plant oxygen detectors/instruments in the two major volumes of the primary containment Acceptance Criteria Level 1 The release of radioactive gaseous and particulate effluents must not exceed the limits specified in the site technical specifications. Level 2-The system flow, pressure, temperature,, and relative humidity shall comply with desiqn specifications. The catalytic recombiner, the hydroqen analyzer, the activated carbon beds and the filters shall be performinq their required function. There coequal he no less than 8000 lb/hr. shall of dilution steam flow when the
.,team jet. air ejectors are pumpinq. The containment nitrogen inertinq system shall be capable of inerting the primary containment free volume within 24 hours .from the start of the test and the resultinq oxygen concentration shall be less than or to 4%. /ST-38/ Rgp pggigg System gxpapsion (The system expansion testing previously contained in this test has been merged into ST-17.)
W (ST-39l Pioina Vibration Durina Dvnamic Transients Test objective - The objective of this test is to demonstrate that vibration levels on main steam inside containment, reactor recirculation, and system piping identified in Table 3.9-33 meet acceptable limits durinq selected dynamic transients. Prereguisites: Instrumentation has been installed and calibrate ion. Test Nethod Devices for measurinq continuous loads, displacements, accelerations and pressures are mounted on piping systems and responses during transients are compared with calculated values. Those portions of the systems which are non-safety related are visually inspected prior to, during and subsequent to the transient loadinq condition. I l N Acceptance Criteria Level The measured vibration amplitude (peak to peak) for each remotely monitored point of main steam inside drywell and/or reactor recirculation piping shall not exceed the allowable value for each specific point. R ev. 32, 12/82 14- 2-93
SS ES-FSAR Level 2 The maximum measured loads, displacements, accelerations and pressures on those systems listed in Table 3.9-33 shall not exceed the desiqn maximum expected, values at each specific point. The vibratory response of non-remotely monitored systems identified in Table 3.9-33 shall be judged to be within acceptable limits by a qualified test engineer. Based on visual inspection during a post transient walkdown, there shall be no siqns of excessive piping response (such as damaged insulation, markings on piping, structural or hanger steel, or walls, damaqed pipe supports, etc.) on 'systems listed in Table 3. 9-33. The measured vibration amplitude (peak to peak) for each remotely monitored point of main steam inside drywell and/or reactor recirculation piping shall not exceed the expected value for each specific point. (ST 401BQP Piscina Steady State Vibration {The steady state vibration testinq previously contained in. this test has been merq'ed into ST-33.)
- 14. 2. 12. 3 ~ au, Peauested A ota Acceotance Test Procedure Te A r Abstracts Tests comprisinq the Acceptance Test procedures are listed in Table 14.2-2. For each test a description is provided for
- .objective, prerequisites, method and acceptance criteria, where aoplicable. Modifications to these descriptions will be reflected in amendments to the FSAR.
A3 1 13. 8 KV SYSTFM ACCEPTANCE TgST Test objective. - To demonstrate the capability of the 13.8 kV system to provide electrical power to the Startup and Unit Auxiliary 13.8 kV Busses by demonstrating the proper operation of breakers, relaying and logic, permissive and prohibit interlocks, a nd inst rum en ta tion a nd alarms. Preregiiisites - Construction is completed to the extent necessary
;to perform this test and the systems are turned over to the ISG.
Required 230 kV transmission lines are available to energize the 13.8, kV system. Required instruments and, protective relays are calibrated and controls are operable. Test 'getho0 Breakers are opened and closed by operating or simulatinq controls to verify breaker operation, relaying and R e'v. 32, 12/82 14. 2" 94
SSES-PSAR logic, permissive and. prohibit interlocks, instrumentation and alarms, and automatic transfers. Acceptance Criteria The system performance parameters are in accordance with applicable desiqn documents. A7 1 LIGHTING SYSTEM AND MISCELLANEOUS 120V DISTRIBUTION ACCEPTANCE TEST Test Objectives To demonstrate the ability of the St'ation Battery Liqhtinq System to automatically transfer on loss of the Normal power feed, to demonstrate the ability of the Control Room Fmerqencv Liqhtinq Units to provide limited i'llumination upon loss of the Essential Lighting System, and to provide a format for tabulation of Technical Procedures (TPs) performed on system components durinq startup testing. Prereguisites Construction is complete to the extent necessary to perform this test and the system is turned over to the ISG. Normal a nd essential 480 volt AC and 125 volt DC power is available. Requixed test instruments are calibrated and controls a re'perable. 'Pest Method - The Station Bat tery Lighting System and Control Room Emergency Lighting System are tested by interrupting normal power supply feeds and verifying proper switchover from normal to emerqency power. Arceptan're Criteria The system performance parameters are in accordance with the applicable design document. A 11. 1 STATION SERVICE WAgER SYSTEM ACCEPTANCE TEST Test Objective To demonstrate the capability of Station Service Water Sy tern to provide coolinq water to connected components/systems. Prereggisites Construction is complete to the extent necessary 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. Mater supply from the coolinq tower is available. Test Method System operation is initiated normally. The system is operated in the different desiqn modes and Service Water Pump performance is determined. Required controls are operated or simulated siqnals are applied to verify automatic features, system interlocks and alarms. Acceptable Criteria The system performance parameters are in accordance with applicable desiqn documents. Rev. 32, 12/82 14 2-95
SSES-FSAR TBCCM SYSTEM ACCEPTANCE TQST Test Objective To demonstrate proper operation of the TBCCM system, specifically to furnish coolinq water to miscellaneous turbine plant heat exchanqers, coolers, and chillers, and to demonstrate the abiltiy of a standby pump to automatically r eplace the operatinq pump in case of pressure loss in the header. Prereguisites Construction is completed to the extent necessary to perform this test and the'system is turned over to the TSG. Required electrical power supply systems are available to energize the necessary 480 volt motor control centers. Required insruments are calibrated and controls are available. The service water system is available. The instrument air system is available. Tc st g~tbod The system operation is initiated manually, and where applicable automatically. The syste~ is operated in the system design modes and TBCCM pumps performance is determined. Required controls are operated or simulated to verify automatic system functions and alarms. Acceptance Criteria is capable of delivering Ic
- 1) Each of the two TBCCM pumps a minimum flow of 292.5 qpm.
- 2) With one pump in operation, the standby pump starts automatically at a low header pressure of less than or equal to 70 psiq.
- 3) The TBCCM system provides cooling water to the following:
- a. Control rod drive pump bearing and oil coolers
- b. Condensate pump motor bearing coolers
- c. Instrument air compressor coolers
- d. Service air compressor coolers
- e. " EHC fluid coolers 4 f. Turbine Buildinq sample station chillers station chillers
~
- q. Auxiliary Boiler sample A18.1 INSTRUNENT AIR SYSTEM ACCEPTANCE TPST Test Objective The general objective of this test is to demonstrate proper operation of the Instrument Air System.
Specific objectives are to demonstrate the followinq:
- 1) The ability of the Instrument Air System to provide air to outlets located throughout the plant.
h
- 2) System "ontrols function in accordance with design intent.
I
~ Rev 32, 12/82 14 2-96
SSZS-PSAR
- 3) Alarms function properly to provide alert of an abnormality in the Instrument Air System.
- 4) Instrument air dryers reduce instrument air moisture in accordance with desiqn requirements.
- 5) Standby Instrument Air Unit, under AUTO Mode, starts automatically when the system pressure is down.
Prerequisites Construction turnover of the system is complete to the extent required to.conduct the test. The system has been walked through, verified complete and air blowing hah been completed. The required Technical Tests have been completed and the required instruments are calibrated. Test Method - Both compressors are fully tested in both Manual and Auto mode of operation. The Dryer packaqes are tested for effectiveness and all automatic trips and alarms are verified. Acceptance Criteria The system performance parameters are in accordance with applicable enqineerinq design documents. PP 4 A 19 1 S EH VICE AIR S Y~STgg ACCEPT ANCE T EQT 4 44 Test ohjectives The objectives of this test 'are as follows:
- 1) To demonstrate that the compressors can provide pressurized air (115-130 psiq) to outlets located throughout the plant.
- 2) To Remonstrate that system controls and alarms function in accordance with the desiqn intent.
To demonstrate that. the standby compressor will start 4 P, 3) automatically if the system pressure is lov. P 4 Prerequisites The prerequisites of this test are as follows: Construction is complete to the extent necessary to conduct 4 1)
- 2) 'llthis test and system is turned over to XSG.
component inspections, tests and calibrations have been completed satisfactorily. Test Method The system will be pressurized by starting the 4 rompressors Compressor modes and functions will be checked for proper operation. Alarms will be verified as they are induced durinq normal operation or simulation.
,,P ~
Acceotance Criteria 4
-4 Rev. 32, 12/82 14 2-97
SSES-FSAR
- 1) The service air compressors have the capacity to deliver 440 scfm of air each and provide air to outlets plant. located'hrouqhout
- 2) The compresors will automatically trip when an abnormal condition exists and alarms perform their, design function.
- 3) The standby compressor will automatically start if the lead compressor fails or if its operation cannot meet service air system demand.
- 4) The Service Air System is capable of providing backup supply to the Instrument Air System A/0+1 BtlILDING DRAIN/: NON QADIOQCgIVP ACCEPTQNCg TEST Tegg objectives - The objectives of this test are as follows:
- 1) To demonstrate that system controls and alarms function in accordance with the desiqn intent.
- 2) To demonstrate the waste filter is capable of automatically dewaterinq sludge.
\
.3) To demonstrate the diesel generator floor drain sump pumps operate automatically.
Prereguisites Construction is complete to the 'necessary extent and the system is turned over to ISG. Required instrumentation is calihrated and controls are operable. Required electrical power supply systems are available. Instrument.air is available.
)
Test Method Low Hiqh and High-High sump levels are simulated to verify pumps start and stop as required. Acceptance Criteria The system performs in accordance with design documents.. A22. 1 MAKENP DEMINERALIZER SySTEM ACCEPTANCE TEST
~
Test Object.ive To demonstrate the capability of the System to provide quality water consistant with the Makeup'emineralizer requirements of the Final Safety Analysis Report. Prereguisit~s-- Construction is complete to the extent necessary to perform this test and the system is turned over to ISG. All instrumentation contained in this system is calibrated and, the
., controls are operational. The Mater Pretreatment System and the
'.,;- Neutralization Basins are available. gest gethorl A normal, automatic regeneration of makeup demineralizers shall be perfo'rmed verifying all regeneration Rev. 32 12/82 14 2-98
SS ES- PS AR sequence interlocks and verifying that the Nakeup Demineralizer conforms to FSAR requirements. All interlocks shall be verified that will remove the Makeup Demineralizer from service upon its effluent water quality not meet inq speci f ications. AccPgtance Criteria The makeup Demineralizer shall be capable of makinq water in accordance with FSAR requirements at, a flow rate between 20 and 120 qpm. Xt shall also be capable of nerforminq automatic shutdowns, startups and reqenerations per its desiqn requirements. 430~3 CONTROL STQUCTUPE QISCQLLQNEOUS HSV SYSTgl ACCEPTANCE TEST Test objectives To demonstrate that the Control Structure Miscellaneous HGV maintains temperature and delivers an adequate air supply and exhaust to various areas in accordance with design requirements. Prereg<<isites Construction is complete and the system is turned over to the ISG. Required instruments are calibrated and controls are operable. The Turbine Building Vent and Instrument Air Systems are in service. Required electrical power supply systems are a va ilab le. Test Method The system operation is initiated manually and fan performance, damper operations and heating or cooling operation fwhere applicable) are determined. Required controls are operated or simulated signals are applied to verify fan interlocks, high-high temperature from charcoal filters (where applicable),. electric duct heater operation and associated alarms. Acceptance Cgjtegia The system performance parameters are in accodance with the applicable desiqn documents. gegg objective The general oblective of this test is to demonstrate proper operation of the Computer Uninterruptible Power Supply. Specific objectives are to demonstrate the following:
- 1) The ability of the static transfer switch to provide automatic transfer of the 120 VAC distribution panel loads from the preferred to the alternate supply on loss of the preferred supply or overcurrent or in case of load side fa <<lt.
- 2) The ability of the manual transfer switch and manual operation of the static transfer switch to transfer Rev. 32, 12/82 14 2-99
SS ES-FS AR distribution panel loads between the preferred and the alternate source. p P Prereguisites - Construction turnover of the system is complete to the extent required to conduct this test. The system has been walked throuqh and verified complete. The reguired Technical Tests have been completed and the required instruments are calibrated. Test method The power supply is operated at full load, the static transfer switch is tested, the manual transfer is tested and all alarms and computer inputs associated with the system are verified. Acceptance Criteria The system performance parameters are in accordance with applicable enqineerinq design documents. A31 P PROCESS COQPfJTQQ ACCEPTANCE TEST Test Objective The objective of this test is to demonstrate proper operation of the computer. Specif ic ob jectives are to demonstrate the ability of the DCS to monitor unit operation and venerate video displays for operator use; the PNS to perform BOP calculations, loq data, make historical records, generate video displays and generate alarm status summary displays; the NSS subsystem proqram to provide an accurate determination of the core thermal performance and data loading, and to supplement procedural requirements for control and manipulation during reactor startup and shutdown. Preregnisites Construction turnover of the system is complete to the extent required to conduct this test. The system has been walked throuqh and verified complete. The required Technical Tests tern have been completed and the required instruments are ca libra ted. Test. Nethod Computer inputs are verified, the software programs are tested and computer self-protection and alarm functions are verified. Acceptance Criteria The system performance parameters are in accordance with applicable enqineerinq design documents. A32 1 SECURITY 125V DC SYSTEH NO 1 ACCEPTANCE TEST Test Objective To demonstrate the ability of the 125 Volt DC s Vs t. o p er fo rm the f olio wing:
- 1) The batteries can endure a complete discharge based on their ampere hour rating without exceedinq the battery bank
. minimum voltaqe limit.
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SS ES- F SAR
- 2) The batteries can provide reliable stored energy to selected loads in the event of a loss of normal power.
- 3) The battery charqers can deliver their rated output.
- 4) The battery charqers can fully charge their associated batteries from design minimum charged state simultaneously providing power to the distribution panels for normal security loads.
- 5) That the alarms are. simulated and verified to operate properly.
- 6) The reliable 125V DC power is delivered to the security'C distribution panel.
Prereguistes Construction is complete to the extent necessary to perform this test and the system is turned over to the ISG. Required calibration and operation of instruments, protective devices, and breakers is verified. 480V AC Power, Resistor Load Bank, Battery Room Ventilation and Emergency Eyewash is available and/or in service. Test Method The Battery Performance Test is manually initiated by connectinq the battery bank to the resistor load bank and discharqinq the batteries at a constant current for a specified period of time. The Battery Service Test is manually initiated bv connectinq the battery bank to the resistor load bank and simulating, as closely as possible, the~load the batteries will supplv during a desiqn basis accident. Then the battery charger is connected to the batteries and the distribution-panels to verify that they can charge the batteries while simultaneously p oviding power to the normal security loads. The battery charger is also connected to the resistor load bank and current is increased to its maximum rating with the charger isolated from its associated battery bank. Alarms are simulated and verified to be operated properly. Acceptance Criteria The batteries can satisfactorily deliver stored enerqy for the specified amount of time as required for the Performance and Service Test. The battery chargers can deliver rated output and can charge their associated battery bank from minimum voltage to a fully charged state in a specified amount of time while simultaneously supplying normal security loads. The alarms operate at their engineered setpoints and annunciate in the Security Control Center. A32 2 SECURITY UNINTERRUPTIBLE POMER SUPPLY NO 1 ACCEPTANCE TEST R ev. 32, 12/82 14 2-10 1
SS ES- FS AR Test objective The qeneral objective of this test is to demonstrate proper operation of the Security Uninterruptible Power Supply. Specific objectives are to demonstrate the f ollowinq: The ability of the static transfer switch to provide automatic transfer of the 120 V AC distribution panel loads from the preferred to the alternate supply on loss of the preferred supply or overcurrent or in case of load side fault. The ability of the manual transfer switch and manual operation of. the static transfer switch to 'transfer distribution panel loads between the preferred and the alternate source. Construction turnover of the system is complete t rereguisites to the extent required to conduct this test. The system has been walked throuqh and verified complete. The required Technical
<ests have been completed and the required instruments are calibrated.
T~st Method The power supply is operated at full load, the static transfer switch is tested, the manual transfer is tested and, all alarms associated with the system are verified. Acceptance Criteria The system performance parameters are in accordance with applicable enqineering design documents. A32 4 SECflRZTY BACKUP DIESEL AND ASSOCIATED 480 VOLT DISTRIBUTION ACCEQTQQCg T$ $ T
'Pest Objective To demonstrate system reliability, proper voltage and frequency regulation under transient and steady-state conditions. proper logic, correct setpoints for trip devices and proper operation of initiating devices and permissive and' prohibit interlocks. Startinq, cooling, heating, ventilating, lub'ricating and fuelinq auxiliary systems will also be tested to
'emonstrate that their performance is in accordance with design. To demonstrate the capability of the 480 Volt Load Centers and 480 Volt Motor Control Centers systems to provide electrical power to connected 480 Volt Load Centers and Motor Control Centers hy demonstrating the proper operation of breakers, transfer and trip devices, relaying and logic, permissive and prohibit interlocks, instrumentation and alarms. Preregnisit~s Construction is complete to the extent necessary to perform this test and the system is turned over to operable. the ISG. Required instruments are calibrated and controls are Rev. 32, 12/82 14. 2-102
SSES-PSAR 24 Volt DC Po wer is available. The diesel oil day tank is filled and a make-up source is available. Required electrical power supply systems are available to energize the 480 Volt system. Required instruments and protective relays are calibrated and controls are operable. Test Net.hod System operation is initiated manually and diesel qenerator capability to start and attain rated voltage within the specified time are verified. Diesel generator is loaded to the rated load and the performance is determined. Required controls are operated to verify automatic start, D-G protection. Feeder breakers are opened and closed by operatinq or simulating controls. Voltage on the bus being fed are measured to verify breaker operations, relayinq and logic, permissive and prohibit interlocks and alarms. Signals are applied to verify alarms and Buses are de-enerqized and energized to verify 'nstrumentation. automatic transfer, switch transfer, and re-transfer and motor-generator set operation. Arceptnace Cgitegia The system performance parameters are in accordance with applicable design documents. A32 9 SECURITY 125 V DC AND UNINTERRUPTIBLE POWER SUPPLY No. 2 ACCEPTANCE TEST Test Objective To demonstrate the ability of the 125 Volt DC system to perform the followinq:
- 1) The batteries can endure a complete discharge, based on their ampere hour rating, without exceeding the battery bank minimum vol taqe limit.
- 2) The batteries can provide reliable stored enerqy to selected loads in the event of a design basis accident.
The battery charqers can deliver their rated output.
- 4) The battery charqers can fully charge their associated batteries from design minimum charged state simultaneously providinq power to the distribution panels for normal security loads.
That the alarms operate and annunciate at their specified abnormal condi tion.
- 6) The reliable 125 V DC power is delivered to the security DC distribution panel.
Rev. 32, 12/82 14 2-1 03
'Eh w II C=
SS ES-PS AR
- 7) The ability of the static transfer switch to provide automatic transfer of the 120 V AC distribution panel loads from the preferred to the alternate supply on loss of the preferrred supply or overcurrent or in case of load side side fault.
- 8) The ability of the manual transfer switch and manual operation of the static transfer switch to transfer distribution panel loads between the preferred and the alt erna te source.
Prereguisites Construction is complete to the extent necessary to perform this test and the system is turned over to the ISG. Required calibration and operation of instruments, protective devices, and breakers is verified. 480 V AC Power, Resistor Load Bank, Battery Room Ventilation and Emergency Eyewash is available and/or in service. Test ")ethos The Battery Performance Test is manually initiated hy connectinq the battery bank to the resistor load bank and discharqinq the batteries at a constant current for a specified period of time. The Battery Service Test is manually initated by connecting the battery bank to the resistor load bank and simulating, as closely as possible, the load the batteries will supply during a design basis accident. Then the battery charger is connected to the batteries and the distribution panels to verify that they can charge the batteries while simultaneously providinq power to the normal security loads. The battery charqer is also connected to the resistor load bank and current is increased at its maximumrating with the charger isolated from its associated battery bank. Alarms are simulated and verified to be operated properly. The power supply is operated at full load, the static transfer switch is tested, the manual transfer is tested Acceptance Criteria The batteries can satisfactorily deliver stored enerqy for the specified amount of time as required for the Performance and Service Test. The battery charqers can deliver rated output and can charge their associated battery bank from minimum voltage to a fully charged state in a specified amount of time while simultaneously supplying normal plant loads. The alarms operate at their engineered setpoints and annunciate in the Security Control Center. The system performance parameters are in accordance with applicable engineering design documents. A33 1 TURBINE BUILDING HEATING 6 VENTILATING SYSTEM ACCEPTANCE TEST ives The ob electives of this test are as follows: 4 Test. Object
- 1) To provide filtered and tempered air to all areas of the Turbine Building.
R e v. 32, 12/82 14 2-104
SS ES-FS AR
- 2) To maintain air flow from areas of. lesser potential contamination to areas of greater potential contamination.
- 3) To exhaust air from potentia1ly contaminated spaces to particulate and charcoal filters.
- 4) To maintain .the Turbine Building at a sliqhtly negative pressure with respect to atmosphere to minimize exfiltration to outside atmosphere.
- 5) To recirculate and cool Turbine Building air to reduce exhaust volume.
- 6) To discharqe all exhaust air through the Turbine Building Exhaust Vent.
- 7) To supply cool air to the Reactor Recirculation Motor Genera tor sets.
>ra requisites
- 1) Flow balancinq is completed
- 2) Instrument'ir System is operational.
- 3) Fire Protection System is operational.
Test Method The system vill be tested vith manual controls and, automatically where applicable. All interlocks, start and trip schemes will also be verified. Maintain buildinq temperature above 40oF. Maintain building spaces belov the folloving maximum temperatures: a) General areas 104' b) Electrical rooms 104~ F c) Mechanical areas 1200 F 533 2 TORBTPE BUILDING CHILLED WATER SgSTEQ ACCEPTANCE TEST Test Ohjectives The objectives of this test are as follovs:
- 1) To demonstrate the ability of the Turbine Building Chilled Water System to maintain desiqn temperature.
Rev. 32, 12/82 14 2-105
SSES-PSAR
- 2) To demonstrate the ability of the Service Mater System to remove the chiller condenser heat.
Prereauisites
- 1) Construction is complete to the extent required to complete this test.
- 2) The followinq systems are operational:
a) Instrument Air System b) Turbine Building Hfy is functionally checked c) Service Mater System d) Makeup Demineralizers e) Expansion tank IT-123 is filled halfway and pressurized, to 20 psi Test Method The system will be initiated manually and automatically with a3.1 automatic functions verified. All interlocks will be verified and alarms checked as -they occur durinq normal process variation. Acceptance Criteria Turbine Building Chilled Mater System will supply water at 50oF. A 3'5 ' FfJFL POOL COOLING AND CLEA 4 NLJP SYSTFM ACCEPTANCE TEST vegt objective To demonstrate that the Fuel pool Coolinq and Cleanup System filters, demineralizes and cools the fuel pool water. The system is able to maintain a minimum differential pressure in the heat exchanqers and will prevent siphoning of water from the .fuel pool to any cooling water supply line. Prerequisite - Construction is complete to the extent necessary to perform this test and the system is turned over to ISG. Required instruments are calibrated and controls are operable. The Demineralized Water Transfer System, Service Water System, Sample System, Condensate System, Instrument Air System, Residual Heat Removal System, Liquid Radwaste Drain System, Emergency Service Water System, Solid Radwaste System and required electrical. power supply systems are available. Test Method - The system is operated to demonstrate the demineralizer heat exchanqers and fuel pool cooling pumps operation. Required controls are operated or simulated signals are applied to verify system operation, automatic valve alignment a nd system in ter 1oc ks and a la rms. .Rev. 32, 12/82 10 2-106
SSES-FSAR Arcegtance Cgigeria The system performance parameters are in accordance with the applicable design requirements. A 37 1 DEMI NFRALIZED MATER TRANSFER SYSTEM ACCEPTANCE TEST Test objectives To demonstrate proper operation of the Demineralized Mater Transfer system by verifying the following: The. abilitv to supply condensate for various plant systems, including the condenser hotwells. The ability to supply condensate to the suction of the hiqh pressure coolant injection (HPCI), reactor core isolation cooling (RCIC), core snrav, and control rod drive (CRD) pumps. The ability to supply demineralized water as makeup to the reactor,'adwaste, and closed coolant systems. The ability to supply demineralized water to the condensate storage tank 8 refueling water storage tank. frere<<tuisites Construction is complete to the extent necessary to peform this test and the system is turned over to ISG. Hydrostatic testing, velocity flushing and air blowing have been
..omplete to the extent required to perform this test. Required instruments are calibrated and controls are operable. Required electrical power supply systems, makeup demineralizers, and instrument air are available. The'ssociated plant systems which are capable of receivinq water from the Demineralized Mater System are available to the extent required to perform this test.
Yest Method The operatinq modes of this system are initiated manually and, where applicable, automatically. The system is operated to determine performance of all pumps. Control devices are operated or simulated siqnals are applied to verify system . automatic functions and alarms. Acceptanre Criteria The system performance parameters are in accordance with the applicable design documents. All automatic trips and alarms actuate within their allowable limits. A 38. 1 LOM PRESSURE AIR SYSTEM ACCEPTANCE TEST Test Objectives- The objective of this test is to demonstrate oroper operation of the Low Pressure Air System; specif ically to
'demonstrate the ability to provide air for the liquid radwaste filters, and the liquid radwaste demineralizers, as these processes require. The ability to provide backup air to the cement silo and to operate intermittently on demand is demonstrated. The protection of the compressor aqainst low oil pressure, high oil temperature, high air discharge temperature, hiqh coolinq water temperature and low cooling water pressure is <<)emonstrated.
Prereguisites Construction is complete to the extent necessary to perform the test and the system is turned over to the ISG. R ev. 32 ~ 12/'82 14 2- 107
SSES-FSAR Required instruments are calibrated and Technical Tests are complete.
'Pest Method The system is operated in the Manual and Automatic modes of operation. The Flow Rate is verified and all trips and alarms are tested.
Acceptance Criteria The system performance parameters are in accordance with the applicable design documents. A39 1 CONDENSATE DENXNERALI'KER SYSTEM ACCEPTANCE TEST Test objective To demonstrate the ability of t'e Condensate Demineralizer System to process full condensate flow producing effluent of acceptable quality thereby providing reasonable assurance that contaminants which may be introduced to the condenser durinq normal and abnormal plant operation will be removed. Also demonstrate that resin transfer, cleaning and regeneration are pushbutton initiated, fully automatic processes that clean and regenerate for reuse. Demonstrate valving and controls are such that a ready standby unit can be placed in service, or any operating unit can be taken out of service from the local control \ panels. Prereguisites Consruction is complete to the extent necessary to perform this test and the system is turned over to the ISG. Component technical procedures component calibrations have been completed satisfactorily. Test method - 'The system will be tested while processing water at 100% rated flow and at 120% rated flow, verifying that monitored influent and effluent parameters do not exceed desiqn values. Resin capacity will be tested (one bed minimum} by processing the design quantity of water and verifying that monitored effluent paramenters do not exceed, design values prior to achieving the design output. Control functions related to all modes of operation shall be demonstrated. Flow paths will be verified under actual operation as will all valve operations, motor-driven equipment performance, demonstration of all monitoring control and support equipment while pzocessinq dirty, exhausted resin charges exposed to condensate flow, through the regeneration modes, returninq the resin charge to inservice processing condensate to design quality effluent. Simulation of functions .will be used where off-normal conditions cannot he established or redundant testinq of the same function under actual conditions serves n'o purpose. E Acceptance criteria Each vessel passing rated flow will produce water quality at desiqn spec or better. Each vessels is capable of passinq 120% rated flow for a short period of time. The condensate demineralizer and reqeneration systems are pushbutton initiated, automatically controlled from a local control panel Re v 32, 12/82 10- 2-108
SSES-PSAR for all modes of operation. An automatically controlled isolation valve protects the resin trans'fer system from condensate system pressure. A proper concentration of acid solution is supplied to regenerate the cation resins and the proper concentrations of caustic solution at the proper temperature is supplied to regenerate the anion resins. A40. 1 LUBE OIL TRANSFERS STORAGE' PURIPICATION SYSTEM ACCEPTA NCE TEST gest Objective - To demonstrate the ability of the system to transfer lube oil from one lube oil reservoir to anot'her at rated flowrates and to demonstrate proper operation -of the controls and t,he alarms of the lube oil centrifuge. Prereguisites - Construction is complete to the extent necessary to perform this test and the system is turned over to ISG. Required instruments are calibrated and the controls are operable. Demineralized water transfer system and Instrument air system are operational. Required electrical supply systems are available and lube oil is available in sufficient quantity Test Methnd - The lube oil transfer pump performance parameters are measured and recorded. The batch oil tank pump performance parameters are measured and recorded. The centrifuqe and oil heaters cont.rol and alarm circuits are tested and the operating parameters are measured and recorded. All flowpaths are then verified. Arceptance Criteria The system performance is in accordance with the applicable design documents. A41 1 NAZN CQQLIQG gQMgP /AD gggXQTQQIQS QCCQPgANCE TgQT
%egg Qbjectiyes To demonstrate the proper operation of the cooling tower, coolinq tower makeup and level control,
- chlorination system, 'sulfuric acid addition system, and the
'b lowdown treatment system.
Prereguisites Construction is complete to the extent necessary 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, instrument air system, plant makeup water system, and. chlorination building HSV are a va i lab 1 e. Test method Sliding gate valves and bypass valve operation is verified Makeup system is verified to keep basin ~ater level at the proper level. Chlorination addition capabilities are verified, and the acid system is verified to control pH at the proper value. The blowdown treatment system will remove enough R ev. 32, 12/82 14 2-109
SSES-FSAR chlorine to allov the plant to meet the requirements of its environmental discharqe permit. Acceptance Critsegia The system performance parameters are in accordance vith the applicable desiqn documents. A42 1 CXRCOLATING WATQQ $ YQTEN ACCEPTANCE TEST Tegt Objectives To demonstrate proper 'operation of the Circulatinq Water System. I' Pr~regnisites construction is complete to.the extent hecessary to run this test and the system is turned over to the ISG. Required instruments are calibrated and controls are operable. Required electrical power supply systems and the cooling tover system are available. Test method - Pump protective interlocks and. system design pressures and flows are verified. Acceptance Criteria The system performance parameters are in accordance with the applicable design documents. I Tegt Qbjectives The objectives of this test are as follovs:
- 1) To demonstrate the ability of the mechanical vacuum pump to pull a vacuum on the condenser.
I
',qR), . To demonstrate the ability of the SJAEis to maintain
,condenser vacuum vhen pump is tripped.
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- 3) To demonstrate system ability to remove noncondensible gases from the main condenser and discharge them to the off-gas system.
- 4) To condense any steam removed from the condenser with the noncondensible qases and return the condensate to the con den se r.
Prereguisites The prerequisites for this test are as follovs:
- 1) Construction is complete to the extent necessary to perf orm
,p this test and system is turned over to ISG.
The main turbine is on turning gear. I s 2)
- 3) The aux. boiler is operational and the main turbine seals are established.
R ev. 32, 12/'82 14. 2-110
SS ES-FSAR
- 4) Instrument Air System is operational.
- 5) Turbine Bldg. HGV is operational.
fi) The Condensate System is operational.
- 7) The Off-Gas System is operational.
- 8) The separator-silencer 1T-107 is filled to the proper level.
- 9) All steam lines are properly drained of condensate.
Vest Method A vacuum will be pulled on the 'condenser using the mechanical vacuum pump and S JAE'. it will be maintained using the Valve interlocks will be checked as will all automatic functions. Alarms will be verified as they are induced during normal system change or simulation. Acceptance Criteria The mechanical vacuum pump can pull a vacuum of 5 in. Hga in 95 min. on the main condenser. The SJAE's can maintain the vacuum after .the mechanical vacuum pump is shutdown.
- 3) Valve sequencing operates per design.
A44 1 CONDFNSATE SYSTEM ACCEPTANCE TPST Test objective@ To demonstrate the following: {1) The ability of the condensate pumps and their associated valves to function properly. {2) The ability of the system to maintain minimum recirculation flow through each condensate pump. (3) The ability of the Turbine Building Closed Cooling Hater System to provide sufficient cooling Slow for the condensate pump bearings. {4) The ability of the Hotwell Load Control to maintain condenser at normal operating level. Prer~quisites Construction is complete to the extent necessary to perform this test and the system is turned over to the ISG. power and control voltage is available for the associated motors, valves and instruments. Required calibration and operation of instruments, protective devices and controls is verified. Motor bearing coolinq and pump seal water and instrument air is available. Main condensers are cleaned and filled with water Rev. 32, 12/82 14. 2-111
SS ES- FS AR Test Method The system operation is manually initiated by startinq the condensate pumps and establishing flow through various paths. System l'oqic, interlocks and alarms are verified to be in accordance vith design intent and system flows, pressures are vithin enqineerinq specifications under various simulated operatinq conditions. Acceptance Criteria The system performance parameters are in accordance with the applicable desiqn documents f or the conditions simulated during the test. t A46. 1 P~XTP ACTION ST/AM SYSTEM ACCEPTANCE TEST vest obgectives The general objective of this test is to demonstrate proper operation of the Extraction Steam System and Feedwater Heaters Drains and Vents System. Specific objectives are to demonstrate the follovinq: The isolation valves in the Extraction Steam Sytem, the Peedwater Heater Drain System, and the Peedwater Heater Vents operate as required by their'design.
- 2) All associated systems that drain to the feedvater heater systems isolate when required by the Peedvater Heater System design.
- 3) The alarms function to provide indication of an abnormality in the system.
Pregeguisites Construction is completed to the necessary exterit and the system is turned over to ISG. Required instrumentation is calibrated and controls are operable. Required electrical pover supply systems are available. plant demineralized vater a nd instrument air is a va ilable. Test Method Fxtraction Steam and Peedvater Heater System tests are simualted and performed vith no steam present to the turbine. All system interlocks are tested.
'Acceptance Criteria The system performance parameters are in accordance with the applicable design documents.
A65 1 RADWASTE BQILDING AIR PLOW SYSTEM ACCEPTANCE TEST Vest Oh)ective To demonstrate the ability of the Radvaste Buildinq Air Plow System to provide an adequate amount of filtered air to the Radwaste Building and to exhaust an adequate amount of air from the Radwaste Building. preregnisi.tes - Construction is complete to the extent necessary
'or the test and the system is turned over to the ISG. 480 V Rev. 32, 12/82 14 2-1 12
SSES-FSAR power and instrument air are available.. The required instruments are calibrated and controls are operable. Test Method The system is put into operation manually. Proper operation of all interlocks between system components is verified. The system air balance report and filter test reports are reviewed to ensure conformance with design specifications. Acceptance Criteria The system performs in accordance with ,desiqn documents. A65 2 RADMASTE BUILDING CHILLED RATER SXSTEM ACCEPTANCE TEST Test objectives To demonstrate the ability of the Radwaste Buildinq Chilled Mater System to provide an adequate amount of chilled water to the Radwaste Building Air Supply System cooling coils. Pgereguisites Construction is complete to the extent necessary for performing this test and the system is turned over to the ZSG. 480V power and instrument air are available. The Makeup Demineralized Mater System is available to provide makeup water as needed. The required instruments are calibrated and controls are operable. Test Method The system is placed in operation. Proper operation of all interlocks between system components is verified. All safety switches on both chillers are tested to ensure that they will shut down the associated unit when necessary. The system flow balance report is reviewed to verif y that flowrates are within design specifications. Arceptance Criteria The system performs in accordance with desiqn documents. A67.1 Loose Parts Monitorina System Test Ohjectiyps To demonstrate that the Loose Parts Monitoring System is capable of detection of a loose part resulting in an alarm and automatically startinq the tape recording equipment. Prereguisites Construction is complete to the extent necessary and the various systems are turned over to the ZSG. Required instruments are calibrated and control schemes have been checked and are operable. Test Method - Each Loose Part Detection (LPD) channel is tested by causinq an impact on the pipinq monitored and verification that a correspondinq visual alarm is activated. The Digital Loose Part Location (DLPL) is functionally tested by placing any two LPDs in alarm test condition and then verifying that the DLPL Re v. 32, 12/82 14. 2-113
SS ES- PS AR visible and audible alarms annunciator are activated and that the tape recorder starts recording the signal on the alarming charm el. Acceptance Cgiteria A predetermined impact on a specified coolant pipinq will result in a corresponding visual alarm. A series of impacts, based on the loqic indicating a loose part, will initiate an audible and. visual alarm and the tape recorder will start automatically. A68 1 RADQASTE SOLIDS HANDLING SYSTEM ACCLPTANCE TEST Test Objective To demonstrate the capability of the Radwaste Solids Handlinq System to control, collect, handle, process, packaqe, solidify and temporarily store the wet waste sludges, spent resins and evaporator concentrates. Pre.requisites Construction is complete to the extent necessary 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 System operation is initiated manually. Reguired controls are operated and process is 'varied to verify interlocks and alarms. Acceptance Criteria The system perf ormance parameters are in
~ accordance with the applicable design documents;
%68~/ SPENT R~FSIN HANDLING $ XSTQM ACCEPTANCE TEST Tost Object.iye To demonstrate the capability of the spent resin collection system to control, collect,, handle and discharge spent resin to the liquid radwaste filters.
The Prerequisites, Test Method, and Acceptance criteria are the same as those for A68.1. A69.2 LIQUID RADWASTE SUBSYSTEMS ACCEPTANCE TEST Test objective To demonstrate the capability of the subsystems to collect, process, store and monitor for reuse or disposal all potentially radioactive liguid waste.
)'-
~ Prereguisites Construction is complete to the extent necessary
.;,to perform this test and the subsystems are turned over to the & ISG. Required instruments are calibrated and controls are operable. Required Electrical Power Supply Systems are available. Liquid radwaste subsystem storage tanks and sample tanks are available to be filled with water.
Re v. 32, 12/82 14. 2-114
SS ES-PS AR Tegt method Subsystem pumps are operated an d performance rharacteristics are determined. Level contro ls are operated to verify alarms, pump starts and pump shutoffs. performance of the liquid radwaste filtration, demineralization, chemical vaste neutralization, chemical radwaste evaporation system, laundry radwaste filtration and effluent isolation is determined to the extent possible durinq this test. Acceptance Criteria The system performance parameters are in accordance with the applicable desiqn documents. V,o..st ohjectiye To demonstrate the proper operation of the GRRccM system specifically, that the coolinq pumps supply the
~
rated flow to the system, the coolinq water is temperature controlled and the chemica1 addition tank has flov capabilities
~
for addinq chemicals to the system. Prereguisites - Construction is completed to the extent necessary to perform this test and the system is turned over to the LSG. Required electrical pover supply systems are available. Required instruments are calibrated and controls are available. The instrument air'ystem is available. The service water system is operational and lined up to the GRRCCM heat exchangers. Vest,'tet hod - The system operation is initiated manually, and vhere applicable automatically. The system is operated in the y~ system design modes and GRRCCW pumps performance is determined. Required controls are operated or simulated to verify automatic system f unctions and alarms. grceptapce Criteria The Unit One (1) and Common cooling water
~
flow through the heat exchanqers is temperature controlled through a ranqe of 900 to 120~P. The Unit One (1) and common 4 coolinq water pumps deliver 1124 gpm to the respective system. Chemicals can be added to the system when flow is established t hrough the Unit One f1) and common chemical addition tanks. A72 1 QgP GAS RECONBIQER SYSTEM ACCEPTANCE TEST
~,Vest. ohjectiye To demonstrate the operation of the Off-Gas Recombiner System, specif ically, that the system vill operate in the standby, pre-start and process modes and that the standby recombiner can be brouqht on line within 10 minutes.
Prerequisites Construction is completed to the extent necessary to perform this test and the system is turned over to the ISG. Required electrical power supply systems are available. Required R, instruments are calibrated and controls are available. The instrument air system is operational. The following systems are h Rev. 32, 12/82 14 2-115
SSES-PSAR operational as needed: Condensate system, GRRCCW System, RBCCW, Auxiliary Boiler, and Hain Condenser.
~.est Method The system operation is initiated manually, and, where applicable, automatically. The system is operated in the system desiqn modes, required controls are operated or simulated to verify automatic system functions and alarms.
Acceptance criteria - The Unit I and common Off-Gas Recombiner Systems perform the followinq:
- 1) The Off Gas Recombiner System will operate in the Standby, Prestart and Process modes.
- 2) A standby recombiner can maintain recombiner temperature close to 3000P and can be brought on line in 10 minutes.
- 3) 'The Off Gas Recombiners can be transfered and shut down Zocally and from the main control room.
- 4) The Charcoal Absorber subtrains are capable of beinq transfered and isolated locally and from the main control room.
I A74. 1 NITROGEN STORAGE AND SUPPLY SYSTEM ACCEPTANCE TEST Test Objective To demonstrate the capability of the Nitrogen Storaqe and Supply to provide and control the supply of nitrogen gas for primary containment purging and to maintain an inert atmosphere in containment. Prereguisites - Construction is complete to the extent necessary
'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 System operation is initiated manually. The system is operated in the different desiqn modes, system performance is determined and a purge flow will be established to demonstrate proper operation. Required controls are operated or simulated
'-';.: ;",...signals are applied to verify automatic features, system
~
'..";-."~,,'.," interlocks and alarms.
85l Acceptance Criteria The system performance parameters are in accordance with applicable design documents.
'A76 2 PROCESS SCAPI ING SQQTEQ ACCEPTANCE /EST Test Objective To demonstrate proper operation of the Process Sampling System. This is performed by proving:
Rev. 32, 12/82 14. 2-116
SS ES- FS AR
- 1) The operability of the reactor and,.turbine building thermal baths.
- 2) The ability of the chemical fume hood to control out-leakage when drawinq grab samples.
- 3) The ability of the system to provide required monitorinq of sample fluids.
- 4) Capability of obtaininq grab samples.
Prereguisites Construction is complete to the extent necessary to peform this test and the system is turned over to ISG. Required instrumentation is calibrated and controls are operable. Required electrical power supply systems are available. Plant demineralized water is available. Turbine Bldg. and Reactor 91dq. closed coolinq water is available. Te~t Net:hod Tests whenever feasible will be performed when the process being sampled is in operation. Other tests such as main steam samples, will be simulated. All sampling devices will be calibrated and alarm conditions set. Acceptance Criteria-- The system performance parameters are in accordance with the applicable design documents. A84 1 NOISTURE SQPARATOQS ACCEPTANCE TEST Test Objective To demonstrate the ability of the moisture separator drain tank level controls to maintain level and provide a main turbine trip signal as a result of high level. PREREgOIsITES Construction is complete to the extent necessary to perform this test and the system is turned over to ISG. Hydrostatic testinq, velocity flushinq and air blowing have been completed. Required instruments are calibrated and controls are operable. Required electrical power supplies, water supplies and instrument air are available. The associated plant systems which are capable of receivinq water are available to the extent necessary to peform this test. TFST NFTHOD - The water level in the drain tank will actually be varied and the proper operation of the level controls, level alarms and level trips will be verified. ACCFPTANCF. CpITEQIA The system performance parameters are in accordance with the applicable desiqn documents. All automatic +rips and alarms actuate within their allowable limits. A85. 2 FREF7g PROTECTION SYSTPQ ACCFQTANCE TEST R ev. 32, 12/82 14 2-1 17
SSES-PS AR Test objective To demonstrate the ability of the system to supply and interrupt power to the individual heater circuits at t he correct voltaqe and current in both the AUTO and MANUAL modes of operation and to demonstrate the sytem's ability to detect a loss of source supply voltage on a faulty heater circuit. Prereguisites '- Construction is complete to the extent necessary to perform this test and the system is turned over to ISG. The required instruments are calibrated and the controls are operable. Test Methocl Each control panel is energized and proper source supply voltaqe verified. The required controls will be operated and siqnals simulated as necessary to verify the individual heater circuits function per design in the AUTO, OPF, and Manual modes, and are providinq the design specified heat requirements for the a pplica tions. ACCEPTANCE CgIT~PHIA The system performance parameters are in accordance with the applicable design documents, technical spec's. and vendor prints. A 91. 1 A NNU NCIAQOR SQSTgg ACCQPTQQCP, TEST Test Objective The objective of this test is to demonstrate the ability of the main control room annunciators to provide audible and visual indication of an alarm condition. prereguisites Construction turnover of the system is complete to the extent required to conduct this test. The system has been walked throuqh, verified complete and the component technical tests have been completed. Test Method Simulated alarms are applied and the audible and visual indication verified. Annunciator loss of power and ground detection feature are also tested, where applicable Acceptance Criteria The system performance parameters are in accordance with applicable enqineerinq design documents. A92.1 TURBINE STEAM SEALS 6 DRAINS ACCEPTANCE TEST Test Objective The objective of this test is to demonstrate the proper operation of the turbine steam seal system and drains usinq the auxiliary boiler steam supply to the turbine steam seal header. Also, the test will demonstrate the ability of the steam packing exha uster to maintain a proper vacuum on the steam seal exhaust header. Prereguisites Construction is complete to the extent necessary to perform this test and the system is turned over to the ISG. Required instruments are calibrated and controls are operable. R ev 32, 12/82 14. 2-118
SSES-FSAR Required electrical supply systems are available. The instrument air system is operational. The auxiliary boilers are available and in the standby mode. The condensate system is operational. The main turbine and feedsater turbines are available to be placed on turning qear. The main condensers are lined up to receive drains and to provide support to seal the main and reactor feed pump turbines. Vest Nethod The auxiliary boilers sill provide a continuous and regulated supply of steam to the steam seal evaporator header. The performance of the steam packing exhauster to maintain a proper vacuum on the exhaust header is verified. Simulated and automatic signals are applied to verify systeh interlocks and alarms for the seal steam evaporator drain tank, seal steam system and steam packing exhauster. Acceptance Criteria The steam packing exhauster vill maintain a n approximate vacuum of 5. 0 inches H20 on the seal steam evaporator exhaust header during normal operating conditions. The auxiliary steam system can provide a continuous amount of clean steam to the seal steam evaporator header at approximately 4 psiq to supply the follosinq sith sealing steam: the main turbine shaft seals, the stem packings of the main steam stop valves, control valves, and bypass valves, the combined intermediate valves, the shaft seals of the reactor feed pump turbines, and the stem packinqs of the reactor feed pump turbine stop and control valves. A 93~1 Tl1QBINE LUBF, OIQ SYSTEN ACCEPTANCE TgST Vest objectives To demonstrate the proper operation of the Turbine Lube Oil System. Prerequisites Construction is complete to the extent necessary to perform this test and the system is turned over to the ISG. Eeguired instruments are calibrated and controls operable. Required electrical poser supply systems are available. The Service Mater System and the Hain Turbine-Generator Assembly is available. Test Method System operation is initiated manually and automatically testing all trips and interlocks. The main reservoir vapor extractor is tested manually and automatically to verify proper vacuum in the main reservoir and isolation on detection of fire. All main lube oil pumps are tested for proper manual and automatic start to verify proper bearing oil Supply pressures durinq all conditions including loss of AC poser. Bearing verify lift proper pumps are tested manually and automatically to bearing lift for turning gear operation. The main turbine turning gear is tested for both manual and auto engaging and starting to ensure proper rotation during shaft cooldosn. Hev. 32, 12/82 14. 2-119
SSES-PS AR Acceptance Cgjtepia The system performance parameters are in accordance with the applicable design documents. A93 2 TURBINE VALVES VALVE TEST EHC AND SUPERVISORY SYSTEMS ACCEQQQQCE Tg$ T Test Ohgectiyes To demonstrate the proper operation of the turbine EHC and supervisory system. Prerequisite~ Construction is complete to the extent necessary to perform this test and the system is turned over to the ISG. Required instruments are calibrated and controls operable. Required electrical power supply systems are available. The Main Condenser, Stator Cooling and Instrument Air Systems are available. gest Method Hydraulic System Manual and Automatic Modes are tested. All turbine trip paths are verified. All system stop, control and bypass valves are tested for EHC operation. Turbine warm-up, speed selects and load ramp functions are verified. Turbine steam lead drain valves are tested for proper operation. Acceptance Criteria The system performance parameters are in accordance with the applicable desiqn'ocuments. A98 1 NllIM ( FNFRATOR AND
~ ~ ~RXCITAYION SYSTEM
~
ACCEPTANCE TEST Test Objectives To demonstrate the ability of .the protective relays and their associated interlocks to shutdown the generator. Prereguisites Construction is complete to the extent necessary to perform this test and the system is turned over to the ISG. Component calibrations and alarm verifications are complete to
- t,he extent nece sary to perform this test.
Test Method - Throuqh the use of jumpers, lifted leads, pulled fuses, and manual manipulation of relay contacts conditions are simulated to initiate automatic responses of the generator protection circuitry. Proper operation of the generator protection circuitry is verified. Arreptance Criteria - The followinq is verified: (1) The ability of the voltage regulator to transfer from auto to manual upon initiation of design events. (2) The ability of the exciter -field breaker to f unction according to design basis events. (3) The ability of the primary and backup lockout relays to trip the qenerator upon initiation of design basis events. Rev. 32, 12/82 14. 2-120
SS ES-FSAR A99 2 Communications System Acceptance, Test Test Objective To demonstrate the ability of the three part communications system (PA, Plant Maint./Test Jack, and Plant Evacuation and Alarm Systems} components to function as an integrated system. The PA system to provide communications and a medium for transmitting plant alarms in conjunction vith the Plant Evacuation Alarm System. The P'lant Evacuation Systems ability to qenerate the necessary tones and freguencies and the Plant Maint./Test Jack Systems ability to provide an additional independent means of communication. Prereguisites - Construction is complete to the extent necessary
+ o perform this test and, the system is turned over to ISG. The required instruments are calibrated and the controls are operable.
Test method By operatinq the required controls each Public Address station vill be tested in the transmit and receive modes vill on all channels. The associated speakers be tested for functional audibility. The systems loop separation and muting features vill be operationally verified. The Plant Maint./Test Jack System vill be tested by operating the C. required controls and verifying each Jack Stations transmit/receive capability on all of the systems 23 channels. An integrated test with several remote Jack Stations attached will also be performed. The Plant Fvacuation and Alarm System vill be used in conjunction with the PA system to broadcast all 5 of the possible tones and frequencies generated by the system. Also the systems isolation . and silencinq features vill be operationally verified. Acceptance Cgiterja The systems performance is in accordance with the applicable design documents. Test Objective To verify the operability of the seismic monitorinq instrumentation {digital cassette accelerographs, playback unit, response spectrum analyzer and triaxial accelerometers} and to demonstrate proper integrated response of the system to activate upon occurance of a seismic event as desiqned. prereguisites Construction is complete to the extent necessary to perform this test and the system is turned over to the ISG. Reguired instruments are calibrated and controls are operable. The required electrical power supply system is available. All Rev. 32, 12/82 14 2-121
recorders have ample paper and all accelerographs are loaded with the proper magnetic tape cassettes. Test Method Both an internal calibration feature on the SHB-102 (seismic monitorinq recorder) and a simulat ed seismic event at each triaxial accelerometer are used as>>tr igger input> to the seismic monitorinq system to verify automat ic initiation and alarm actuations. Playback (production of time-history seismic graphsj is demonstrated by manual transfer of cassette tapes from the digital cassette accelerographs to the seismic monitoring recorder. Acceptance Criteria The system performance par'ameters are in accordance with the applicable desiqn documents. "l
~ t R
Bev. 32, 12/82 10. 2-122
SS ES-PS AR Test ~Ob. ective To demonstrate the ability of the three part communications system (PA, Plant Maint./Test Jack, and Plant Evacuation and Alarm Systems) components to function as an inteqrated system. The PA system to provide communications and a medium for transmitting plant alarms in conjunction with the Plant Evacuation Alarm System. The Plant Evacuation Systems ability to generate the necessary tones and freguencies and the Plant Haint./Test Jack Systems ability to provide an additional independent means of communication. Prereguisites - Construction is complete to the extent necessary to perform this test and the system is turned over to ISG. The required instruments are calibrated and the controls are o perable. Test Method-- By operating the required controls each Public Address station will be tested in the transmit and receive modes on all channels. The associated speakers will'be tested for functional audibility. The systems loop separation and muting features will be operationally verified. The Plant Maint./Test Jack System will be tested by operating the required controls and verifying each Jack Stations transmit/receive capability on all of the systems 23 channels. An inteqrated test with will also be performed. several remote Jack Stations attached The Plant Evacuation and Alarm System will be used in conjunction with the PA system to broadcast all 5'f the possible tones and frequencies qenerated by the system. The siren will be operationally tested. Also the systems isolation and silencing features will be operationally verified. ~Acce tance Criteria The systems performance is in accordance with the applicable design documents. +9~96 -SeifmoSSaS~hc~a-NondtoriSS System Ac~em tance Test Test ~Ob ective-- To verify the operability of the seismic monitoring i,nstrumentation (digital cassette accelerographs, playback unit, response spectrum analyzer and triaxial accelerometers) and to demonstrate proper integrated response of the system to activate upon occurance of a seismic event as desiqned. ~P ereguisites Construction is complete to the extent necessary to perform this test and the system is turned- over to the XSG., Required instruments are calibrated and controls are operable.. The required electrical power supply system is available. All Rev. 30, 5/82 14 2-119
recorders have ampl.e paper and all accelerographs are loaded vith the proper maqnetic tape cassettes. Test Nethon Both .an internal. calihration feature on the SBB-102 (seisnic monitoring recorner) ann a siaulate8 seisaic event at each triaxial accelerometer are used as "trigger input" to the seismic monitorinq system to verify automatic initiation and alarm actuations. Playback (production of time-history seismic qraphs) is demonstrated by manual transfer of, cassette tapes from the digital cassette accelerographs to the seismic monitoring recorder. Acce~tance~Ciferia The system performance parameters are in accordance vith the applicable design. documents Rev. 30, 5/82 10 2-120
SS ZS-PS AR Pre~re uisites construction is complete to the extent necessary to perform this test and the system is .turned over to ZSG The required instruments are calibrated and the controls aze operable. Test Method By operating the reguized controls each Public Address station will be tested in the transmit and receive modes on all channels The associated speakers will be tested for 20 functional audibility. The systems loop separation and muting features will be operationally verified. The Plant Maint./Test Jack System will be tested by operating the required controls and verif ying each Jack Stations transmit/receive capability on all of the systems 23 channels. An integrated test with several remote Jack Stations attached will also be performed. The Plant Evacuation and ALRH system will be used in conjunction with the PA system to broadcast all 5 of the possible tones and frequencies generated, by the system. The siren will be operationally tested. Also the systems isolation and silencing features will be operationally verified. Acceptance Criteria The systems performance is in accordance with the applicable design documents n99.6 seism~ora~hical sonitorincisrstem ncc~etance 1est ~est Objective To verify the operabil'ity of the seismic monitoring instrumentation (digital cassette accelerographs, playback unit, response spectrum analyzer and triaxial accelerometers) and to demonstrate proper integrated response of 20 the system to activate upon occurance of a seismic event as desiqned. Pre~re uisites Construction is complete to the extent necessary to perform this test and the system is turned over to the ISG Required instruments are calibrated and controls are operable. The required electrical power supply system is available All recorders have ample. paper and all accelerographs are loaded with the proper magnetic tape cassettes. Test Method Both an internal calibration feature on the SABIR-102 (seismic monitoring recorder) and a simulated seismic event at each triaxial accelerometer are used as >>trigger input" to the seismic monitoring system to verify automatic initiation and alarm actuations. Playback (production of time-history seismic qraphs) is demonstrated by manual transfer of cassette tapes from the diqital cassette accelerographs. to the seismic monitoring recorder. REV..20, 2/81 10 2-121
SSPS-PSAR Acceptance-Criteria-- The system performance parameters are in accordance with the applicable design. documents. REV. 20, 2/81 14 2-122
SS ES-FS AR T~AB y- 1~42-0 Page 1 gest-Humheg. ~est-~fini~t on. P2.1 125 volt dc System P4 1 4.16 KV System P5 1 480 volt System P13.1 Pire Protection Water System P13. 2 Pire Protection S Generator Parge Systems P13.3 Smoke Detection System P13 4 Control Room Halon System P14. 1 Reactor Building Closed Cooling Water System P16 1 RHR Service Water System P17.1 Tnstrument ac Power System P23.1 Diesel Fuel Oil System P24 1 Diesel Generator System P25 1 Primary Containment Xnstrument Gas, System P28.1 ESSQ Pumphouse HGV System P28. 3 Diesel Generator Building HSV System P30.1 Control Structare HSV System P30 2 Control Structure Chilled Mater System P34.1 Reactor Building HSU System P34 2 Reactor Building Chilled Mater System P45.1 Peedwater System P45.2 Peedwater Control System P 49.1 Residual Heat Removal System P50.1 Reactor Core Esolation Cooling System Rev. 30, 5/82
SSES-FS AB TA~BL "1~4$ -~CONTINUED ~ Page 2 P51. 1 Core Spray System P51.1A Core Spray System Pattern P52.1 Hiqh Pressure Coolant Injection System ,P53.1 Standby Liquid Control System P54.1 Emergency Service Water System P55.1 Control Rod Drive System P56 ~ IA Reactor Manual Control System P56.1B Rod Sequence Control System P56.1C Rod Worth Minimizer System P57.1 Uninterruptable ac Power System P58.1 Reactor Protection System P59.1 Primary Containment System P59 2 Containment Integrated Leak Bate Test P60.1 Containment Atmosphere Circulation System P61 1 Reactor Hater Cleanup System P64 1 Reactor Recirculation System P69. 1 Liquid Radvaste Collection System P70 1 Standby Gas Treatment System and Secondary Containment Isolation P73 1 Containment Atmospheric Control System P73 2 COntainment Hydrogen Recombiner System P73 3 Containment Oxygen and Hydrogen Analyzer System P75.1 24 volt dc System P76. 1 plant Leak Detection System P78 1 Source Range Monitorinq System Rev 30, 5/82
SSES-FSAR TABLE 14.2-1 CONTINUED Page 3 P78. 2 Intermediate Range Monitoring System P78.3 Average Power Range Neutron Monitoring System P78.4 Traversing Incore Probe System P79.1 a Area Radiation Monitoring System P79.2I P79.2A-H Process Radiation Monitoring System P80.1 Reactor Nonnuclear Instrumentation System P81.1 Fuel Handling System P83.1A Main Steam-Nuclear Steam Supply Shutoff System Preoperational Test P83.1B Main Steam Relief Valves/Automatic Depressurization System Preoperational Test P83.1C Main Steam Leakage Control System Preoperational Test P83. 1D Main Steam Leak Detection System Preoperational Test P88. 1 250 volt dc System P99. 1 Reactor Building Crane P100.1 Cold Functional Test Rev. 30. 5/82
SSES-F SAR TABLE 14. 2-2 ACCEPTANCE TEST PROCEDURES Page 1 Test Number Test Definition A-3. 1 1 3. 8 kV System A-7 1 Lighting System and Miscellaneous 120V Distribution A-8 1 Domestic Mater Sytem A-9 1 River Mater Makenp System A-9 2 Intake Structure Compressed Air System A-10 1 Screens 8 Srreen Hash System A-11. 1 Station Service Mater System A-15. 1 Turbine Building Closed Cooling Mater System A-18. 1 Instrument Air System A-19 1 Service Air System A-20 1 Building Drains Nonradioactive A-21 1 Mater Pretreatment System A-22 1 Makeup Demineralizer System A-27 1 Auxiliary Boiler System A-28 2 River Intake Structure HSV System A-28-4 Chlorination Building HF'V System A-28.5 Circulating Mater Pump House HbV System A-30.3 Control Structure Misrellaneons HGV System A-31. 1 Computer A-31.2 Process Computer A-32 ~ 1 Security System 125 VDC A-32. 2 Security UPS Rev. 26, 9/81
SS S-FSAR TABLE 14- 2-1 CONTINUED Page 2 e- P52.1 High Pressure Coolant Injection System P53.1 Standby Liquid Control System PS4.1 Emerqency Service Wate System P55.1 Control Rod Drive System P56.1 Reactor Manual Control System P57.1 Uninterruptable ac Power System P58.1 Reactor. Protection System P59.1 Primary Containment System P59.2 Containment Integrated Leak Rate Zest P60. 1 Containment Atmosphere Circulation System P61.1 Reactor Water Cleanup System P64.1 Reactor Recirculation System P69.1 Liquid Radwaste Collection System P70.1 Standby Gas Treatment System and Secondary Containment Isolation P73.1 Containment Atmospheric Control System P75.1 24 volt dc System P76-1 Plant Leak Detection System P78.1 Source Range Monitoring System P78. 2 Intermediate Range Monitoring System I P78 3 Average Power Range Neutron Monitoring System P78 4 Traversinq Incore Probe System P79.1 Area Radiation Monitorinq System P79.2 Process Radiation Monitoring System P80.1 Reactor Nonnuclear Instrumentation System P81.1 Fuel Handling System REV. 20, 2/Sl
SSL'S-FSAR TABLE 14. 2-1 CONTINUED Page 3 llain Steam System P88 1 250 volt dc System P99.1 Reactor Building Crane P100.1 Cold Functional Test REV. 20, 2/81
0 0'
SSES-PSAR TABLE 14.2-2 ACCEPTANCE TEST PROCEDURES Page 1 Test Number Test Definition A-3.1 13.8 kV System A-7.1 Lighting System and Miscellaneous 120V Distribution A-8.1 Domestic Water Sytem A-9.1 River Water Makeup System A-9.2 Intake Structure Compressed Air System A-10.1 Screens 6 Screen Wash System A-ll.l Station Service Water System A-15.1 Turbine Building Closed Cooling Water System A-18.1 Instrument Air System A-19.1 Service Air System A-20.1 Building Drains - Nonradioactive A-21.1 Water Pretreatment System A-22.1 Makeup Demineralizer System A-27.1 Auxiliary Boiler System A-28.2 River Intake Structure HSV System A-28.4 Chlorination Building HRV System A-28.5 Circulating Water Pump House HGV System A-29.1 Administration Building HSV System A-30.3 Control Structure Miscellaneous H&V System A-31.1 Computer A"31.2 Process Computer A-32.1 Security System 125 VDC A-32.2 Security UPS Rev. 23, 6/81
,V fl l I 'I
SSES-FSAR TABLE 14.2-2 CONTINUED Page 2 A-32.3 Security 480 Volt A-32.4 Security Backup Diesel A-32.5 Security 480/120 Volt A-32.6 Security Bldgs. HRV A-32.7 Security Bldgs. Halon A-33.1 Turbine Building HSV System A-33.2 Turbine Building Chilled Water System A-35.1 Fuel Pool Cooling and Cleanup System A-37.1 Demineralized Water Transfer System A-38.1 Low Pressure Air System A-39.1 Condensate Demineralizer System A-40.1 Lube Oil Transfer, Storage 6 Purification System A-41.1 Cooling Tower System A-42.1 Circulating Water System A-43.1 Main Condenser Air Removal System A-43.2 Condenser Tube Cleaning System A-44.1 Condensate System A-46.1 Extraction Steam System A-65.1 Radwaste Building Air Flow System A-65.2 Radwaste Building Chilled Water System A-68.1 Radwaste Solids Handling System A-69.2 Liquid Radwaste Subsystems Gaseous Radwaste Recombiner Closed Cooling Water A-72.1 Off-Gas Recombiner System A-74.1 Nitrogen Storage S Supply System A-74.2 Bulk Hydrogen System Rev. 23, 6/81
SSES-FSAR TABLE 14.2-2 CONTINUED Page 3 A-76.2 Process Sampling System A-84.1 Moisture Separators A-85.1 Cathodic Protection System A-85.2 Freeze Protection System A-91.1 Annunciator System A-92.1 Turbine Steam Seals 5 Drains A-93.1 Turbine Lube Oil Systems A-93. 2 Turbine Valves, Valve Test, EHC and Supervisory Systems A-95. 1 H2 Seal Oil System A-97.1 Stator Cooling System A-98.1 Main Generator 5 Excitation System A-99.2 Communications System A-99.4 Radiation Area Doors A-99.6 Seismographical Monitoring System Rev. 23, 6/81
SSES-FSAR TABLE 14.2-3 STARTUP TEST PROCEDURES Test Number Test Definition Chemical and Radiochemical Radiation Measurements Fuel Loading Full Core Shutdown Margin Control Rod Drive System SRM Performance and Control Rod Sequence Reactor Water Cleanup System ST-8 Residual Heat Removal System Water Level Measurement ST-10 IRM Performance ST-11 LPRH Calibration ST-12 APRM Calibration ST-13 NSSS Process Computer ST-14 RCIC System ST-15 HPCI System ST-16 Selected Process Temperatures ST-17 System Expansion ST-18 TIP Uncertainty ST-19 Core Performance ST-20 Steam Production Verification ST-21 Core Power - Void Mode Response ST-22 Pressure Regulator ST-23 Feedwater System ST-24 Turbine Valve Surveillance ST-25 Hain Steam Isolation Valves Rev. 23, 6/81
SSES-FSAR TABLE 14 2-3 [Conti Page 2 STARTUP TEST PROCEDURES S T-26 Re1i e f Valves ST-27 Turbine Trip and Generator Load Rejection .ST-28 'hutdown From Outside the Hain Control Room ST-29 Recirculation, Flow Control System ST-30 Recirculation System ST-31 Loss of Turbine Generator and Offsite Power ST-32 Containment Atmosphere and Hain Steam Tunnel Coolinq ST-33 Piping Steady State Vibration ST-34 Control Rod Sequence Exchange ST-35 Recirculation System Flow Calibration ST-36 Cooling Water Systems ST-37 Gaseous Radwaste System ST-38 BOP Pipinq System Expansion ST-39 Piping Vibration During Dynamic Transients ST-40 BOP Pipinq Steady State Vibration Rev. 31, 7/82
SSES-PSAR TABLE 14,2-4 MAJOR TEST PHASE AND TEST PLATEAU SCHEDULE TEST CONDITION SEQUENCE Test Test Phase Plateau Test Condition Sequence Open Vessel Test Condition IV Heatup Test Condit ion Test Condit ion 1 Testinq during approach to Test Condition 2 Test Condition 2 Testing during approach to Test Condition 3 Test Condition 3 V D,+ Testinq Purinq approach to Test Condition 5 Test Condition 5 Testing during approach to Test Condition 6 Test Condition 6 Test Condition 100% Power Marranty Bun Because of the transitory nature of testing per formed along the 100% rod line durinq Test Phase V Test Plateau D, all testinq assigned to Test Condition 6 may not be completed prior to enterinq Test Condition 4. Rev. 31, 7/82
SSES-FSAR TABLE 14.2-5 CONTROL ROD DRIVE SYSTEM STARTUP TESTS Reactor Pressure With Core Loaded Accumula to r psig Action Pressure 0 600 800 Rated Position Indication all Normal Times all 4
~
Insert/Withdraw Coupling all Friction all all Scram Times Normal all 4" 4
~
all Scram Times Minimum 4)I
.Scram Times Zero 4J Scram Times Normal 4JA n Refers to 4 CRDs selected for continuous monitoring based on slow normal accumulator pressure scram times, or unusual operating characteristics, at zero reactor pressure or rated reactor pressure when this data is available. The 4 selected CRDs must be compatible with the rod worth minimizer, RSCS system, and CRD sequence requirements.
Scram times of the four slowest CRDs (based on scram data at rated pressure) will be determined at Test Conditions 2 6 6 during planned reactor scrams. Rev. 23, 6/Sl
100 TC 6
~o>
4 80 TCS 60 ~C) l4 TC 3 a TC~ 40 4 go> TC )Q,(~
.2 20 FLOW INTERLOCK LINE TC 1
JET PUMP RECIRC PUMP NPSH NPSH 20 40 60 80 100 X RATED CORE FLOW NOTES
- 1. SEE FIGURE 14.2-6 SHEET 2 FOR DEFINITION TEST CONDITIONS
- 2. CONSTANT PUMP SPEED LINES
- a. NATURAL CIRCULATION
- b. MINIMUM RECIRCULATION PUMP SPEED Rev. 20, 2/81
- c. ANALYTICALLOWER LIMIT OF MASTER SUSQUEHANNA STEAM ELECTRIC STATION FLOW CONTROL UNITS 1 AND 2
- d. ANALYTICAL UPPER LIMIT OF 'MASTER FINAL SAFETY ANALYSIS REPORT FLOW CONTROL POWER FLOW MAP AND STARTUP TEST CONDITIONS FIGURE 14.2-6 SH. 1
SSES-PS A'R Test Condition Number . Power-Plow May Region and Notes Core thermal power between approximately 5% and 20'$ rated Recirculation pump speed vithin +10% of minimum pump speed. Before and after main generator sychronization. Core ther rod" line ma l power between the 45% power
<>> and 75$ pover rod line.
Recirculation pump speed betveen minimum and lowest pump speed corresponding to Master Manual Mode. Lowerpower corner is vithin Bypass valve capacity. Core thermal pover between 45% pover rod line and 75% power rod line. Total core flow between 80% and 100% ated. On the natural circulation core flow, line within +0, -5% of the intersection the 100% power rod line. 'ith Core thermal power vithin +0, -5% of the 100% pover rod,line. Recirculation pump speed vithin
+5% of the minimum recirculation pump speed corresponding to Master Manual 'tode.
Core thermal pover betveen 95% and 100% rated. Total Core flov +0, -5X rated core flow. Notes: (1) Rated core thermal pover is 3293 MII. Bated core flow is 1065 x 106 1b/hr. (2) 45% power rod line goes through 45% rated core thermal power and 100% rated core flow. 75% power rod line goes through 75% rated core thermal power and 100% dhted core flow. 100% power rod line goes through 1004 rated core thermal pover and 100% rated core flow. Rev. 31, 7/82 SUSQUEHANNA STEAM ELECTRIC STATION UNITS 1 AND 2 FINAL SAFETY ANALYSIS REPORT POWER FLOW MAP AND POWER TEST CONDITIONS'IGURE 14.2-6 Sh. 2
400 300 I
~~ 200 UNSAFE A
M 100 SAFE UP TO LIMITED POWER 25 50 75 100 PERCENT RATED POWER 100 O SAFE, C3 M A50 O M O UNSAFE C4 D Ql
$ 4 25 50 75 100 PERCENT RATED POWER SUSQUEHANNA STEAM ELECTRIC STATION UNITS 1 AND 2 FINAL SAFETY ANALYSIS REPORT RCIC ACCEPTANCE CRITERIA CURVES FOR CAPA'CITY AND ACTUATION TIME FIGURE 14 2 7
~
SSFS- FSA R 16.2 PROPOSED FINAL TECHNICAL SPECIFICATIONS This section vill be submitted later using the NRC's Standard Technical S pecif ications. 16.2-1
SS ES-FS AR 17 2 QUALITY ASSURANCE DURING THE OPERATIONS PHASE 17 2 0 TNTRO DUCTION PPCL is fully responsible for testing, operating, maintaininq, refueling and modifying the Susquehanna SES in compliance with Federal, Sta te, and local laws and the plant operating license reguirements. These activities are also performed in response to required codes and specified QA related NRC regulatory guides. These regulatory guides and associated ANSI standards are listed in Ta ble 17. 2-1. To assure compliance with 10CFR50 ~ Appendix 8 requirements, PPCL has established and implemented a management control plan for assurinq the quality of saf ety-related activities during the operations phase. The plan consists of a) this Operational Quality Assurance (OQA) Program which contains PPCL's quality assurance commitments to the Nuclear Regulatory Commission; b) the OQA Manual which contains Operational Policy Statements (OPS) and defines PPCL's policies for meeting these commitments; and c) Nuclear Department Instructions and functional unit procedures which contain, the detailed steps. necessary for a functional unit to. comply with the OQA Program requirements. The relationships between these documents are shown in Figure 17. 2-1. Xn implementing the OQA Program, PPCL assures that its activities comply w.ith Federal Bequlations which are designed to protect the health and safety of the public. The OQA policie, qoals and objectives of PPCL are stated in the followinq Nuclear Quality Philosophy and Intent statement: For the Susquehanna Steam Electric Station, Pennsylvania Power 6 Liqht Company will comply with the requirements of
, 10CFR50, Appendix H, Quality Assurance Criteria for Nuclear Power Plants ahd Fuel Reorocessina Plants and other applicable federal regulations with respect to all safety-related activities which include engineerinq,< design, procurement, construction, preoperational testing, power testing, operation, maintenance, re fueling, repairing, modification and in-service inspection. PPCL is also committed to be responsive to the applicable Regulatory Guides, Industrial Codes and Standards, or parts thereof, as specifically noted in controlling documents. The applicability of these Guides, Codes, and Standards, or parts t.hereof, and their effectiveness shall be interpreted by the responsible managers. If Guides, Codes, or Standards are nonexistent or inadequate, PPCL shall develop the required practices and procedures with the controls necessa ry,for their implementation.
Rev. 28, 1/82 17% 2 1
SS ES- FS AR
- 17. 2 1 ORG ANIZATION PPGL has es+ablished the Nuclear Department in order to provide a cohesive management team with the primary objective of providing lonq term technical and management support for Susquehanna SES.
In addition +o the resources within the Nuclear Department, auxiliary support is provided by the Construction .'.tanager and the Manaqer-Procurement. The key management positions responsible for the performance of safety related activities are described in the fo] lowinq subsections,. Fiqure 17.2-2 shows the organizational structure and lines of responsibility for the groups that provide technical and management support for Susquehanna SFS. The positions listed below are described in the followinq subsection.: Son ior Vice Presid en t- Nuclear Vice President-Enqineerinq and Construct ion (EGC) -Nuclear (Project Director) Vice Pre ident-Nuclear Operations A.,sistant Project Directors Manaqer-Nuclear Plant Engineerinq (NPE) Project Cons+rue+ion Manage" Manaqer-Nuclear Dual i+ y Assuranre (NQA) Superintendent of Plant Assistant Superintendent of Plant Assistant Su perintendent-Outaqes Integrated Startup Group Supervisor Manager-Nuclear Support Manager-Nuclear Traininq Manager-Nuclear Safety Assessment Manaqer-Nuclear Licensinq Manaqer-Nuclear Administration Construction Manaqer Manaqe r-Procurement ln addition to the above individuals, the Susquehanna Review Committee (SRC) is established as a review, audit and advisory group, comprised of at least five key Nuclear Department managers, whose function is to verify independently that the Susquehanna SES is beinq tested, operated and maintained in accordance with all safety related, ALARA and environmental requirements. The SBC will perform the independent review mandated by ANSI H18.7. 1 7~ 2 2 Rev. 33, 4/83
SSES-FS AR
- 17. 2. 1. 1 Senior Vice President Nuclear The Senior Vice President Nuclear has overall authority and responsibility for the Susquehanna OQA Program and, as a result, he:
(a) Requires the performance of an annual, preplanned and documented assessment of the OQA Program in which corrective action is identified and tracked. (b) Sets OQA Poli'cies,. qoals and objectives for safe operation of Susquehanna SES. (c) Commits PPGL to an OQA Program designed to assure compliance with requlatory requirements. (d} Requires compliance with the provisions of the OQA Proqram and causes periodic assessments of PPGL commitments and established practices for safe plant o per at ion. In order to maintain a continuing involvement in QA matters, the Senior VP-Nuclear receives monthly written reports on the status and adequacy of the OQA Program issued by the Manager-NQA and approves the Operational Policy Statements contained and'eviews in the OQA Manual prior to their issuance. The Senior VP Nuclear delegates to the VP EGC Nuclear and the VP-Nuclear Operations those responsibilities for attaining specified quality levels and, to the Manager-Nuclear Quality Assurance those responsibilities for verifying that those'uality level s have been met. The Senior VP Nuclear delegates to the Manager-Nuclear Safety Assessment the responsibility for performing the on-.,ite Independent Safety Enqineerinq Group (ISEG) function mandated by NUREG-Q731. In addition, the Senior Vice President-Nuclear has overall corporate responsibility for Susquehanna SES activities related to enqineerinq, constru'ction, startup and operations. The Senior VP-Nuclear delegates these responsibilities to the Vice President-EGC-Nuclear, and the Vice President-Nuclear Operations. The reportinq relationships are shown in Figure 17.2-2. Rev. 28, 1/82 17& 2 3
SSES-FSAR
- 17. 2. 1. 1. 1 Vice President Enqineerinq 6 Construction (HGC) nuclear The VP F~C Nuclear (also identified as the Project Director nn Fiqure 17.2-2) has overall corporate responsibili y for the Susquehanna engineerinq, construction and licensing activities as deleqated by the Senior VP-Nuclear. In addition, as Project Director, he directs and is accountable for all facets of project, performance +hrouqh project completion.
- 17. 2. 1. 1. 1. 1 Assistant Project Directors The Assis+ant Project Directors at the site (APD-S) and Allentown (APD-A) are responsible to the Project Director for the enqineerinq and construction aspects of the pro ject. Their responsibilities encompa s the day-to-day decision-making process, conduct of pro ject activities, and contract administration. They also coordinate the support f unctions of other company departments as they interface with the project.
The (APD-S) has a direct coordination and inteqration relationship with the NQA Resident Nuclear Quality Assurance Enqineer (RMQAE) . The RNQAE, in tu n, has the responsibility to support the APD-S objectives by alertinq the APD-S to quality rela+ed matters which have the potential for adversely affecting construction activities.
- 17. 2.1. 1.1. 2 Nanaaer Nuclear Plant Enaineerinq The Nanaqer NPE is responsible .for enqinee" ing activities (includinq those related to nuclear fuel) and +heir quality management. The. e activities include a) desiqn and design verification related to plant modifications, b) the technical evaluation and approval of acceptable suppliers of parts, components, equipment, and systems, c) specifyinq technical requirements for tho procurement of spare parts, d) modifications to the "as-built" plant, and e) enqineerinq outage support.
- 17. 2. 1. 1. 1. 3 pro ject Construction lfanager The Projec+ Construction Manager is responsible for the nerformance of construction activities at Susquehanna SHS, includinq that of prime contractors, and fo" the preparation of equipment and systems for turnover to the Integrated Startuo Group for +estinq. The Project Construction Manager receives Rev. 33, 4/83 17. 2-0
SS ES- FSA R administrative and project technical direction from the Project Director throuqh the Assistant Project., Director-site. 17.2.1 1.1.4 Manage Nuclear Licensing The Manager-Nuclear Licensinq is responsible for directing the licensinq aspects for Susquehanna SES. This includes interfacing with the Licensinq Branch of the NRC, updating and changing the CESAR to reflect as-built conditions or modifications, and coordinatinq responses to the NRC relative to IE Bulletins.
- 17. 2.1.1.2 Vice president Nuclear Operations The Vice President-Nuclear Operations is responsible for the Initial Test Program and operation of Susquehanna SES. This includes formulatinq and establishinq the necessary technical and administrative staff and planning and coordinating the activities of these personnel.
The Vice President-Nuclear operations delegates responsibilities to the Superintendent of Plant, Manaqer-Nuclear Support, Manager-Nuclear Traininq, and Manaqer-Nuclear Adminstration. 17 g,1,1,2,1 Supegintendeng of Plant The Superintendent of Plant is responsible for Susquehanna SES durinq plant testing, startup, and operation and has for the Initial Test Program conducted by the overall'esponsibility Integrated Startup Group. The Superintendent of Plant is responsible for the safe operation of Susquehanna SES and has overall responsibility for the execution of the administrative controls at the plant to assure safety. The Superintendent of Plant ensures that plant operations are conducted in accordance with the plant operating license, technical specif ications, the FSAR, and the OQA Proqram with its implementing documents. 'he Superintendent of. Plant delegates his authority f or performing activities related to operation of the plant to the Assistant 'Superintendent of Plant, Assistant Superintendent-Ou taqes, Supervisor of 0 pe rations, Supervisor of Maintenance, Technical Supervisor, and other personnel assiqned to the staff organization. The Superintendent of Plant reports to and is 'directly accoutable to the Vice President-Nuclear Operations for activities directly related to plant support of preoperational testinq.
- 17. 2-5 Rev. 33, 4/83
SSFS-FSAR 17.2 1 1.2,1,1 Assistant Superintendent of Plant The Assistant Superintendent of Plant assists the. Superintendent of Plant in all matters and assumes the responsibilities of the Superintendent of Plant in his absence. 17 2.1,1. 2.1,2 Assistant Supegigtendent-Outgoes The Assistant Superintendent-Outaqes reports to the Superintendent of Plant and is responsible for outaqe management at Susquehanna SES includinq planning, establishment of qoals, and performance. 17 2. 1- 1. 2. 1. 2. 1 Integrated Startup Group Supervisor The Integrated Startup Group Supervisor has the responsibility for supervisinq the conduct of the Integrated Startup Group {ISG) . The ISG Supervisor reports to the Assistant Superintendent-Outaqes on matters pertaining to the Initial Test. Program (ITP). The qualifications for this position are listed in Chapter 14.2.
- 17. 2. 1. 1. 2. 2 Manager. Nuclear support The Manager. - Nuclear Support is responsible for coordinating both Nuclear Department activities and selected outside service organization activities in support of Susquehanna SFS startup and operation.
The Manaqer Nuclear Support provides technical assistance to the Susquehanna SES Plant Staff in the areas of operation and maintenance. The Manager Nuclear Support advises the VP-Nuclear Operations of activities within or affecting the Nuclear Department and advises the Susquehanna SFS Plant Staff of potential changes to plant operatinq and maintenance reguirements by reviewing changes to Requlatory Guides, .Industry Standards and other industry literature. 17.2. 1. 1.2. 3 Manaaer Nuclear Trainina Rev. 33, 4/83 17 2-6
SSZS-FSAR The Manager-Nuclear Training is responsible for assessing the long term training needs reqardinq Susquehanna SES and developing training proqrams commensurate with those needs.
- 17. 2. l. 1. 2. 4 Manaaer Nuclear Administration The Manager-Nuclear Administration is responsible f or developing and implementing a nuclear records management sy"tern and directina all interfacinq organizations toward the implementation of the system. The Manaqer-Nuclear Administration is also responsible for establishing and maintaining a document control system for Susquehanna SES.
17.2. 1. 1. 3 Nagaqer Nuclear Saf et'ssessment The Manager-Nuclear Safety Assessment is responsible for independently reviewinq and monitoring all nuclear activities to ensure that they are performed in a manner which results in safe reliable operation. 17.2.1.1.4 Manaaer Nuclear.Ouality Assurance The Manager-NQA is responsible for: (a) Directinq and coordinating the development and updating of PPSL~s OQA Proqram. (b) Assurinq overall implementation of the OQA Program. (c) Tnterpretinq the OQA Proqram, subject to the approval of the Senior Vic'e President Nuclear. (d) Auditinq, monitoring, inspecting and witnessinq, as necessary, contractor, vendor and plant safety-related activities to assess compliance with the requirements of the OQA program and/or procurement documents, and reportinq the results of these activities to responsible manaqement. (e) Beviewinq Nuclear Department Instructions and functional unit procedures to assure compliance with the OQA Proqram. (f) Providing traininq assistance in OQA Program requirements. Rev. 33, 4/83 17 2-7
SS HS- FS AB (q) Implementinq the QA and site QC activities identified in the OQA Proqram. (h) Reviewinq and auditinq the OQA Proqram provisions that are applied to the fire protection program and reportinq the results of these activities to responsible manaqement. (i) Implementing the nondestructive examination traininq, qualification and certification program. {j) Evaluating potential suppliers of material eguipment and services to determine their capabilities for providinq quality products or services. (k) Overseeinq the administrative integration of the OQA and Environmental auditinq proqrams for Susquehanna SES. (1) Reviewinq and approving quality assurance requirements in proc urement documents. The Manaqer NQA is responsible for taking action (including work stoppage), as necessary to correct conditions adverse to actuality. The Manaqer NQA is responsible for informing the Superintendent of Plant when it is determined that safety-related components or the activities performed on these components fail to comply with approved specifications, plans, or procedures. The Superintendent of Plant retains the responsibility for the evaluation of conditions adverse to quality with regard to plant operation and is responsible for determining when an operating unit(s) is to be shut down. PPGL requires that the Manager-NQA shall have qualifications that are commensurate with the responsibilities of that position. As a minimum, these shall include a B. S. in Engineerinq and ten years experience in Enqineerinq and/or Construction. At least one year of this ten years experience shall be nuclear power plant experience in the overall implementation of the quality assurance program. The Manaqer NQA and the NQA Staff are independent of organizations responsible for performinq safety-related activities. The NQA Section has sufficient authority and organizational freedom to identify quality problems, to initiate, recommend or provide solutions through designated channels, and to verif y implementation of solutions. The PPGL Nuclear Quality Assurance f unctional structure is shown in Fiqure 17.2-3. The Manager NOA delegates functional responsibilities for accomplishing quality assurance activities as folio ws: Rev. 33, 4/83 17. 2-8
SSES-FSAR Quality Enaineerina 6 Procurement
- l. Quality Enqineerinq (a) Interface with engineering organizations to accomplish the incorporation of quality requirements in design, test, 6 procurement
.documents via the specification, review and approval process.
{b) Interface to provide QA coverage of nuclear fuel. (c) Review and maintain cognizance of applicable codes and standards (d) Review and support responses to NRC Bulletins, Circulars, and Information Notices. (e) Review and support for reporting items per 10CPR50. 55 (e) and 10CPR21. (f) Provide technical support for auditing. (q) Coordinate responses to NRC Inspections. {h) Provide administrative support functions.
- 2. P roc ure ment (a) Perform'endor QA program evaluations, surveys and performance trendinq and rating, vendor audits.
(b) Perform technical review/acceptance of vendor QL records. (c) Provide for post award vendor meetings {review P.O. pro visi ons) . (d) Perform Source surveillance/verification. Construction {a) Interface with QA'nd QC organizations for plant construction support. (b) Interface with NRC construction inspectors. (c) Provide direct support of the preservice inspection activities. (d) Retain direct responsibility f or the review of NDE procedures. Rev. 33, 4/83 17 2-9
SS ES-FS AR {e) Provide QA support for specified major modifications during plant operations. (f) Interface with the Authorized Nuclear Inspector. (q) Perform audits of construction activities. (h) Review of construction procedures and instructions. (i) Perform field checks and verification of responses to NRC citations, bulletins, circulars and reportable conditions related to construction activities. (5) Provide for completion of N-3 Forms. (k) Perform quality trending of construction related ac ti vi ties. Operations
'1.. Quality Assurance (a) Interface with the Plant Staff and ISG fo" the QA support of preoperational, startup testing and plant operations.
(b) Review administ ative, preoperational and startup test procedures. (c) .Interface with NRC operations inspectors. (d) Perform field checks and verification of responses to NRC citations, bulletins, circulars and reportable conditions related to operations acti vi ties. (e) Perform audits of operations. (f) Perform quality trending of plant operations related activities.
- 2. Dual.ity Control (a) Inspect maintenance, modification, repair, testing and PPGL Construction activities.
I (b) Perform and interpret the results of NDE. (c) f r ece ipt inspection a nd acceptance of Per or m material, equipment and consumables. Rev. 33, 4/83 17 2- 10
S SES- FS AR (d) Fvaluate NCRs for trends. (e) Review procedures for insertion of hold/notification points. (f) Perform inspection planning.
- 3. Quality Systems 6 Training (a) Provide for auditor training, qualification and certification.
(b) Provide for Inspector training, qualification and certification. (c) Coordinate QA indoctrination and training fo" the NQA section and other PL orqanizations. (d) Maintain the Construction QA Program. (e) Develop and maintain the Operational QA Program. (f) Develop and maintain NQA Section procedures. D. Auditing fa) Schedule and scope proqrammatic audits of PPGL and other orqanizations. (b) Coordinate the implementation of programmatic audits and the allocation of auditor resources throuqh the other NQA supervisors. (c) Perform audits of other NQA subsections. (d) Evaluate and trend the results of the auditing effort. (e) Perform audit follow-up and verification/close-out. The Manager-NQA is responsible for initiatinq correspondence such that the NRC is notified of changes to (1) the accepted FSAR QA program description prior to their implementation, and (2) organizational elements within thirty (30) days after their announcement. (Note--editorial changes or personnel reassiqnments of a non-substantive nature do not require NRC notification.) Rev. 33, 4 /83 17. 2-11
SS ES- FS AR The Construction Manager is responsible f or providing the necessary orqanization, trained resources and equipment for the performance of maintenance tasks during normal operations and for outages. The same organization and resources will also be responsible for completion of plant modif ications, repairs and/or additions to the operatinq plant. These operations will encompass prospects/tasks assigned hy the Superintendent of Plant either directly or through the on-site organization. Activities will be defined in procedures developed in accordance with OQA Program requirements.
- 17. 2.-1.3 Manager Procurement The,Manaqer Procurement is responsible for the purchase of equipment,'aterials. supplies and se'rvices that conform to all applicable purchasing specifications and for procurinq equipment, materials, supplies. and services from approved suppliers (except for nuclear fuel as specified in Subsection 17. 2. 1. 1..2. 5) .
Procedures shall define how the procurement process is controlled'n accordance with OQA Program requirements. 17 2 2 OOALITY ASSURANCE PROGRAM The Operational Quality Assurance {OQA) Program is applied to all safety-related Susquehanna SES structures, systems, components, and activities. SAFETY RELATED is a generic term applied to: Those systems, structures, and components that meet one or more of the followinq requirements: (a) Maintain.the integrity of the Reactor Coolant System pressure boundary. (h) Assure their capability to prevent nr mitiqate the consequences of accidents that could cause the release of radioactivity in excess of 10CFR100 limits. (c) Preclude failures which could cause or increase the severity of postulated accidents or could cause undue risk to the health and safety of the public due to the release of radioactive material. (d) Provide for safe reactor shutdown and immediate term post accident control. or'onq Rev. 33, 4 /83 17& 2 12
SSES- FSAR Those activities that affect the systems, structures 2~ and components discussed in'Item l above such as their construction, operation, desiqn, procurement, refuelinq, maintenance, modif ication and testing. The Manager - NPE is responsible for maintaining a list designating those structures, systems, and components which are safety-related based upon the applicable portions of Table 3.2-1. The OQA Program vill be .implemented at least 90 days prior to fuel load. Safety-related activities occurrinq prior to the implementation of the 'OQA Proqram will be controlled by the Susquehanna QA Proqram. The Susguehanna QA. Program will be modified throuqh amendments to the PPSL QA Manual, as necessary, to cover nev activities occurring durinq the preoperational test ing pha se. The Senior Vice President Nuclear has assigned to the Manaqer-Nuclear Safety Assessment the responsibility for reqularly assessinq the scope, st'at us, implementation, and ef fectiveness of the OQA Proqram. This will assure that the Proqram is adequate and complies with 10CFR50, Appendix B. The OQA Program requires that safety-related activities be performed usinq specified equipment under suitable environmental conditions and that prerequisites have been satisfied prior to inspection and test. The Manaqer NQA is responsible for establishing and maintaininq the OQA Program and for insurinq that it provides adequate control of all activities. The Manager NQA is responsible for assurinq that functions delegated to principal contractors are being properly accomplished. Supplier QA programs are evaluated to determine that the requirements of 10CFR50 Appendix B will be implemented and this evaluation is documented-. The corporate OQA policies, goals, and objectives are transmitted to the persons performinq activities vhich are required by the OQA Program and supportinq documents. The commitments of the OQA Program are described in Chapter 17 vhich also assiqns responsibilities for implementing OQA Program commitments. The OQA Manual contains Operational Policy Statements (OPS) which stipulate PPGL QA policies, goals and objectives for implementing the OQA Program commitments. These policies give generic direction for the performance of activities. A synopsis of the OPS and a matrix which cross-references them to each criterion of Appendix B to 10 CFR Part 50, is contained in Table 17.2-2. The OQA Proqram is patterned after and fully complies with ANSI N18.7-1976 as modified by NRC Regulatory Guide 1.33, Revision 2 except for the review frequency of certain procedures (i.e. reaqent preparation) vhich employ standardized methods for Rev. 33, 4/83 17& 2 1 3
SS ES-FS AR performance of plant-support evolutions. The reviev frequency ,for these procedures vill be established appropriate to the nature of the activities addressed by the procedures. The degree of compliance with:other regulatory quides and associated ANSI Standards is listed in Table 17.2-1. Where quides, codes or standards are nonexistent or inadequate, PPGT. will develop methods to provide the necessary control. The OQA Proqram requirements are mandatory for all safety-related activities. Fach functional unit manager is responsible for assuring that safety-related activities performed by that. functional unit, meet the requirements of the OQA Program. inspection The Manager NQA is responsible for the audit, review, and verification of activities both- onsite and offsite to assure that they are accomplished accordinq to the OQA Program requirements. OC activities shall be performed in compliance with the OQA Program requirements. Disagreements betveen NQA and other department personnel (such as Enqineerinq, Construction, Fuels, Plant Staff, and Procurement) concerninq the OOA Program and related activities will be resolved between the Manager-NQA and the affected department's supervisor or manaqer. Disagreements not resolved at these levels vill he referred to the Senior Vice President Nuclear for resolution. The OQA Manual, which contains OPS, is controlled and distributed by the NQA Section. All manaqers responsible for the performance of safety-related activities will be issued controlled copies of the OQA Manual. The Manager NQA is responsible for obtaining appropriate review and approval of the content and chanqes to the OQA Proqram and Manual. Any group performing activities governed by the OQA Program and Manual may propose changes to these documents. All OOA Proqram (FSAR Section 17.2) changes require review by the Manager NQA, the Vice President EGC Nuclear and the V.P. Nuclear Operations, and approval by the Senior Vice President Nuclear. All OQA Manual chanqes shall be reviewed by functional unit managers affected by the change and reviewed and approved by the Manaqer NOA, Vice President EGC Nuclear, V.P. -.Nuclear Operations and Senior VP - Nuclear. Nuclear Department Instructions vhich implement the OQA Program shall be reviewed by the Manaqer-NQA and approved .by the appropriate Vice President. Functional unit procedures shall be reviewed by t.he Manager NQA and revieved and approved by the appropriate functional unit manaqer. Control of QA programs other than the applicant's is addressed in Subsection 17.2.7. Individuals performinq inspection, examination and testing functions associated with normal operations of the plant, such as surveillance testing, routine maintenance and certain technical 17 2-14 Rev. 33, 4/83
SSES-FSAR revievs normally assigned to the on-site ope ation organization shall be qualified to ANSI 3.1-1978. Personnel whose qualifications are not required to meet those specified in ANS 3.1 and who are performinq inspection, examination and testing activities during the operational phase of the plant shall be qualified to ANSI 3.1-1978 N45.2.6-1978, except that the QA experience cited for Levels I, II and out III shall be of interpreted inspection, to mean actual experience in carrying the types examination and testinq activity heing performed. Managers are responsible for assuring that their personnel receive the indoctrination and training necessary to properly perform their activities. The indoctrina.tion and training proqram shall be such that personnel perform'ing activities are knowledgeable in procedures and reguirements and proficient in implementing those procedures. The program assures that: (a) Personnel responsible for performing activities are instructed as to the purpose, scope, and implementation of the safety-related manuals, instructions, and procedures which control their activities. (b) Personnel performing activities are trained and qualified in the principles and techniques of the activity being performed. (c) The scope, the objective, and the method of implementing the indoctrination and training program are documented. (d) Proficiency of personnel performing activities is maintained by retraininq. Re-examination and/or recertification vill be utilized as applicable. (e) Methods are provided for documenting training sessions, includinq a description of the content and results and a record of attendance. The Manaqement and technical interfaces betveen Bechtel, General Electric and PPGL during the Initial Test Program are described in the Start-up Administrative Manual. The Susguehanna describe SES QA Proqram as modified by amendments to the QA Manual will the receipt and processinq of QA'ecords by PPGL. In addition, certain provisions of the OQA Program are applied to fire protection. These provisions apply to those items within the scope of the fire protection program such as fire protection systems, emerqency liqhtinq, communication, and breathing apparatus, as well as the fire protection requirements of applicable safety-related equipment. Specifically, the OQA Proqram applies to the 10 criteria listed in Regulatory Position 17 2-15 Rev. 33, 4/83
SS ES- FSA R C.3 in the O.S. NRC Regulatory Guide 1. 120 Revision 1, Fire Protection Guidelines for Nuclear Power Plants. The OQA Program is also structured and implemented such that the requirements of 10CFR71, Appendix F., Quality Assurance Criteria f or Shipping Packaqes f or Radioactive Material, a re f ulf illed. 17 2 3 DESIGN CONTROL The OQA Program documents 'identify those managers responsible for performinq design activities and describe their. responsibilities and methods for meeting the OQA Program requirements. The functional unit's procedures detail the steps necessary for its compliance with the requirements for its associated design activities. These procedures assure that design activities includinq changes in the design are carried out in a planned, controlled, and orderly manner. Applicable desiqn inputs such as regulatory requirements, codes and standards, and desiqn bases shall be reflected in design output documents, such as specifications, drawings, written procedures, and instructions. These design output documents shall specify the appropriate quality standards and any deviations from these quality standards will be accomplished in accordance with OQA Program requirements. The design control process shall include, but not be limited to, the followinq, where applicable: {a) Reactor physics (b) Seismic, stress, thermal, hydraulic, radiation, and accident analyses (c) Material compatibility (d) Accessibility of items for in-service inspection, maintenance, and repair (e) Verification that the design characteristics can be controlled, inspected and tested (f) Identification of inspection and test criteria The desiqn enqineer shall evaluate and select suitable materials, parts, equipment, and processes for safety-related structures, systems, and components. This evaluation and selection shall include the use of appropriate industry standards and . specifications. Materials, parts, and equipment which are Rev. 33,. 4 /83 17. 2-16
SSES-FSAR standard, commercial {off the shelf), or which have been previously approved for a different application, shall be reviewed for suitability in the intended application prior to use. Internal and external interfaces between orqanizations performing work affectinq quality of desiqn shall be identified. Procedures shall be established to control the flow of design information between organizations. These procedures shall include the review, approval, release, distribution, and revision of documents involvinq desiqn interfaces with other organizations. Designs shall be reviewed to assure that design characteristics can, be verified and acceptance-criteria are identified. Desiqns shall be verified by reviewinq, alternate calculations, or qualification testinq. Desiqn verification shall be performed bv a qualified person or qroup other than the original designer or the desiqner~s immediate supervisor. However, supervisors may perform desiqn verification subject to the restrictions of Paraqraph C. 2 of Requlatory Guide l. 64, Revision 2. Procedures for desiqn verification shall identify the responsibility and authority of persons or groups performing design verifications. Rhen a test program is used to verify the adequacy of a design, the test will'he performed on a prototype unit or initial production unit and shall demonstrate adequacy of performance under the most adverse desiqn conditions. Changes to design output documents, including field changes, shall be subjected to design control measures the same as, or equivalent to, the original measures. Responsible plant personnel are made aware of design changes/modifications which may affect the performance of their duties by: {a) Plant Operations Review Committee review of all modification packages prior to installation. {b) Installation of modifications are controlled hy the plant work authorization system. {c) Nuclear Plant Engineerinq notifies plant supervisors of desiqn changes to,allow updating of procedures. {A) Fffects of modifications are incorporated into the plant training proqram. Errors and deficiencies in the desiqn or the design process that could adversely affect safety-related structures, systems, and components will be documented and corrective action will be taken 17& 2 1 7 Rev. 33, 4/83
SS ES-FS AR in accordance with Subsection 17. 2.16. Design documents, includinq chanqes are filed as described. in Subsection 17.2.17. 17 2 4 PROCUREMENT DOCUMENT CONTROL OQA Program documents identify those managers re"ponsible for activities related to the control of procurement documents and describe their responsibilities and methods for meeting the OQA Proqram requirements. Procedures detail the steps to be accomplished in the preparation, review, approval and control of procurement documents. Managers are responsible for establishing, maintaining and implementing procedures as reguired for their functional unit to comply with OQA Program requirements. Pzocurement documents shall contain or reference as applicable: {a) Design basis technical requirements including the applicable requlatory requirements. {h) Component and material identification requirements. {c) D ra w inqs. {d) Specifications. {e) Codes and industry standards. {f) Manufacturers'est and inspection requirements. {q) Special process .instructions. Procurement documents shall identify a) the applicable quality requirements which must be met and described in the supplier's QA pzoqram, b) the documentation {such as drawings, specifications, procedures, inspection and fabrication plans, inspection and test records, personnel and proceduze qualifications and material, chemical and physical test results) to he prepared, maintained and submitted to FPGL for review and approval, and c) those records which shall be retained, controlled, maintained or delivered to PPGL prior to use or installation of the purchased items. Procurement documents shall also contain provisions for PPSL or its aqent, as applicable, to have the right of access to suppliers'nd subtier suppliezs'acilities and records for source inspection and audits. Procurement documents shall also require that the supplier submit, when required, its QA Program or portions thereof to PPSL for review and approval by qualified QA personnel prior to initiation of activities controlled by the Program. Rev. 33, 4/83 17 2-18
SS ES-PS AR Procurement documents shall be reviewed by qualified personnel for adequacy of quality requirements {surh as acceptance and rejection criteria). Quality reguirements shall be correctly stated, inspectable and controllable. Prior to their release, procurement documents shall have been prepared, reviewed and approved in accordance with OQA Proqram requirements. The procurement document review and approval is documented and filed as described in Subsection 17 2. 17. When"procurement documents are revised, they are subject to the same or equivalent review and approval as the original document. Procurement documents for safety-related spare or replacement parts for structures, systems and components are subject to controls the same as or equivalent to those used for the original equipment. All activities described in this subsection are to be performed by personnel qualified to perform the activity. 17~2 5 INSTRUCTIONS~ PROCEDURES AND DRAWINGS Activities shall be accomplished in accordance with documented instrurtions. procedures or drawings. This subsection applies to internal PPF L instructionsprocedures and drawings. Such requirements for contractors and vendors are included in procurement documents as discussed in Subsection 17.2.4. There are three qeneral levels of OQA Program doruments which are used to implement the OQA Proqram. The first document level is comprised of Operational Policy Statements {OPS) which describe PPSL's policies for complying with 10CPR50, Appendix B and OQA Proqram requirements. These OPS delineate the requirements for preparinq, reviewinq, approving, and controlling instructions, procedures, and drawings. The second level of documents used to implement the OQA Program consist.s of Nuclear Department Instructions (NDI) . These documents describe inter- and intra-department interfaces and may provide detailed instructions for implementinq the OQA Program requirements. The third level of documents consists of functional unit procedures, which detail the specific instructions required to impleme'nt the Operational Quality Program requirements. These documents require that instructions, procedures or drawinqs specify the methods utilized in complying with OPS requirements. Instructions, procedures and drawings controlled by the OQA Proqram shall include quantitative (such as dimensions, tolerances, and operating limits) and qualitative (such as workmanship samples) acceptance criteria for use in determininq that important activities have been satisfactorily accomplished. Rev. 33, 4/83 17 2- 19
SSES-FSAR The functional unit manager shall prepare, obtain the appropriate review, approve, issue, and revise the Nuclear Department Instructions and the functional unit procedures which control the activities of that qroup. These procedures are reviewed by cognizant functional unit personnel for accuracy and workability and by QA personnel for compliance with OQA Program requirements. Inspection 'lans; test, calibration, special process, maintenance, modification and repair procedures; drawings and specifications; and chanqes thereto are subject to audit for their compliance with OQA Program reguirements. 17 2 6 DOCUMENT CONTROL The document control system described in OQA Program documents requires that, prior to their release, documents and changes thereto are reviewed for their adequacy and approved and released bv authorized personnel and distributed for use at the location where the prescribed activity is to be performed. The documents controlled under this subsection as a minimum include: (a) Desiqn Specifications (b) Procurement Documents (c) Test Procedures (d) Desiqn, Manufacturinq, Construction and Installation Dra winqs (e) Manu facturinq, Inspection, and Testing 'Instructions {f) Final Saf ety Analysis Report fq) OQA Proqram Documents (h) Maintenance and Modification Procedures fi) Non-conformance Reports The NQA Section or other qualified individuals delegated by NQA, but other than the person who generated the document, shall review and concur with the document and changes thereto, with regard to QA-related aspects prior to implementation. Each manaqer who is responsible for issuinq a document is also responsible for obtaininq the proper review and approval of that document. Changes to documents are reviewed and approved by the same organizations that performed the original review and approval unless specifically delegated to other qualified
- 17. 2-20 Rev. 33, 4/83
SS ES- FSA R organizations. This review will be completed prior to issuinq the document except for temporary pro'cedures/instructions issued by the Susquehanna SES Plant Staff. This special case is described in Section 6 of the Technical Specifications and the Susquehanna Plant Administrative Procedures. Each functional unit manager is responsible f or preparing and periodically issuinq distribution lists and/or revision status lists, where necessary, for the control of quality documents issued by that functional unit. These lists identifv the additions and chanqes made to documents since the previous report period and assist recipients in maintaining up-to-date files. Each recipient is responsible for reviewing the latest list(s) to confirm that the current revision of each document is available. Prior to implementation, approved changes are included in instructions, procedures, drawings, or other documents hy procedurally controlled change mechanisms. It is the responsibility of each functional unit supervisor/manager to assure that the proper documents such as instructions, procedures, and drawings are available at the location where the prescribed activities are performed. The issuinq department is responsible for describing and implementinq measures which provide controls to prevent the inadvertent use of obsolete or superceded documents. Individuals or qroups responsible for preparation, review, approval, issue and distribution of quality documents and their revisions are identified in the OQA Program documents. 17 2 7 CONTROL OF PJJBCHASED MATERIAL~ EQUIPMENT 8 SERVICES PPGL OQA Proqram documents list those managers responsible for performinq activities related to the control of purchased material, equipment and services. .describe their responsibilities; and specify their methods for meeting the OQA requirements. Each functional unit's procedures detail the steps necessary for complying with these requirements for their activities. PPGL's system for control is comprised of supplier evaluation, surveillance of the supplier durinq production, receipt inspection of items or services, and evaluation of supplier records. The extent and methods of control used assure compliance with applicable technical, manufacturing, and quality requirements. Prior to the award of a purchase order or contract, PPCL evaluates the prospective suppliez~s ability to provide material, Rev. 33, 4 /83 17. 2-21
SSES-PSAR equipment, and, services which comply with the technical, design, manufacturinq and quality requirements. The suppliers judged capable of meeting the requirements are considered approved suppliers for the specific article. The results of supplier evaluations are documented and the records maintained in accordance with Subsection 17.2.17. The evaluation includes, as necessary, reviews of the records and performance of suppliers who have previously supplied similar articles, surveys of their facilities, and evaluations ability of their quality assurance proqrams to determine their to meet the design, manufacturinq and quality requirements of the procurement document. These quality requirements include the applicable elements of 10CFR50 Appendix B. Suppliers'ctivities during the design, fabrication, inspection, testinq, and preparation for shipment of material, equipment and components are subject to surveillance to assure their compliance with the procurement document requirements. The surveillance of suppliers is planned and performed in accordance with written procedures as described in Subsection 17.2.18. These procedures specify the characteristics or processes to be witnessed, inspected or verified and accepted; the method of surveillance; the extent of documentation required; and those responsible for implementing these procedures. These procedures also specify the audits and surveillances required to assure that the supplier complies with the quality requirements where compliance cannot be determined by receipt inspection. As applicable, qualified personnel perform receipt inspection of material, eauipment and services to assure that: (a) The material, component or equipment is properly identified and corresponds with the receiving documentation. (b) The material; component or equipment and its acceptance records are judqed acceptable in accordance with pre-determined inspection instructions prior to installation or use. (c) Inspection records or certificates of conformance attesting to the acceptability of material, components, and equipment: are available at Susquehanna SES prior to its installation or use. Upon completion of the receipt inspection, items accepted and released are identified as to their inspection status prior to forwardinq them to a controlled storaqe area or releasing them for installati.on or further work. Rev. 33, 4/83 17 2-22
SS ES- FSAR Supplier furnished records shall be reviewed and accepted by a qualified indivi'dual knowledqeable i.n.quality assurance. These records shall, as a minimum, contain: (a) Documentation that specifically identifies by purchase order number the purchased material or equipment and the specific procurement requirements, such as codes, standards, and specifications met by the items. Documentation that identifies any procurement requirements which have not been met toqether with a description of those nonconformances dispositioned naccept as isn or <<repair The requirements of th'is subsection shall also be applied to the purchase of spare and replacement parts and shall assure that these parts have a level of quality consistent with their importance, complexity, and quantity. Supplier certificates of conformance are periodically evaluated to verify their validity. The effectiveness of the control of quality by suppliers is assessed by PPGL at intervals consistent with the importance, complexity. and quantity of an item. 17,2,8 IDENTIPICATION AND CONTROL OP MATERIALS PARTS 8 COMPONENTS OOA Proqram documents list those managers responsible for performing activities related to the identification and control of materials, parts and components, includinq.partially fabricated subassemblies describe their responsibilities, and specify the methods for meetinq the OQA program requirements. Detailed steps necessary to comply with these requirements are specified in procedures. procurement documents specify the requirements that PPGL suppliers must comply with for the identification of material, parts, and components (includinq partially fabricated subassemblies) . Item identification is maintained either on the item or on records traceable to the item to prevent the use of incorrect or defective items throuqhout fabrication, erection, installation and use. The location, type, and application method of the identification shall not affect the the item beinq identified. fit, function, or quality of Materials and parts, as required by their importance to plant safety and applicable codes, standards and regulatory Rev. 33, 4/83 17. 2-23
SSES-PSAB requirements, shall be traceable to appropriate documentation such as drawings, specifications, purchase. orders, manufacturing and inspection documents, deviation reports and physical and chemical mill test reports. The correct identification of materials, parts, and components is verified and documented prior to release for fabrication, assembly, installation or shippinq. 17 2 9 CONTROL OZ SPECIAL PROCESSES Special processes are those that require interim in-process controls in addition to final inspection to assure quality. OQA Proqram documents identify those managers responsible for the writing, qualifyinq. approvinq and issuing of procedures for special processes. Procedures for special processes are prepared in accordance with applicable codes. standards, specifications, criteria, and other special requirements to control processes such as weldinq, heat treating, nondestructive examination (NDE), and chemical cleaninq. Personnel performing special processes and the procedures and equipment used for this activity are qualified in accordance with applicable codes, standards and specifications. The procedures for special processes specify the requirements for their control, the parameters to be considered, the methods of documentation, and applicable codes, standards, specifications or supplementary requirements which govern their qualification. The special processes are accomplished in accordance with written process sheets, or equivalent, with recorded evidence of verification. When special processes are not covered by existinq codes and standards, or when item quality requirements exceed the requirements of established codes or standard." the necessary qualifications for personnel, procedures or equipment are defined. I Records verifyinq the qualification of personnel to perform special processes are maintained in a current status. Procurement documents specify contractor responsibility for controllinq special processes and for maintaining records to verify that special processes are performed in accordance with established requirement s. 17 2. 10 INSPECTION OQA Proqram documents identify those managers responsible for the preparation, approval, and issuance of inspection procedures. The documents also identify those managers responsible for the performance of inspections. Onsite and offsite activities
- 17. 2-24 Rev. 33, 4/83
SSES-FS AR affecting quality are inspected in accordance with written controlled procedures to verif y confo'rmance with applicable procedures, design documents, codes and specifications for accomplishinq the activity. Activities affecting quality are subject to inspections in areas such as: (a) Special Processes as identified in Subsection 17.2.9. (b) Modifications to the Plant. (c) Receipt of Materials, Parts or Components. (d) Plant Operations. (e) Repairs or Replacement of Equipment. (f) Inservice Inspection. Inspection activities conform to the following requirements: (a) Inspection personnel are qualified individuals other than those who performed or directly supervised the activity beinq inspected. (b) Mandatory inspection hold points are identified in inspection procedures. (c) Modifications repairs and replacements are inspected in accordance with the original design and inspection requirements or approved alternatives. (d) Maintenance and modification procedures are reviewed by qualified personnel knowledqeable in quality assurance requirements to determine the need for (a) inspection, (b) identification of inspection personnel, and (c) documenting inspection results. The criteria for performinq inspections are based upon an activity's complexity, uniqueness and impact on safety. (e) If direct inspection of processed material or products is impossible or disadvantageous, indirect control by monitorinq processinq methods, equipment, and personnel is provided. (f) Inspectors are trained and qualified in accordance with appropriate codes, standards, and company training proqrams and their qualifications and certifications are kept current. (q) Inspection instrumentation is calibrated and has an uncertainty (error) equal to or less than the tolerance stated in the acceptance criteria. Rev. 33, 4/83 17. 2-25
SSES-FS AR (h) Inspection of activities is accomplished accordinq to approved procedures, instructions, and check lists. These inspection documents contain the following: (1) Identification of the items or activities to be inspected. (2) Identif ication of the characteristics of the items or activities inspected. (3) Identification of the individuals or groups responsible for performinq the inspection. {4) Identification of acceptance and refection criteria. (5) A description of the method of inspection includinq necessary measuring and test equipment. {6) Evidence of completion and verification of a manufacturinq inspection, or test. {7) A record of the inspector, or data recorder, the date and results of the inspection. (i) Inspection procedures or instructions contain or reference necessary procedures, drawings and specifications to be used when performinq inspection operations. {j) Provisions for inspection results to be documented ~ evaluated and accepted by the supervisor responsible for the inspection f unction. 17.2.11 TEST CONTROL The OQA Proqram documents identify those managers responsible for testing structures, systems and components durinq the preoperational testing, power testing and operations phases of Susqueha.nna SES. {Prior to implementation of this OQA Program preoperational testing will be performed under the control of the Susquehanna Quality Assurance Program as supplemented by interim procedures to the PPGL Quality Assurance Manual.) The test proqram described herein and further detailed in Operations Policy Statements is desiqned to assure that structures, systems and components will perform satisfactorily in service. Modifications, repairs and replacements are tested in accordance with the original design and testing requirements or by approved a lt er nates. Rev. 33, 4/83 17. 2-26
SS ES- FS AR Testing is e'stablished, documented and accomplished in accordance with written controlled procedures. These proced ures contain or reference: {a) The requirements and acceptance limits specified in the applicable desiq'n and procurement documents. (b) The instructions for performing the test. (c) The test prerequisites such as: 1 That test instrumentation is calibrated and has an uncertainty (error) equal to or less than the tolerance stated in the acceptance criteria. 2 That testing equipment is adequate and appropriate for the test. 3 That personnel performinq the test are properly trained, qualified and licensed or certified as required. That the item is sufficiently complete to be tested. 5 That environmental conditions are suitable and controlled. 6 That. provisions are made for data collection and storage. (d) The mandatory inspection hold points. for witness by PPGL, their contractor or agent. (e) The test acceptance and rejection criteria. (f) The methods of documenting or recording the test data and test results. Tests are required to be performed: (a) Periodically to provide assurance that failures or substandard performance do not remain undetected and that the required reliability of sa,fety-related systems is maintained. (b) Followinq maintenance, modification or procedural changes to demonstrate satisfactory performance. The test results are documented and evaluated to determine the acceptability of .he test. The individuals or groups responsible 17% 2 27 Bev. 33, 4/83
SSES-FSAH for evaluating the test results shall be qualified to perform this evaluation. When by evaluation of the test results, the structure, system or component is determined to be nonconforminq, it shall be controlled in accordance with Subsection 17.2.15. 17 2 12 CONTROL OF MEASURING AND TEST PPGL's OQA Proqram documents provide measures to assure that tools, gauges, instruments and other measurinq and testing devices are controlled., Calibrations are scheduled with sufficient frequency to maintain required accuracy. The measurinq and test equipment controls assure that: {a) Procedures are used to control measuring and test equipment. These procedures describe the calibration technique and frequency, maintenance and method of control of measurinq and test equipment (such as instruments, tools, qauges, fixtures, reference and transfer standards, and nondestructive examination equipmept) which are used in the measurement, inspection, and monitorinq of components, systems and structures. {b) Measuring and test equipment is identified and traceable to the calibration test data. (c) Measurinq and test instruments are calibrated at specific intervals based on the required accuracy,. purpose, deqree of usaqe, stability characteristics and other conditions affecting the measurement. (d) Measuring and test equipment is labeled or tagged to indicate the date of. the calibration and the due date of the next calibration. (e) When measurinq or test equipment is found to be out of calibration, measures are taken and documented to determine the validity of previous inspections performed since the last v'alid calibration. (f) Calibration standards have an uncertainty (error) of no more than 1/4 of the tolerance of the eguipment being calibrated, unless limited by the "state-of-the-art". (q) A complete status of all items under the calibration system is recorded and maintained. Rev. 33, 4/83 17. 2-28
SSFS-FSAR (h) Reference and transfer standards a"e traceable to nationally recognized standards; or, where national standards do not exist, provisions are established to document the basis for calibration. 17 2 13 HANDLING~ STORAGE~ AND SHIPPING OQA Program documents list those managers responsible for the handling, preservinq, storing, cleaning, packaging and shipping of materials, parts and components; and, describe t he ir authorities and methods for meeting the. guali ty requirements. procedures control each functional unit's act,ivities and assure compliance with the quality requirements contained in drawings, specifications and procurement documents. These requirements include those necessitated by the design, as outlined in the design output documents, and those submitted by the supplier. These procedures provide control to prevent damage and loss or deterioration by environmental conditions, such as temperature or humidity, and specify the personnel qualifications required to accomplish the activity satisfactorily. Consumables such as chemicals, reagents, weld rod, lubricants, etc. shall be stored in accordance with manufacturer's instructions or other approved methods to prevent harmful deterioration of the i em. Materials with an identified shelf life shall he controlled such that they are used or discarded prior to expiration date. 17 2 14 INSPECTION~ TEST~ AND OPERATING STATUS OOA Program documents list those managers responsible f or the development and implementation of procedures to assure that the inspection, test, and operating status of structures, systems, and components is properly identified and controlled. These procedures incorporate the following provisions: {a) The inspection, test, and operating status of structures, systems, and components is identified to the a ffected part ies. (b) Application and removal of inspection and welding stamps and status indicators, such as tags, markings, labels, and stamps are procedurally controlled. Rev. 33, 4/83 17. 2-29
SS ES- FSAR (c) Methods for bypassing of required inspection, tests, and other critical operations are controlled through documented functional unit procedures. (d) The status of nonconforari.nq, inoperative, or malfunctioninq structures, systems or components is identified to prevent their inadvertent use.
- 17. 2. 15 NONCONFORMING MATERIALS~ PARTS OR COMPONENTS OQA Program documents list those manaqezs responsible and their methods for handlinq nonconforming materials, parts, components, or services. Procedures control the identification, documentation, seqreqation, review, disposition and notification to affected organizations of nonconforminq materials, parts, components, or services.
Materials, parts, components or services which do no+ meet established drawinq, specification, or workmanship requirements, are identified as nonconforminq and documented. Nonconforming items are identified as discrepant and segreqated from acceptable items until they are properly dispositioned. The manager of each functional unit is responsible for the review and disposition of nonconforminq items which fall under the scope of zesponsibility of that manager. The manager is also responsible for notifying or obtaininq input from other functional units who may have a specific interest in the nonconforminq item. Documentation related to the identification, disposition and corzection of nonconformances is maintained in accordance with Subsection 17.2.17. Documentation pertaininq to nonconfozminq items or services shall include the details of .the nonconformance, the disposition, and the approval siqnature(s) . Acceptability of rework or repair of materials, parts, components, systems, and structures is verified by re-inspecting and re-testing the item by a method 'which is the same as or comparable to the original inspection and test and in acc'ordance with written procedures. Inspection, testing, rework, and repair procedures are documented. Vendor nonconformance reports dispositioned>>accept as is" or "repair" are made part of the inspection records and forwarded with the hardware to PPSL for review and assessment. Rev. 33, 4/83 17. 2-30
SS ES-PS AR Nonconformances are periodically analyzed for quality trends, and the results are reported to manaqement, for review and assessment. 17,2,16 CARR ECTI VE ACTION PPGL's OQA Program establishes the reguirements for controlling conditions adverse to quality (such as nonconformances, failures, malfunctions, deficiencies, deviations, and defective material and equipment) . Conditions adverse to quality are promptly identified, reported, evaluated, corrected and documented. OQA Program documents identify the methods used and personnel responsible for these activites. Conditions adverse to quality are identified and reported to the appropriate levels of manaqement of the affected organizations. The responsible organization evaluates the conditions- to determine if they are siqnificant conditions adverse to quality and to determine the corrective action required. If siqnificant-conditions cause of the condition and the adverse to quality are detected, the corrective action taken are reported to the appropriate management levels of affected home office organizations, plant staff and quality assurance for review and assessment. The corrective action for conditions adverse to quality shall correct the specific conditions. For conditions detormined to be significant, the corrective action provides measures to correct specific conditions and preclude recurrence. The responsible organization shall implement the corrective action and document the details of the conditions including their resolution. Follow-up action is conducted to determine that the required corrective. action has been completed and that the corrective action documentation has been closed out.
- 17. 2. 17 QUALITy ASSURANCE RECORDS A QA record system, detailed in OQA Program documents, has been established by PPGL which assures that records are identifiable, retrievable and that sufficient records are maintained to provide documentary evidence of the quality of items and services. The system assures that requirements and responsibilities for r'ecord transmittal, retention (such as duration, location, fire protection and assigned responsibilities) and maintenance, 17& 2 3 1 Rev. 33, 4/83
SSES-FSAR subsequent to completion of work, are consistent with applicable codes, standards and procurement documents. QA records include: (a) Plant Historical Records (b) Operating Loqs (c) Principle Maintenance and Nodif ication Activities (d) Reportable Occurrences (e) Results of Independent Reviews, (e. g., Plant Operations Review Committee or Susquehanna Review Committee), Inspections, Tests, Audits and Materi'als Analysis (f) Monitorinq of Work Performance (q) Qualification of Personnel, Procedures and Equipment These records also include other documentation such as drawings, specifications, procurement documents, calibration procedures and reports, nonconformance reports, and corrective action reports. Each manager is responsible for developing procedures which control the origination and transmittal of QA records within that functional unit. Each manager is responsible for transmitting QA records to the storage location designated for that record. PPGL record storage facilities are constructed, located, and .- secured to prevent destruction of the records by fire, flooding, theft, and deterioration by environmental conditions such as temperature or humidity.
- 17. 2 18 'UDT TS The PPGL audit program requires the planning, performing, documentinq, and evaluating of audits. It assures compliance with license commitments, OQA Program requirements, Technical Specifications, and other applicable requirements. It also assures that corrective measures are taken in response to audit findings to resolve the original problem and minimize the probability of its recurrence.
Audits of selected operational phase activities are performed by NOA. These audits include areas which reguire implementation of 10CFR50, Appendix B. These areas include activities associated with: (a) Plant Operation, Maintenance and Modification. Rev. 33, 4 /83 17& 2 32
4 SSES-FS AR (b) The Preparation, Review, Approval and Control of Desiqns, Specif ications, Procurement Documents, Instructions, Procedures and Drawings. (c) Receivinq and Plant Inspections. (d) Indoctrination and Training Programs. (e) The Implementation of Operatinq and Test Procedures. (f) Calibration of Measuring and Testing Equipment. Audits are reqularly scheduled based on the statu and safety importance of the activity. Audits are also scheduled according to the requirements of Section 6 of the Technical Specification. The audit schedule assures proper coverage of all applicable activities. Additionally, the audit program provides for schedulinq audits which can be conducted on short notice to respond to specific quality problems. Audits are structured with a sufficiently defined scope to permit oh jective evaluation of the activity observed. procedures and instructions are audited to measure Duality-related'ractices,
~
both the effectiveness of their implementation and their conformance to OQA Proqram requirements. The audit process is conducted according to procedures which require that a written audit plan be prepared. The audit plan ensures the proper scope, team preparation, and depth of coverage. The audit process includes, as applicable, an evaluation of work areas, activities, processes, and items Audits include a review of associated documents and records. Audit teams consist of trained personnel, not directly responsible for the areas audited. Each team shall have a desiqnated leader who is responsible for the planning, conduct, and reportinq of the audit. The auditor qualification program ensures that audit team members are qualified to perform their assigned tasks. Audit results are documented in a formal audit report which is transmitted to the responsible levels of management. Audit team leaders, throuqh their supervisors, ensure that responsible manaqement takes necessary action to correct deficiencies noted, and provide a basis for preventing their recurrence. Team leaders verify, either through review of documentation resulting from corrective action, or if necessary, re-audit, that deficiencies have been properly corrected. Rev. 33, 4 /83 17% 2 33
SSES-FSAH Formal audit reports are reviewed bv NQA management to determine the effectiveness of the OQA program, and .indications of quality of these If additional ma nagement action is required, reviews are formally reported to the the results 'rends. appropriate manager of the responsible organization. Rev. 33, 4/83 17 2-34
Table 17.2-2 OPERATIONAL POLICY STATEMENT CROSS REFERENCE MATRIX WITH 10CFR50 APPENDIX B CRITERIA OPS TITLE SYNOPSIS CRITERIA 1> 2 1 Operational Quality Defines the scope and applicability of the OQA Program. Establishes requirements for II,V,VI Assurance Program the OQA Manual and defines the tiers of documents comprising the OQA Program. 2 Terms and Definitions Defines those terms having particular meaning within the context of the OQA Program 3 Control and Issuance of Establishes controls for the issuance and use of documents. Defines those documents V, VI Documents controlled by the OQA Program and requires review, approval, and use of documents at required locations. 4 Document Reviews Establishes the requirements for performing and documenting document reviews. IIII IVI VI 5 Deficiency Control System Delineates those activities associated with the control and correction of nonconforming VIII, XV, XVI material, parts or components; other conditions adverse to quality; and significant conditions adverse to quality. 6 Qualification, Training Establishes the requirements for the training, qualification and certification of II, IX, XVIII and Certification of personnel performing activities affecting quality to assure that they achieve and Personnel maintain suitable proficiency. 7 Auditing and Surveillance Establishes the requirements for the development of programs for auditing and monitoring II, XVIII Activities quality related activities and includes performance, qualifications, reporting, and follow-up action. 8 The Collection, Storage, Establishes the requirements for the collection, storage, and maintenance of quality XVII and Maintenance of Quality assurance records. Assurance Records 9 Control of Modifications & Establishes the requirements for ensuring that the quality of modified structures, systems Design Activities or components is at least equivalent to that specified in the original design bases, material specifications, and inspection requirements. 10 Procurement Control Establishes the requirements for the procurement of material, parts, components, services IV, VII and spare parts. 11 Nuclear Fuel Management Establishes the requirements for the management of nuclear fuel activities IV, VII 12 Administrative Control of Establishes the requirements for the administrative and procedural controls that ensure Plant Operations the plant is operated in a safe and efficient manner. 13 Maintenance, Installation Establishes the requirements for ensuring that structures, systems, and components are IX, XIV of Modifications and maintained in a condition to perform their intended function. The field activities Related Activities associated with modifications are also included. Rev. 28, I/82
Table 17.2-2 Cont. 14 Control of Inspection Establishes the requirements for testing and inspection activities. X> XI, XIV and Testing 15 Inservice Inspection Establishes the requirements for the quality-related Inservice Inspection activities. X, XI 16 Instrument and Calibration Establishes the requirements for the calibration and control of calibration standards, XII Control installed plant instrumentation, and measuring and test equipment. 17 Control of Plant Material Establishes the requirements for the control of plant material and includes receipt VII 'III> XIII inspection, handling, storage, and shipping. 18 ASME Supplement Establishes the requirements for PP&L to perform engineering, fabrication, and repair N/A activities in accordance with Section XI of the ASME Code. 19 Reporting of Substantial Establishes the requirements for reporting substantial safety hazards (10 CFR 21) and N/A Safety Hazards, Licensee reportable occurrences and requirements for inclusion of 10 CPR 21 requirements in Event Reports and procurement documents. Significant Events Footnotes: (1) Criterion I, Organization, is covered extensively in Section 17.2.1 and is not repeated in a separate OPS. However, the "Responsibility" section in each OPS identifies the managers responsible for implementation and verification of the OPS'equirements. (2) Criteria such as V, Instructions, Procedures, and Drawings, and XVII, Records, could be cross referenced with the majority of OPS identified. A deliberate effort was made to cross reference the Criteria only to those OPS which have a direct relationship. Rev. 28, I/82
Table 17.2-2 OPERATIONAL POLICY STATEMENT CROSS REFERENCE MATRIX HITH 10CFR50 APPENDIX B CRITERIA OPS TITLE SYNOPSIS CRITERIA I, 2 Operational Quality Defines the scope and applicability of the OQA Program. Establishes requirements for II ~ VI VI Assurance Program the OQA Manual and defines the tiers of documents comprising the OQA Program. Definition 2 Terms and Definitions Defines those terms having particular meaning within the context of the OQA Program. Control and Issuance of Establishes controls for the issuance and use of documents. Defines those documents Vs VI Doc~ate controlled by the OQA Program and requires review, approval, and use of documents at required locations. Document Reviews Establishes the requirements for performing and documenting document revievs. 111, IV, VI 5 Deficiency Control Delineates those activities associated with the control and correction of nonconforming VIII, XV, XVI material, parts or components; other conditions adverse to quality; and significant conditions adverse to quality. Personnel Qualification Establishes the requirements for the training and qualification of personnel performing II, IX, XVIII and Training activities affecting quality to assure that they achieve and maintain suitable proficiency. Auditing/Quality Establishes the requirements for the development of programs for auditing and monitoring II, XVIII Verification Activities quality related activities and includes performance, qualifications, reporting, and follow-up act ion. 8 Records Establishes the requirements for the collection, storage, and maintenance of quality XVII assurance records. Control of Modifications & Establishes the requirements for ensuring that the quality of modified structures, systems Design Activities or components is at least equivalent to that specified in the original design bases, material specifications, and inspection requirements. 10 Procurement Establishes the requirements for the procuremenr of material, parts, components, services IV, VII and spare parts. Procurement of Nuclear Establishes the requirements for the procurement of reload nuclear fuel. IV, VII Fuels 12 Administrative Control of Establishes the requirements for the administrative and procedural controls that ensure Plant Operations the plant is operated in a safe and efficient manner. 13 Control of Maintenance Establishes the requirements for ensuring that structures, systems, and components are IX, XIV maintained in a condition to perform their intended function. The field activities associated wirh modifications are also included. Control of Testing and Establishes the requirements for testing and inspection activities. X, XI, XIV Inspection Activities 15 Inservice Inspecrion Establishes the requirements for the quality-related Inservice Inspection activities. X, XI 16 Instrument and Calibration Establishes the requirements for the calibration and contxol of calibration standards, XII Control installed plant fnstrumentatfon, and measuring and test equipment. 17 Control of Plant Material Establishes the requfrements for the control of plant material and includes receipt VII, VIII, XIII inspection, handling, storage, and shipping. 18 ASME Supplement Establishes the requirements for PP6L to perfrom engineering fabrication, and repair N/A activities in accordance with Section III of the ASME Code. Footnotes: (1) Criterion I, Organisation, is covered extensively in Section 17.2.1 and is not repeated in a separate OPSY However, the "Responsibility" section in each OPS identifies the managers responsible for implementation and verification of the OPS'equirements. (2) Criteria such as V, Instructions, Procedures, and Drawings, and XVII, Records, could be cross referenced with the majority of OPS identified. A deliberate effort was made to cross reference the Criteria only to those OPS which have ~ direct relationship.
SS ES-PS AR 18 0 ORGANIZATION This chapter contains a response for each,TNI-related requirement. The chapter is divided into sections which contain the responses to all requirements for applicants for operating 1icenses. The table of contents identifies which section provides the responses for a given document. Each section 'addresses all the requir'ements 'in its corresponding document. A response is only given to the most recent in the series of requirements which contains an explanatory text. Por example, if an explanatory text of requirement I.A.l.l appears on both NUREG 0737 and NUREG 0694, a response is provided to NUBEG 0737 since it supersedes all previous requirements. If requirement I. A.1.2 appears in both NUREGs 0737 and 0694, but the only explanatory text is in NUREG 0694, the response is provided to NUREG 0694 utilizing the implementation dates of NUREG 0737. The responses in this chapter are applicable to Unit 1 and systems common to Units 1 and 2. Rev. 27, 10/81 18.0-1
I 'J ! ~ 0
SSES-CESAR 18.1. 1.'1 Stafement of Qegag~ement" Each licensee shall pz;ovide an on-shift technical advisor to the shift supervisor. The. shift technical advisor {STA) may serve more than one unit at a multiunit site the advisor function for the various if qualified to perform units."'he STA shall have a bachelor~s degree or equivalent in a scientific or engineering discipline and have received specific training in the response and analysis of the plant for transients and accidents. The STA shall also receive training in plant design and layout, including the capabilities of instrumentation and controls in the control room. The licensee shall 'assign normal duties to the STAs that pertain to the engineering aspects of assuring safe operations of the plant, including the review and evaluation of operating experience.
\
The need for the STA position may be eliminated when the qualifications of the shift supervisors and senior operators have been upgraded and the man-machine interface in the control room has been acceptably upgraded. However, until. those long-term improvements are attained, the need for an STA progra~ will continue. The staff has not yet established the detailed elements of the academic and training requirements of the STA beyond the guidance given in the Vassallo letter on November 9, 1979. Hor has the staff made a decision on the level of upgrading required for licensed operating personnel and the man-machine interface in the control room that ~ould be acceptable for eliminating the need of an STA. Until these requirements for eliminating the STA position have been established, the staff continues to require that, in addition to the staffing requirement specified in Subsecpion 18.1.3, an STA 'be available for duty on each operating shift when a plant is being operated in Hodes 1-3 for a BHR. At other times, an STA is not required to be on duty. Since the Hovember 9, 1979 letter was issued, several efforts have been made to establish, for the longer term, the minimum level of experience, education, and training for STAs. These efforts include work on the revision to AHS-3'.1, work by the Institute of Huclear Power Operations (XHPO), and, internal staff efforts. Rev. 27, 10/81 18 ~ 1-0
SSES-PSAR INPO has made available a document entitled "Nuclear Power Plant Shift Technical Advisor--Recommendations for Position Description, Qualifications, Education 'and Training.>> Sections 5 and 6 of the INPO document describe the education, training, and experience requirements for STAs. The NRC staff finds that the descriptions as set forth in Sections 5 and 6 of Revision 0 to the IHPO document are an acceptable approach for the selection" and traininq of personnel to staff the,STA positions. "'{Note: This should not be interpreted to mean that this is an NRC requirement at this time. The intent is to refer to the IHPO document as acceptable for "interim guidance for a utility in planning its STA proqram over the long term -{i.e., beyond the January 1, 1981 requirement to have STAs in place in accordance with the qualification requirements specified in the staff's November 9, 1979 letter). Applicants for operatinq licenses shall provide a description of their STA training and requalification program in their application, or amendments thereto, on a schedule consistent with the NRC licensinq review schedule. t Applicants for operating licenses shall provide a description of their long-term STA program, including qualification, selection criteria, training, and possible phaseout. The description shall be provided in the application, or amendments thereto, on a schedule consistent with the HRC licensing review schedule. The description shall include a comparison of the 3.ong-term program the above mentioned IHPO document. 'ith
- 18. l. l. 2 Intervretation The applicant is to develop a training program in compliance with the November 9, 1979 letter and submit a description to the HRC.
The applicant is to provide STA coverage for all operating shifts. Candidates vill complete a training program and pass a certification examination prior to assumption of duties..The applicant is to develop a long-term program to maintain or phaseout STAs. 18.1. 1.3 Statement of Response The proqram for the selection and training of STA~s is detailed in the Nuclear Department Instruction NDI-0.2.2 ~ Selection, L Training and Certification of Shift Technical Advisors".'TA coverage vill be provided on operating shifts in accordance with Subsection 6.2.2 of the Technical Specifications. STA's Rev. 31 ~ 7/82 18 1-2
SSES-PS AR will perform the duties and have the responsibilities outlined in plant procedure AD-QA-400, "Conduct of Technical Support." STAs will meet the qualification requirements of the Vassallo letter of November 9,'979. All STA training willtobe fuel completed and STAs will be ready for shift assignment pri.or load. The STA program described above will be maintained long-term until such time as phaseout is permitt'ed i.n accordance with NRC instr uctions. 18.1 2 SHIFT SUPERVISDR RESPDNSXBILITIES (I A 1 23 No requirement stated in NUREG 0737. Refer to Subsection 18.2.2 which contains the response to the requirement stated in NU]EG 0694
- 18. 1-. 3 SHXPT QA N NI~G gI A 1 3) 18 1 3 1 t nt of Reauirement Statement R a n Applicants for operating licenses shall include in their administrative procedures (required by license conditions) provisions governing required shift staffing and movement of key individuals about the plant. These provisions are required to assure that qualified plant personnel to man the operational-shifts are readily available in the event of an abnormal or emergency situation. Interim requirements for shift staffing are given in Table 18.1-1.
These ad min istrative procedures shall also se t forth a policy, the objective of which is to prevent situations-where fatigue could reduce the ability of operating personnel to keep the reactor in a safe condition. The controls established should assure that, to the extent practicable, personnel are not assigned to shift duties while in a fatigues condition that could significantly reduce their mental alertness or their decision making ability. The controls shall apply to the plant staff who perform safety-related functions (e.g. ~ senior reactor operators, reactor operators, auxiliary operators, health physicists, and key maintenance personnel). XE Circular No. 80-02, <Nuclear Power Plant Staff Mork Hours," dated Pebruary 1,'980 discusses the concern of overtime work for members of the plant staff who perform safety-related functions. The guidance contained in the XE Circular No. 80-02 was amended by the July 31, 1980 letter. In turn, the overtime guidance of the July 31, 1980 letter 'was revised in Section X.A.1.3 of NUREG-Rev. 31, 7/82 18 1-3 I
SSES-ZS AR 0737. The HRC has issued a policy statemeat which further revises the overtime guida'nce as stated in::NQRBG0737. This guidance is as follows: Enough plant operating personnel should be employed. to maintain adequate shift, coverage without routine heavy use of overtime. The objective is to have operating personnel -work a normal 8-hour day, 40-hour week while the plant is operating. . However,'in the event that unforeseen problems require:substantial amounts of overtime to be used, or during extended periods of shutdown for refueling, malor maintenance or ma)or plant modifications, on. a temporary basis, the following quidelines shall be followed: (a) An individual should not be permitted to work more than 16 hours straight (excluding shift turnover time}. (b) An individual should not be permitted to work more'han 16 hours in any 24-hour period, no more than 24 hours in any 48-hour period, no more than 72 hours in any seven day period (all excluding'hif t turnover time) . (c) A break of at least eight hours should be allowed bewteen work periods (including shift turnover time)-
'L (d) Except during extended shutdown periods, the use of overtime should be considered on an individual basis and not for the entire staff on shift.
Recoqnizinq that very unusual circumstances may arise requixing deviation from the above guidelines, such deviation shall be authorized by the plant manager or his deputy, or higher levels. of management. The paramount consideration'n such authorization shall be that significant reductions in the effectiveness of operating personnel would be highly unlikely. Authorized deviations to the working hour guidelines shall be documented and available for NRC review. In addition, procedures are encouraged that would allow licensed operators at the controls to be periodically relieved and assigned to other duties away from the control board during their tours of duty. Operatinq licen'se applicants shall complete these administrative procedures before fuel loading.
- 18. 1. 3. 2 Integpgefgtj,on Hone required.
Rev. 31, 7/82 18. 1-4
SSES-FS AR
- 18. l. 3. 3 St atemen t of Resnonse The facility staffinq requirements are presented in Subsection =-
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.6.2.2 of the Technical Specifications. These requirements are consistent with those qiven in Table 18.1-1. The plant policy on operations personnel working hours is discussed in administrative procedure AD-QA-300, itConduct of Operations.i' ~ 18 1 4 IMMEDIATE UPGRADING QF REACTOR OPERATOR" AND. SENIOR REACTOR l, 18.1.4.1 Statement of peguigement Applicants~ for senior operator licenses shall have 4 years of responsible power plant experience. Responsible power plant " ,experience should be that obtained as a control room operator (fossil or nuclear) or as a power plant staff engineer involved .in the day-to-day activities of the facility,. commencing with the final year of construction. A maximum of 2 years power, plant experience may be fulfilled by academic or. related technical training,'n a one-for-one time basis. Two years shall be nuclear power plant experience. At least 6 months of the nuclear power'plant experience shall be at the plant for which he seeks a license. Effective date: Applications received on or after May 1~ 1980. Applicants for senior operator licenses shall have held an operator's license for 1 year. Effective Date: Applications received after December 1, 1980. -The NRC has not imposed the 1-year experience requirement on cold applicants for SRO licenses. Cold applicants are to work on a facility not yet in operation; their training programs are designed to supply the equivalent of the experience not available to them. Senior operator+: Applicants shall have 3 months of, shift traininq as an extra man on shift. Control room operator+: Applicants shall have 3 months training on shift as an extra person in the control room. Effective date: Applications". received after Auqust 1, 1980.
+Precritical applicants will be required to meet unique qualifications designed to accommodate the fact that their facility has not yet been in operation.
R ev. 31 ~ 7/82 18 1-5
SS ES-PS AR Train ing programs shall 'be modified, as necessary, to 'provide: Training in heat,tran'sfer, fluid flow and 1i ther mod ynamics. II Training in the use of installed, plant systems to control or mitiqate an accident i'n which thecore is severely damaged.,
- 3) Increased emphasis on reactor and plant transients.".
Effective 'date:,'Present programs have b'een modified .in to Bulletins and Orders. Revised programs 'esponse should be submitted for OLB review..by August 1,.1980. Content of the licensed operator requalification programs shall be modified to include instruction in heat transfer,'luid flow, thermodynamics, and mitiqation of accidents involving a degraded core. Effective date: May 1,. 1980. criteria for requirinq licensed individual to participate 'nThe accelerated a requalification shall be modified to be consistent with the new passing grade for, issuance of a license; 80A overall and 70% each category. Effective date. Concurrent with the next facility administered annual requalification examination after the issue date of this requirement.
~ g Programs should be modified to require the control manipulations listed in Enclosure 4 of HUBEG 0737, item I.A.2.1. Normal control manipulations, such as plant reactor startups, must be performed. Control manipulations during abnormal or emergency'.
operations must be walked through with, and evaluated by, a. member of the training staff at a minimum. An may be used to satisfy the requirements, for -control > appropriate'imulator manipulations. Effective date: Programs modified by August 1, 1980. Renewal applications received, after November 1, 1980 must reflect compliance with 'the program. Certifications completed pursuant to Sections 55.10(a) (6) and 55.33a(4) and (5) of 10 CPR Part 55 shall be; signed by, the highest level of corporate manaqement f or plant opera ti:on (f or example, Vice President for Operations). Effective'dat,e: Applications received on or after Nay 1, 1980. 18.1. 4. 2 Interoretation None required. Rev. 3f, 7/82 18. 1-6
SSES-PS AR 18~C. 1 4.3 Statement of Response A program is established to assure that all reactor operator and senior reactor aperator license candidates {beyond the initial compliment required to startup Units 1 6 2) have the prescribed experience, gualifications, and training. Candidates sill be prepared and certified in accordance pith Nuclear Departaent Instruction NDI-4.2.1. Administrative procedure AD-QA-304, I "Operator Selection Training and Qualifications," details the process which the qualifications of candidates for operations
'y positions vill be evaluated in the future.
The initial startup crews sill have completed extensive training devised in part to recoqnize the non-operational status of the units. This program includes real time training an the Susquehanna SES simulator which duplicates the actual unit and thus in many respects equates to the experience requirements. Subsection 13.1.3 describes the qualifications commitments for the existinq plant staff. //BRINING 18 $ ~ 5 ~ ADgI$ISgRAT~IN gg PROG~RMS /~A ~2. 3 Pending accreditation of train ing institutions, licensees and applicants for operating licenses vill assure that tnaining center and facility instructors who teach systems, integrated responses, transient, and simulator courses demonstrate senior reactor operator (SRO) qualifications and be enrolled in appropriate requalification programs. Training center and facility instructors who teach systems, integrated responses, transient and simulator courses shall demonstrate their competence to NRC by successful completion of a senior operator examination. Effective date: Applications should be submitted no later than August 1, 1980 for individuals who do not already hold a senior operator license. Instructors shall be enrolled in apprapriate regualification programs to assure they are cognizant of current operating history, problems, and changes to procedures and administrative limitations. Effective date: Programs should be initiated Hay 1, 1980. Programs should be submitted to OLB for review by August 1 1980 Rev. 30 ~ 5/82 18. 1-7
SSES-FSAR 18.1.5.2 Interpretation The "instructors" referenced in this requirement are those individuals vho teach systems specific to BMBs, integrated responses, transients, and simulator courses to licensed operators or license candidates. 18.1.5 3 Statement of Response Certification of instructors is described in Nuclear Department Instruction NDI-QA-4.1.3.. This procedure delineates which instructors are required to pass an examination for certification of senior reactor operators (SRO). All instructors who teach materials identified in Subsection 18 1.5.2 are certified as SROs. 18.1 6 REVISE SCOPE AND CRITERIA POR LICENSING EXAMINATIONS gr.A.3 1g 18.1. 6.1 Statement of RgqgiremeRt A new cateqory shall be added to the operator written examination entitled, "Principles of Heat Transfer and Pluid Mechanics.<< A new cateqory shall be added to the senior operator written examination entitled, ~~Theory of Fluids and Thermodynamics.< Time limits shall be imposed for completion of the written examinations:
- l. Operator: 9 hours.
- 2. Senior Operator: 7 hours.
The passing qrade for the written examination shall be 80% overall and 70% in each cateqory. . All applicants for senior operator licenses shall written be reguired to be administered an operating test as veil as the
. examination. Effective date: Examinations administered on or a fter Nay 1, 1980.
Applicants vill grant permission to NRC to inform their facility manaqement reqardinq the results of the examinations for purposes of enrollment in requalif ication programs. Applications received on or after May 1, 1980. Simulator examinations will be included as part of the licensing examinations. Rev. 32, 12/82 18. 1-8
SS ES-FS AR 18.1. 6.2 Xnteroretation None required. 18.1. 6.3 Statement of Response The reactor operator and senior reactor operator training program has been upgraded to include the subject material described in this requirement. Refer to Subsection 18.1.0.3 for the response to requirement I-.A.2.1, ~~Immediate Upgrading of Reactor Operator and Senior Reactor Operator Traininq and Qualifications." Candidates will be prepared and certified in accordance with Nuclear Department Instruction NDI-QA-0.2. l. The Susquehanna SES simulator is available for the simulator'portion of exams. Application packages will include a release which permits the NRC to inform PPSL management of exam results. 18 $ 7 EVALUATION OP ORGANIZATION AND MANAGENENT fI B. 1 2) 18.1. 7.1 Statement of Requirement Each applicant for an operatinq license shall establish an onsite independent safety engineering group (ISEG) to perform independent reviews of plant operations. The principal function of the ISEG is to examine plant operating characteristics, NRC issuances, Licensing Information Service advisories, and other appropriate sources of plant design and operating experience information that may indicate areas for improving plant safety. The ISEG is to perform independent review and audits of plant activities including maintenance, modifications, operational problems, and.operational analysis, and aid in the establishment of programmatic reguirements for plant activities. Where useful improvements can be achieved, is expected that this group vill develop and present detailed it ecommendations to corpox:ate manaqement for such things as revised procedures or equipment modifications. Another function of the ISEG is to maintain surveillance of plant operations and maintenance activities to provide independent verification that these activities are performed correctly and that human errors are reduced as far as practicable. The ISEG will then be in a position to advise utility management on the overall quality and safety of operations. The ISEG need not perform detailed audits of plant operations and shall not be R ev. 31, 7/82 18 1-9
SSES-PS AR responsible for sign-off functions such that it becomes, involved in the operating orqanization. The new ISEG shall not replace the plant operations reviev committee (PORC) and the utility's independent reviev and audit group as specified by current staff guidelines (Standard Reviev Plan, Regulatory Guide 1.33, Standard Technical Specifications) . Rather, it is an additional independent group of. a minimum of five dedicated, f ull-time engineers, located onsite, offsite to a corporate official who'holds a high-level, but'eportinq technically oriented position that is not in the management chain for power production. The ISEG will i.ncrease the ava ilable technical expertise located onsite and vill provide continuing, svstematic, and independent assessment of plant activities. Integrating the shift technical advisors: (STAs') into the ISEG in some vay would be desirable in that contact with and knowledge of it day-to-day could enhance the group's plant operations:and provide additional expertise. However, the STA on shift is necessarily a member of the operating staff and cannot be independent of it. It is, expected that the ISEG may interface vith the quality assurance (QA) orqanization, but preferably 'should not be an integral part of t'e QA organization. functions of the ISEG require daily contact vith the
'he operatinq personnel and continued access to plant -facilities and records. The ISEG review f unctions can, therefore, best be carried out by a qroup physically located onsite. Hovever, for utilities vith multiple sites, it may be possible to perform portions of the independent safety assessment function in a centralized location for all the utility's plants. In such cases, an onsite qroup still is required, but smaller than would be the case if it it may be slightly were performing the entire independent safety assessment function. Such cases will be revieved on a case-by-case basis.
This requirement shall be implemented prior to issuance of an opera tin q lice nse. Refer to Subsection 18.2.6 for .the response to.additional requirements contained in NtJREG 0694. 18.1. 7. 2 Interpretation None required. 18.1.7 3 Statement of Response Hev. 31, 7/82 18. 1- 10
SSES- FS AR The functions of the ISEG will be performed by the Nuclear Safety Assessment Group (NSAG) . PPGL~s commi'tment to the NSAG is addressed in a letter from N. N. Curtis to B. J. Youngblood on December 8, 1980 (PLA-585) and are further addressed in Nuclear Department Instruction NDI-1.1.2. NSAG will be functional by fuel load. 18.1.8 - SHORT-TERM ACCIDENT AND PROCEDURE EEVIEM QI C.l) 18.1. 8.1 Statement of Reguirement Reanalysis of small break LOCAs, transients, accidents, and inadequate core cooling and preparation of guidelines for development of emergency procedures should be completed and submitted to the NRC for review by January 1, 1981. The NRC staff will review the analyses and quidelines and determine their acceptability by July 1, 1981, and will issue guidance to licensees on preparinq- emerqency procedures from the guidelines. Followinq NRC approval of the guidelines, licensees and applicants for operatinq licenses issued prior to January 1, 1982, should revise and implement their emergency procedures at first refuelinq outage after January 1, 1982. Applicants for 'he operating licenses issued after January 1, 1982 should implement the procedures prior to operation. This schedule supersedes the implementation schedule included in NUREG-0578, Recommendation 2.1.9 for item Z. C. 1 (a) 3, Reanalysis of Transients and Accidents. For those licensees and/or owners groups that will have in attaining the January 1 1981 due date for
~ 'ifficulty submittal of quidelines, a comprehensive proqram plan, proposed schedule, and a detailed justification for all delays and problems shall be submitted in lieu of the guidelines.
18.1. 8. 2 Interpretation The BMR Owners'roup quidelines may. be utilized to develop emergency procedures for accidents and transients. 18.1.8.3 Statement of Response In the Clarification of the NURBG-0737 requirement >>for reanalysis of transients and accidents and inadeguate core cooling and preparation of guidelines for development of emerqency procedures," NUREG-0737 states: Rev. 31, 7/82 18 1- 11
SS ES- FS AR Owners'roup or vendor submittals may be referenced as appropriate to support- this reanalysis. If'wners "group or~ vendor submittals have already been forwarded to the'ta'ff for review, a brief description of the submittals and justification of their adequacy to support guideline development is all that is required. I PPSL has participated, and will continue to. participate, in the BMR Owners 'roup program to develop Emergency Procedure Guidelines for General Electric Boiling Mater Reactors. Followinq are a brief description of the submittals -to date, and a justification of their adequacy to support guideline de v elo pm en t. A Description of Submittals (l) NED0-24708A, "Additional Information Required for NRC Staff Generic Report on Boiling Mater Reactors," Revision 1, December 1980. (a} Description and analysis of small break loss-of-coolant events, considering a range of break sizes, location ~ and cond itions,,including equi.pment failures and 'operator errors; description and justification of analysis methods. (b) 'Description and analysis of loss of feedwater events, including cases involving stuck-open relief valves, and including equipment failures and operator errors; description and.justification of an'alysis methods. (c) Description and analysis of each FSAR Chapter 15 event resultinq in a reactor 'system transient; demonstration of applicability 'of analyses to each event; demonstration of applicability of Emergency Procedure'uidelines to each event. (d) Description of natural and forced circulation coolinq; factors influencing natural circulation, including noncondensibles; reestablishment of forced circulation under transient and accident conditions. (e) Description and analysis of loss-of-coolant events, loss of feedwater events, and stuck-open relief valve events, including severe multiple equipment failures and operator errors which not mitiqated, could result in conditions of if inadequate core'cooling. Rev. 31, 7/82 18. 1-12
SS ES-PS AR 4 (f) Description of indications available to the BMR
. operator for the'etection of adequate core coolinq (q) Description and justif icati'on of analysis methods.
for extremely degraded cases. (2) NEDO 24934, >>BMR Emergency Procedure Guidelines BMR 1-6," Revision 1, January 1981. Guidelines for BMR -Emergency Procedures based on identification and response to plant symptoms; including a range of equipment fa'ilures and operator errors; includinq severe multiple equipment failures and operator errors which, if not mitigated, would result in conditions of inadequate core 'cooling;, includinq conditions when core cool'ing status, is uncertain or unknown. B~ Adeauacy of Submittals The submittals described in paragraph A have been discussed and reviewed extensively amonq the BMR Owners'roup, Company, and the NRC staff. =The, NRC staff
- the'eneral'lectric ~
has found (NUHEG-0737, page I.C.1-3) that >>the analysis and guidelines submitted by the General Electric Company (GE) Owners'roup...comply with the requirements (of the 'NUREG- - clarification) ." In Reference 18.1-1, the Director of. '737 the Division of Licensing states, >>we*find the Emergency Procedure Guidelines acceptable for trial implementation (on six plants with applications for operating licenses pendinq) ." PPSL believes that in view of these findings, no further detailed justification of the analyses or guidelines is necessary't this time. Ref erence 1 further sta tes, "during the course of implementation we may identify areas, that require modification or further analysis -and justification.>> The enclosure to Reference 18.1-1 identifies several such areas. PPSL will work with the BM,R Owners~ Group in respondinq to such requests. By our commitment to. work wi;th the. Owners'roup on such requests, on'chedules mutually agreed to by the NRC and the. Owners'roup, and by reference to the BMR owners'roup analyses and guidelines already 'submitted, our response to the NUREG-0737 requirement >>for reanalyses of transients and accidents and inadequate core cooling and prepara'tion of guidelines .for development of emergency procedures>> by January 1, 1981, is complete. 0'ev. 31, 7/82 18.'- 13
SS ES-FS AR Emergency procedures based on those guidelines have been developed and are currently in trial,use on the Susquehanna SES Simulator. These procedures have been reviewed by the NRC. Final versions which incorporated NRC comments .were submitted in a letter from N. M. Curtis to B. J.. Youngblood on Nay 15, 1981 (PLA-791) . .18 l. 9 SHIFT RgLIgF APD TURNOVER PROCEDURES gI. C 2L No requirement stated in NUREG 0737. Refer to Subsection 18.2.8 which contains the response to the requirement in NUREG 0694.
- 18. l. 10 SHIFT SUPFRVISQR RQSPOgSIBILITY g'I C 3}
No requirement stated in NUREG 0737. Refer to Subsection 18.2.9 which contains the response to the requirement in NUREG 0694.
- 18. 1. 11 CONT ROL ROON ACCESS gI C 4)
No requirement stated in NUREG 0737. Refer to Subsection 18. 2. 10 which contains'the response to the requirement in NUREG 0694. 18.1. 12 FEEDBACK OF OPERATING EXPER'IENCE (I C.5) lR. l. 12. 1 Statement of Requirement Applicants for an operatinq license shall prepare procedures to assure that information pertinent to plant safety originating inside or outside the utility organization is continually supplied to operators and other personnel and is incorporated into training and retraining programs. These procedures, shall: (1) Clearly identify organizational responsibilities for review'of operating experience, the feedback of pertinent information to operators and other personnel, and the incorporation of such information into training and retraining programs; {2) Identify the administrative and technical review steps necessary in translatinq recommendations by 'the operatinq experience assessment group into plant actions (e. q., chanqes to procedures, operating orders); Rev. 31, 7/82 18 1- 14
S S ES- PS AR (3) Identify the recipients of various'ategories of information from operating experience (i.e., supervisory personnel, shift technical advisors, operators, 'aintenance personnel, health physics technicians) or otherwise provide means throuqh which such information can be readily related to the gob functions of the recipients; (4) Provide means to assure that affected personnel become aware of and understand information of su.fficient importance that should .not wait for emphasis throuqh routine traininq and retraining programs; (5) Assure that plant personnel do not routinely receive extraneous and unimportant information on operating experience in such volume that it would obscure priority information or otherwise detract from overall gob performance and proficiency; (6) Provide suitable checks to assure that conflicting or contradictory information is not conveyed to operators and other personnel until resolution is reached; and, (7) Provide periodic'nternal audit to assure that the .. feedback program functions effectively at all levels. This requirement shall be implemented prior to issuance of an operatinq license.
- 18. l. 12. 2 Interpretation Hone required.
18.1.12. 3 Statement of Response PPGL has developed a comprehensive proqram for feedback of operatinq experience. Components of the program are as follows.. Operatinq experience from other utilities and other industry sources is initially reviewed and dispositioned by the Industry Events Review Program (IERP). The XERP is designed to assure plant personnel do not routinely receive extraneous and unimportant information, that information is not contradictory or conf lictinq, that information is resolved prior to dissemination and that important information is rapidly routed to the appropriate personnel. A description of the organization, responsibilities and proced,ures of the IERP can be found in Nuclear Department Instruction NDI- QA-6. 2. 2. Rev. 31, 7/82 18 1-15
SS ES- FS AR The Shift Technical Adviser (STA) as part of the Operations Assessment Function will be the focal point for dissemination of operating experience information to appropriate plant personnel. This vill include: o Feedback of pertinent information to operators and other station personnel and transmittal of information to the Nuclear Traininq Group for incorporation into appropriate training programs. o Initiatinq, when required, plant procedure changes and/or plant modification requests. o Discussinq with shitt personnel operating experience information of sufficient importance that def erred to the retraining program. it cannot be o Editinq information provided to plant personnel to minimize excessive or conflicting information and distributing information to appropria te functional units. Administrative Procedure AD-QA-406 is being developed to further define this function and the interfaces among the STAs and the Nuclear Safety Assessment Group, Nucl'ear Training, Operations and the Industry Events Review Program. General information from the nuclear industry and, information of general interest from inside the company will be disseminated to appropriate personnel. The details of this proqram are described in rnclear Department znstrncticn NDX-ga-6.2.1. The NQA organization will audit selected portions of the feedback program to assure it functions effectively at all levels. 18 '1 13 VERIFY CORRECT PERFORMANCE OF OPERATING ACTIVITIES (I. C 6) 18.1.13.1 Statemegg of geguiggment Licensees~ procedures shall be reviewed and revised ~ as necessary, to assure that an effective system "of verifyinq the correct performance of operatinq activities is provided as a means of reducinq.human errors and improvinq the quality of normal operations. This will reduce the frequency of occurrence Rev. 31, 7/82 18. 1-16
SSES-PSAR of situations that could result in or contribute to accidents. Such a verification system may include automatic system status monitorinq, human verification of operations and maintenance activities independent of the people performing the activity (see NUREG-0585, Recommendation 5), or both. Implementation of automatic status monitoring if required. will reduce the extent of. human verification of operations and
~
maintenance activities but vill not eliminate the need for such verification in all instances. The procedures adopted by the licensees may consist of two phases one before and one after installation of automatic status"monitoring equipment, if required, in accordance with item I.D. 3. Procedure's .must be reviewed and revised 'prior to fuel load.'8.1.13.2 Interpretation Nonerequired. 18.1. 13.3 Statement of Response Administrative procedure AD-QA-306, "System Status and Equipment Control,~'ill provide the means to verify correct performance of surveillance and maintenance activities. Status ve rif ication will utilize control room indications, presently available, operability testing where appropriate, or independent verification by a second qualified person. The, procedure defines circumstances when independent human verification is required. The procedure also incorporates the requirements of item II.K.1.10 (see Subsection 18.2.26) for the removal from and restoration to service of safety related systems and components during normal operations,and maintenance activities. 18 1 14 NSSS VENDOR REVIEW Og P ROCBDURES QI C 7)" No requirement stated in NUREG 0737. Refer to Subsection 18. 2.12 which contains the response to the requirement in NUREG 0694. 18.1 15 PILOT MONITORING. OF SELECTED EMERGENCY PROCEDURES FOR NEAR TERM OPERATING LICENSES gI C 8) No requirement stated in NUREG 0737. Refer to Subsection 18. 2.13 which contains the response to the requirement in NUREG 0694. Rev. 27, 10/81 18 1-17
SS ES-FS AR
- 18. 1 16 CONT'ROL RQOH DESI GN REVIEW ~ID. 1)
- 18. 1. 16. 1 Statement of Requirement All licensees and applicants for opexating licenses vill be required to conduct a detailed contro1-room design reviev to identify and correct design deficiencies. This detailed control-room design reviev is expected to take about a yeax. Therefore, the Office of Nuclear Reactor Regulation {NRR) requires that those applicants for operating licenses vho are unable to complete this reviev prior to issuance of a license make preliminary assessments of their control rooms to identify siqnificant human factors and instrumentation problems and establish a sched,ule (to be approved by NRC) for correcting deficiencies. These applicants vill be required to complete the more detailed control room reviews on the same schedule as licensees vith opexating plants.
Applicants vill find it of value to refer to the draft document NUREG/CR-1580, "Human Engineering Guide to Control Room Evaluation," in performing the preliminary assessment. NBB'ill evaluate the applicants preliminary assessments including the performance by NRB of onsite review/audit. The NRR onsite reviev/audit will be on a schedule consistent with licensing needs. I This requirement shall be met prior to fuel load. 18.1. 16. 2 Interpretation Applicants for operating licenses are required to perform a preliminaxy control room design assessment vhich should be based assessment will be revieved by vill subsequentlyThisrecommend on NUREG/CR-1580. the NRC, vho changes for correcting deficiences. Applicants must submit for NRC approval a schedule for correcting these deficiencies. Applicants will be xequired to perform a detailed control room design assessment following NUREG 0700 issuance. is not xequired to be completed prior to issuance This assessment of an operating license. 18.1.16 3 Statgmept of Response A detailed control room review to identify significant human factors problems was conducted by PPSL with assistance from Rev. 27, 10/81 18.1-18
SSES-FS AR experienced human factors personnel from General Physics Corporation. This review was based on the criteria given in draft N 0 REG/CR-1580. During the week of October 27, 1980, the NRC performed an onsite review of the Susquehanna control room. The results of th- ". review were formally transmitted to PPSL on January 31, 198'- A meeting was held on February 3, 1981 in Bethesda to discuss and clarify the NRC findings. On February 27, 1981 PPSL submitted a formal response to all NRC findings (refer to PLA-648). This response included a schedule for implementing the findings-addressed in the NRC report. 18.1.17 PLANT SAFETY PARAMETER DISPLAY SYSTEM JI.D.2$ 18.1. 17. 1 Statement of Qeguirement Each applicant and licensee shall install a safety parameter display system (SPDS) that will display to operating personnel a minimum set of parameters which define the safety status of the plant This can be attained through continuous indication of direct and derived variables as necessary to assess plant safety status. The operational date for the SPDS is October 1, 1982. 18.1. 17. l. 1 Function The purpose of the safety parameter display system (SPDS) is to assist control room personnel in evaluating the safety status of the plant. The SPDS is to provide a continuous indication of plant parameters or derived variables representative of the safety status of the plant. The primary function of the SPDS is to aid the operator in the rapid detection of abnormal operating conditions. The functional criteria for the SPD'S presented in this section are applicable for use only in the control room. Xt is recognized that, upon the detection of an abnormal plant status, it may be desirable to provide additional information to analyze and diagnose the cause of the abnormality, execute corrective actions, and monitor plant response as secondary SPDS functions. As an operator aid, the SPDS serves to concentrate a minimum set of plant parameters from which the plant safety status can be assessed. The grouping of parameters is based on the function of enhancinq,the operator's capability to assess plant status in a Rev. 27, 10/81 18 1-19
SS BS-PS AR timely manner without surveying the entire control room. However, the assessment based on SPDS is likely to be followed by confirmatory surveys of many non-SPDS control room indicators. Human-factors engineering shall be incorporated in the various aspects of the SPDS design to enhance the functional effectiveness of control room personnel. The design of the primary or principal display format shall be as simple as possible, consistent with the reguired function, and shall include pattern and coding techniques to assist the operator's memory recall for the detection and recognition of unsafe operatinq conditions. The human-factored concentration of these signals shall aid the operator in functionally comparing signals in the assessment of safety status. All data for display shall be validated where practicable on a realtime basis as part of the display to control room personnel. For example, redundant sensor data may be compared, the range of a parameter may be compared to predetermined limits, or other quantitative methods may be used to compare values. Mhen an unsuccessful validation of data occurs, the SPDS shall contain means of identifying the impacted parameter(s) . Operating procedures and operator traininq in the use of the SPDS shall contain information and provide guidance for the resolution of unsuccessful data validation. The ob jective is to ensure that the SPDS presents the most current and accurate status of the plant possible and is not compromised by unidentified faulty processinq or failed sensors. The SPDS shall be in operation during normal and abnormal operatinq conditions. The SPDS shall be capable of displaying pertinent information during steady-state and transient conditions. The SPDS shall be capable of presenting the magnitudes and the trends of parameters or derived variables as necessary to allow rapid assessment of the current plant status by control room personnel. The parameter trendinq display shall contain recent and current magnitudes of the parameter as a function of time. The derivation and presentation of parameter trending during upset conditions is a task that may be automated, thus freeing the operator to interpret the trends rather than generate them. Display of time derivatives of the parameters in lieu of trends to both optimize operator-process communication and conserve space may be acceptable. The SPDS may be a source of information to other systems, and the functional criteria of these systems shall state the required interfaces with the SPDS. Any interface between the SPDS and a safety system shall be isolated in accordance with the safety system criteria to preserve channel independence and ensure the integrity of the safety system in the case of SPDS malfunction. Rev. 27, 10/81 1 8.1-20
Design provisions shall be included in the interfaces between the SPDS and nonsafety systems to ensure the integrity of the SPDS upon failure of nonsafety equipment. A qualification program shall be established to demonstrate SPDS conformance to the functional criteria of this document. 18 1. 17. 1~ I,ocation The SPDS shall be located in the control room with additional SPDS displays provided in the TSC and the EOP. The SPDS may be physically separated from the normal control boards; however, it shall be readily accessible and visible to the shift supervisor, control room senior reactor operator, shift technical advisor, and at least one reactor operator from the normal operating area. If .the SPDS is part of the control board, recognizable and readable. it shall be easily 18.1.17 1.3 Size The SPDS shall be of such size as to be compatible with the existing space in the control area. The SPDS display shall be readable from the emergency operating station of the control room senior reactor operator. It shall not interfere with normal movement or with full visual access to other control room operating systems and displays.
- 18. 1. 17. l. 4 S ta ffinq The SPDS shall be of such design that no operating personnel in addition to the normal control room operating staff are required for its operation.
18.1.17 1.5 Display Considerations The display shall be responsive to transient and accident seguences and shall be sufficient to indicate the status of the plant. Por each mode of plant operation, a single primary display format designed according to acceptable human-factors principles (a limited number of parameters or derived variables and their trends in an organized display that can be readily interpreted by an operator) shall be displayed, from which plant safety status can be inferred. It is recognized that it may be desirable to have the capability to recall additional data on secondary formats or displays. Rev. 27, 10/81
SS ES-FS AR The primary display may be individual plant parameters or may be composed of a number of parameters or derived variables giving an overall system status. The basis for the selection of the minimum set of parameters in the primary display shall be documented as part of the design. The important plant functions related to the primary display while the plant is qenerating power shall include, but not be limited to: 0 Reactivity control 0 Reactor core cooling and heat removal from primary system 0 Reactor coolant system integrity 0 Radioactivity control 0 'Containment integrity The SPDS may consist of several display formats as appropriate to monitor and present the vari.ous parameters or derived variables. For each plant. operating mode, these formats may either be automatically displayed or manually selected, by the operator to Keep control room operating personnel informed. Flexibility to allow for interaction by the operator is desirable in the display designs. Also, where feasible, the SPDS should include some audible notification to alert personnel of an unsafe operating condition. The SPDS need not be limited to the previously stated functions. It may include other functions that aid operating personnel in evaluating plant status. It is desirable that the SPDS be sufficiently flexible to allow for future incorporation of advanced diagnostic concepts and evaluation techniques and systems. I 18 l. 17. l. 6 Design
- Crit eria The total SPDS need not be Class 1E or meet the single-failure criterion. The sensors and signal conditioners (such as preamplifiers, isolation devices, etc.) shall be desighed and qualified to meet Class 1E standards for those SPDS parameters that are also used by safety systems. Furthermore, sensors and signal conditioners for those parameters of the SPDS identical to the parameters specified within Regulatory Guide 1.97 shall be designed and qualified to the criteria stated in Regulatory Guide 1.97. For SPDS applications it is also acceptable to have Class 1E qualified devices from the sensor to a post-accident-accessible location, such as outside containment, and then non-1E devices from containment to the display (or processor) on the presumption that these components can be repaired or replaced in an accident environment. The processing and display devices of the SPDS shall be of proven high quality and reliability.
Rev. 27, 10/81 18-1-22
SSES-FSAR The function of the SPDS is to aid the operator in the interpretation of transients and accidents. This function shall be provided during and following all events expected to occur during the life of the plant, including earthquakes. To achieve this function, the display system shall not only take adequate account of human factors the,man-machine interface but shall also be sufficiently durable to function during and after earthquakes. Because of current technology, it may not be possible to satisfy these criteria within one SPDS system. From an operational viewpoint, it is preferred that only one display system be used for evaluating the safety status of the plant. One display system simplifies the man-machine interface and thus minimizes operator errors. However, in recognition of the restraints imposed by current technology, an alternative is to design the overall SPDS function with a primary and backup display system: (1) the primary SPDS display would have high performance and flexibility and be human factored but need not be seismically qualified; and (2) the backup display system would be operable during and following earthquakes, such as the normal control room displays needed to comply with Regulatory Guide 1.97. The display system (or systems) provided for the SPDS function shall be capable of functioning during and following all design basis events for the plant. In all cases, both the primary SPDS display and the backup SPDS seismically qualified portion of the display shall be sufficiently human factored in its design to allow the control room operations staff to perform the safety status design to allow the control room operations staff to perform the safety status assessment task in a timely manner. Dependence on poorly human-engineered Class 1E seismically qualified instruments that are scattered over the control board, rather than concentrated for rapid safety status assessment, is not acceptable for this function. An acceptable approach would be to concentrate the seismically qualified display into one segment of the control board. The dynamic loading limitations of the SPDS design shall be defined and incorporated into the training program. The control room operations staff shall be provided with sufficient
,information and criteria to allow for performance of an operability evaluation of SPDS is an earthquake should occur.
The SPDS as used in the control room shall be designed to an operational unavailability goal of 0.01, as defined in Section 1.5 of NUREG 0696. The cold shutdown unavailability goal for the SPDS during the cold shutdown and refueling modes for the reactor shall be 0.2, as defined in Section 1.5 of NUREG 0696. Technical specifications shall be established to be consistent with the unavailability design goal of the SPDS and with the Rev. 27, 10/81 18.1-23
SS ES- PS AR compensatory measures provided during periods when the SPDS is inoperable. Operation of the plant with the SPDS out of service is alloved provided that the control board is sufficiently human factored to allow the operations staff to perform the 'safety status assessment task in a timely manner. Dependence on poorly human-engineered instruments that are scattered over 'the control board rather than concentrated for rapid safety status assessment is not acceptable for this function. The operational date for the SPDS is October 1, 1982. 18,1. 17. 2 - In terpreta tion None required.
- 18. 1.17. 3 Statement of Response The proposed method of responding to this requirement vas submitted by a letter to B. J. Youngblood from N. M. Curtis'n April 2, 1981 (PLA-700). Details on the SPDS are presented in Appendix I of the Emergency Plan.
18 1. 18 TRAINING DURING LOW-POWER TESTING gI. G 1} i No requirement stated in NUREG 0737. Refer to Subsection 18. 2.15 vhich contains the response to the requirement in NUREG 0690. 18 1 19 REACTOR COOLANT SYSTEM VENTS (II B ll 18,1.19.1 Statement of Reguigement Each applicant and licensee shall install reactor coolant system (RCS) and reactor pressure vessel (RPV) head high point vents remotely operated from the control room. Although the purpose of the system is to vent noncondensible gases from the RCS vhich may inhibit core coolinq during natural circulation, the vents must not lead to an unacceptable increase in the probability of a loss-of-coolant accident (LOCA) or a challenge to containment integrity. Since these vents form a part of the reactor coolant pressure boundary, the design of the events shall conform to the requirements of Appendix A to 10 CPR Part 50 'General Design Criteria." The vent system shall be designed with sufficient redundancy that assures a lov probability of inadvertent or irreversible actuation. Rev. 27, 10/Sl 1 8.1-24
SS ES-PS AR Each licensee shall provide the following information concerning the design and operation of the high point vent system: (1) Submit a description of the design, location, size, and power supply for the vent system along with results of analyses for loss-of-coolant accidents initiated by a break in the vent pipe. The results of the analyses should demonstrate compliance with the acceptance criteria of 10 CPR 50.46. (2) Submit procedures and supporting analysis for operator use of the vents that also include the information available to the operator for initiating or terminating vent usage. Documentation, shall be submitted by July 1, 1981. modifications shall be completed by July, 1982. V Ik 18.1.19. 2 Internretation 2 None required. 18.1. 19. 3 Statement Of Response The present design of reactor coolant and reactor vessel vent systems meet these requirements. The RPV is eguipped with various means to vent the reactor during all modes of operation. All the valves involved are safety qrade, powered by essential busses and are capable of remote manual operation from the control room. The largest portion of non-condensables are vented through sixteen (16) safety relief valves (PSV 141F013A-S) mounted on the main steam lines. These power operated relief valves satisfy the intent of the NRC position. Information regarding the design, qualification, power source of these valves has been provided in Sections 5.1, 5.2.2, 6.2, 6.3, 7. 3 and 15. In addition to power operated relief valves, the RPV is equipped with various other means of high point venting. These are: Normally closed RPV head vent valves (HV141-F001 and F002) ~ operable from control room which discharges to drywell equipment drain tank., {Subsection 5.1 and Figure 5.1-3a) . Rev. 27, 10/Sl 18-1-25
SS ES- PS AR
- 2. Normally open reactor head vent line 2 DBA-112 which
.discharges to main steam line "A". (Subsection 5.1 and Piqure 5.1-3a) .
3 Hain steam driven RCIC and HPCE system turbines, operable from the control room which exhaust to suppression pool. (Subsections 5.3 and 6.3 and Figures 5.4-9a and 6.3-la). Although the power operated relief valves fully satisfy the intent of the NRC requirement these other means also provide protection against accumulation of non-condensables in the RPV. The design of the RCS and RPV vent systems is in agreement with the qeneric capabilities proposed by the BMR Owners'roup, with the exception of- isolation condensers Susquehanna SES is not equipped with isolation condensers. The BMH Owners'roup position is summarized in NED0-24782. Operation of the equipment described above during abnormal operatinq conditions is controlled by the Emergency Operating Procedures. While these procedures do not specifically address ventinq of non-condensable qases, they do address proper utilization of equipment to recover from undesirable conditions presented by the presence of non-condensables or by other circumstances. The RCS and HPV vent systems are part of the original SSES design basis. A pipe break in either of these systems would be the same as a small mainsteam line bre'ak. A complete mainsteam line break is within the design basis (see Subsections 6.2.1.1.3.3.2 and 6.3.3). Smaller size breaks have been shown to be of lesser severity (see Subsections 6.2.1;1.3.3.5 and '6.3.3.7.3) . Therefore, no new supporting analysis is necessary in response to NUREG 0737. In addition, no new 10CPR50.46 conformance calculations or containment combustible gas concentration calculations are necessary. Non-condensable gas releases due to a vent, line break would be no more severe than the releases associated with a mainsteam line break. Hainsteam line break analyses included continuous venting of non-condensable gases with high hydrogen concentrations. These analyses demonstrate conformance to 10CFH50.46. 18.1. 20 Plan t Shielding QZI. B. 2g 18.1.20 1 Statement of geguirement With the assumption of a postaccident release of radioactivity equivalent to that described in Regulatory Guides 1.3 and 1.4 Rev. 27, 10/81 18 1-26
SSES-FS AH (i.e. ~ t he equivalent of 50 A o f the core radioiodine, 100% of the core noble qas inventory, and 1% of the core solids are contained in the primary coolant), each licensee shall perform a radiation and shielding-desiqn review of the spaces around systems that may, as a result of an accident, contain highly radioactive materials. The design review should identify the location of vital areas and equipment, such as the control room, radwaste control stations emergency power supplies, motor control centers, and instrument areas, in which personnel occupancy may be unduly limited or safety equipment may be unduly degraded by the radiation fields during postaccident operations of these sy stems. Each licensee shall provide for adeguate access to vital areas and protection of safety equipment by design changes, increased permanent or temporary shielding, or postaccident procedural controls. The design review shall determine which types of corrective actions are needed for vital areas thoruqhout the facility. 18.1. 20. l. 1 Documentation Reguiged for Vital Area Access For vital area access, operating license applicants need to orovide a summary of the shielding design review, a description of the review results, and a description of the modifications made or to be made to implement the result of the review'. Also to be provided by the licensee: (1) Source terms used including time after, shutdown that was assumed for source terms in systems. (2) Systems assumed to contain high levels of activity in a post-accident, situation and jusitification for excluding any of those given in the "Clarification" of NUREG 0737. (3) Areas assumed vital for post-accident operations including justification for exclusion of any of those given'n the
<<Clarification<<of NUHEG 0737.
(0) Projected doses to individuals for necessary occupancy times in vital areas and a dose rate map for potentially occupied a reas. 18-1 20.1 2 Documentation Required for gguipment Qualification Item II.B.2 states, <<Provide the information reguested by the Commission Memorandum and Order on equipment qualification (CLI-80-21) ." This memorandum, with regard to equipment qualification, requests infor-Rev. 27, 10/81 18 1-27
SS ES-FS AR nation on environmental qualification of safety related electrical equip me nt. 18.1. 20 2 Interpretation
- 18. l. 20. 2. 1 Source Terms The source term for recirculated, depressurized coolant need not be assumed to contain noble qases, therefore the RHR shutdown cooling system which may iriitiate at low reactor pressure only will be assumed to contain solely halogens and particulates. The HPCI and .LPCI systems do not recirculate reactor coolant but, rather, suppression pool water. They will also be essentially void of noble gases.
Leakage from systems outside of containment need not be considered as potential sources. Also, containment and equipment leakage (from systems outside containment) need not be considered as potential airborne sources within the reactor building. .follows that airborne sources and any other uncontained sources It in the reactor building do not need be considered in this shieldinq review. 18 l. 20. 2. 2 Post-Accident Systems The standby gas treatment system, or equiva'lent, is given as a system which may contain hiqh levels of radioactivity after an accident. Airborne activity from leakage of equipment outside containment has been clearly established as being outside the review requirements. Drywell leakage must activity processed by the SGTS. This reviewthen provide the will assume the drywell does indeed leak to the reactor building to provide a source within the SGTS. However, this airborne source will not be evaluated any further in the review. 18.1. 20. 2.3 Equipment @uglification Provide a description of the environmental qualification Program and results for safety related electrical equipment both inside and outside of containment. It is our understanding that radiation qualification of non-electrical safety related equipment need not be reported. Rev. 27, 10/81 1 8.1-28
SS ES- PS AR 18,1.20 3 Statement of ge~s onse The required post-accident study is divided into tvo parts; one dealinq with a summary of the shielding design review plus vital area access, another dealinq vith equipment qualification. A summary of the shieldinq design review, results, and methodology used to determine radiation doses is presented below. The results of the eguipment qualification program axe scheduled to .be submitted separately, and in compliance with commission memorandum and order CLI-80-21. The results of the shielding review of contained sources are that all vital areas are accessible post-accident and no shielding modifications are necessary to comply to NUHEG 0737.
- 18. 1. 20. 3. 1 Introduction If an accident are released is postulated. in vhich large amounts of activity from the reactor core, then pathways exist which can transfer this activity to various areas of the reactor building.
These large radiation source terms present a hazard regarding potentially high doses to personnel. In order to deal vith this pxoblem it has become necessar y to quantify these source terms, trace their 'presence and determine their ef fects on the ef f icient performance of post-accident xecovery operations. To this end, the plant shielding of Units 1 and 2 has been reviewed for post-accident adequacy. This summary presents the analytical bases by vhich the review vas carried out. Systems required or postulated to process primary reactor coolant outside the containment during post-accident conditions were selected for evaluation. Large radiation sources beyond the original selected systems. Radiation levels in adjacent plant areas due to contained sources in piping and equipment of these systems were then estimated to yield the desired information. Also included herein is a discussion of radiation exposure guidelines for p.lant personnel, identification of areas vital to- post-accident operations and availability of access to these areas. As a byproduct of this review, several radiation zone maps and associated curves have been produced. The maps will allov operations personnel to identify potential high exposure vital areas of the plant should an accident occur which contaminates the system considered in this study. The curves vill allow them to estimate radiation levels in the'se areas at various times follovinq an accident. Rev. 27, 10/81 18-1-29
SSES-FS AB 18.1.20.3 2 - Desicrn Reviev Bases 18.1. 20. 3.g. 1 Systems Selected for Shielding Review A reviev vas made to determine which systems could be reguired to operate and/or be expected to contain highly radioactive materials followinq a postulated accident where substantial core damage has occurred. The documentation governing the approach to the shielding review is NUREG-0737. A reviev of containment isolation provisions vas conducted in accordance with item II.E.4.2. This vas done to assure isolation of non-essential systems penetrating the containment boundary. Thus, systems other than those identified as having a specified function following an accident are assumed not to contain post-accident activity and do not need to be considered in the shielding reviev. 18 l. 20.3.2 1.1 Cope SRgay~HPC~I RCIC and BHR ~LPCI mode/ I The Core Spray, RHR (LPCI mode), HPCI {water side) and RCIC {water side) systems would contain suppression pool vater being injected into the reactor coolant system. Although the HPCI and RCIC systems could also drav from the condensate storage tank, suppression pool vater is assumed to be their only source of vater for injection. The steam sides of the HPCI and RCIC systems would operate on reactor steam and would not be required when the reactor is depressurized. Hovever, as a first estimate for equipment qualifications it is assumed that these systems should also be available until one year post-accident. 18.1. 20. 3.2. l. 2 RHB /Shutdown Cooling Node) The RHR system recirculates reactor waste heat when it'perates in the shutdown coolinq mode. Operation in this mode reguires that the reactor be in depressurized condition. Depressurization is expected to remove substan tially all of the noble gases released into the reactor coolant whether it be by direct venting to the drywell or by quenching reactor steam in the suppression pool. Another consideration is, following a postulated serious accident, the HPCI, RCIC, R HR (LPCI Node) and/or Core S pray systems vould inject a substantial amount of water into the reactor coolant system. This shielding review vill assume that there are no noble gases in the reactor vater in the RHR system from the shutdovn coolinq mode. However, since the exact amount Rev. 27, 10/81 1 8.1-30
SSZS-PSAR of dilution. of the reactor water is difficult to determine, no dilution in addition to the reactor coolant volume is assumed. 18.1 20.3 2 1 3 RHQ /Suppression Pool Cooling Mode} . The RHB system in this mode circulates and removes heat from suppression pool water to prevent pool boiling. This assures availability of suppression pool water as a source for cooling the reactor and increases the efficiency of a given cooling operation with this source. 18 1 20. 3.2 1 4 RHR /Containment S~ra~Mod~e Under post-accident conditions, water pumped from the suppression pool through the RHR heat exchanger may be diverted to spray header system loops located high in the drywell and above the suppression pool. This mode of operation provides the ability to reduce containment pressure by condensing atmospheric steam while cooling the suppression pool water. No credit is taken for spray removal of iodines.
- 18. 1 20. 3. 2. 1. 5 CRD Hydraulic System The operation of the CRD system was reviewed to determine scram discharge if headers will contain highly radioactive water the followinq a postulated accident. Prior to a scram the CRD housinqs contain condensate water delivered by the CRD pumps."
When a scram occurs some of this condensate water from the CRD system is discharged to the scram discharge header. After the scram, some condensate and reactor water flows to the scram discharge header which fills in a matter of a few seconds. Since the vents and drains in the scram discharge headers are isolated by the scram, all discharge flow then stops. Since is not reasonable to assume that significant core damage occurs it in the first few seconds following a scram, the scram discharge header will initially contain only a mixture of condensate and pre-accident r'eactor water following this postulated accident. After the reactor scram, the scram discharge and instrument volumes vill contain about 700 gallons of pre-accident water, isolated by a single drain .valve leak tested to 20 cc/hr. If the initial scram closed the drain valve, then this leakage is insiqnificant compared to the scram discharge volume and insignificant as a post-accident concern. If the drain valve fails to close, operator action is required to reset the scram and close the soft-seated scram discharge valve. If this action Rev. 27, 10/81 18 1-31
SSES-PS AR is not taken or fails to close the valve, then post-accident sources can enter the liquid radwaste system by leaking past the CRD seals. The CRD withdraw line does not directly communicate with the reactor coolant. In liqht of the anticipated small leak rates and the lack of single failure criteria consideration requirements, the scram discharqe drain valve was assumed to remain closed and any leakaqe was disregarded. 18 1.20.3 2.1 6 RQCU System For a ma)or accident with resulting core damage, the RICO system would automatically isolate on a low reactor coolant level signal and would contain no hiqhly radioactive materials beyond the second isolation valve. Since the cleaning capacity for this system is small, it it accident recovery and would be impractical to use it for THE type is excluded from this shielding review. 18.1.20 3.2.1.7 L~iui~dad waste System Equipment drains and compartment floor drains servicing ECCS systems are isolated from the reactor building sump.. All piping that may contain high activity post-accident water is also isolated from the reactor buildinq sump and radwaste systems CRD system isolation is discussed in Subsection 18.1. 20.3.2.1.5 Since no significant amounts of post-accident activity can reach the liquid radwaste system, it is excluded from this shielding revie w. 18.1.20.3.2.1 8 MSXV Teakage Control System. Subseguent to a postulated accident, system operation may begin upon actuation of the manual switches in the control room. This system may only be activated upon a permissive reactor pressure signal (35 psiq) . The method used to depressurize the reactor to this level has a larqe effect on the amount of activity potentially available for passaqe through this system., For example, the HPCX system can deplete the reactor steam activity considerably with only a few minute's operation. Whichever depressurization method is chosen,.the NSIV-I,CS system remains as one that must be included in the shielding review. Rev. 27, 10/81 18 1-32
SS ES- PS AR 18.1. 20. 3 2. 1 9 Saaplincn-Systems. Sampling systems required or desired for post-accident use include the Containment Atmosphere Monitoring System, the Plant Vent Sampling System and the Post-Accident Sampling System. Each of these systems/stations may contain post-accident sources and is included in the shieldinq review. 18.1. 20. 3.2. 1. 10 Standbv Gas. Treatment System The Reactor Building Recirculation system is used after an accident. This disperses airborne activity throughout the reactor building and refueling floor. The SGTS system collects airborne activity, concentrating ha logens within the charcoal filters while releasing noble gases outside the secondary containment The charcoal filter is considered to be a source of contained activity and is included in this shielding review. The assumptions used in determining this contained source are:
- 1) Drywell leakage at 1% per day.
- 2) SGTS process rate of 1 reactor building/refueling floor volume per day.
- 3) 99% charcoal filter efficiency for halogens. 0% charcoal filter efficiency for noble gases.
g8 1.20.3.2 1.11 Containment Atmosphere $ 0rgwellg f The free volume of the primary containment is assumed to initially contain larqe amounts of post-accident activity, namely l00% of the core noble gases and 25% of the core halogens. Shine through the drywell wall was examined to determine the effects on reactor building radiation levels. Results indicate the six foot thick drywell shield wall reduces shine to radiation 'Zone I levels. Shine through penetrations presents no additional hazard because piping is directed to penetration rooms where area lose rates will be dominated by internal piping.
- 18. 1. 20. 3. 2. l. 12 Supgresgion Pool QQetwell)
The suppression pool is assumed to initially contain 50% of the core haloqens and 1% of the core particulates post-accident. Shine through the wetwell wall was examined to determine the effects on radiation levels in the reactor building. It was Rev. 27, 10I81 18 1-33
SSES-FS AR determined that the six foot thick vetvall shield wall reduces wetvell shine to radiation Zone I levels in the reactor building. 18,1,20 3,2,2 Radioactive Source Release Fractions The followinq release fractions vere used, as a basis for detezmininq the concentrations for the shielding reviev: Source A: Containment Atmosphere: 100% noble gases ~ 25% halogens Source 8: Reactor Liquids: 100'%oble gases, 50% halogens, l% solids Source C: Suppression Pool Liguid: 50% halogens, 1% solids Source D: Reactor Steam: 100% noble gases, 25% ha loge ns The above release fractions were applied to the total curies available for the particular chemical species (i.e., noble gas, halogen, or solid) for an equilibrium fission product inventory for Susquehanna as listed in Table 18.1-2. The Regulatory Guide 1.7 solids release fraction of 1% vas used for Cs and Rb on this review. Further evaluations of the THI radioactivity releases may conclude that higher release fractions are appropriate. However, until the release mechanisms and release fractions have been quantified, the existing regulatory guidance will be followed. No noble qases vere included in the suppression pool liquid (Source C) because Regulatory Guide 1.7 has also set this precedent in modeling liquids in the pool (See References 18.1-0 and 18.1-10) . Furthermore, cursory analyses have indicated that the halogens dominate all shielding requirements and that contributions to the total dose rates from noble qases are negliqible for the purposes of shielding design review. 18.1.20. 3.2.3 Source Term guantification Subsection 18.1.20.3. 2.2 above outlines the assumptions used for release fractions for the shielding design review. These release fractions are, however, only the first step in modeling the source terms for the activity concentrations in the systems under review. The important modeling parameters, decay time and dilution volume obviously also affect any shielding analysis. The folloving sections outline the rationale for the selection of values for these key parameters. Rev. 27, 10/81 18.1-34
SSES-PSAR 2.3.1
'8.1.
20 3 ~ Decay-Time For the first stage of the shielding design review process, minimal decay time credit was used with the above releases.. The primary reason for this was to develop a set of accident radiation zone maps normalized. to 1 hour decay. 18.1.20. 3 2.3.2 ~ Dilution Volume The volume used for dilution is important, affecting the calculations of dose rate in a linear fashion. The following dilution volumes were used with the release fractions and decay times listed above to arrive at the final source terms for the shielding review: Source A: Drywell and suppression pool free volumes. Source B: Reactor coolant system normal liguid volume (based on reactor coolant density at the operating temperature and pressure) . Source C: The volume of the reactor coolant system plus the suppression pool volume. Source D: The reactor steam volume. 18~1. 20 3.2.4 SgstemgSou~ce Summygg 0 Core Spray. System: Source C 0 High Pressure Coolant Injection System Liquid: Source C Steam: Source D (with credit for steam specific activity reduction due to turbine opera ti'on) 0 Reactor Core Isolation Cooling System Liguid Source C Steam: Source D (with credit for steam specific activity reduction due to turbine operation). Residual Heat. Removal 'System LPCX 'Mode. Source C Rev. 27, 10/81 18-1-35
SS ES-ZS AR shutdown coolinu Mode: source B (with credit for noble gas release during vessel depressurization) ., ~ Suppression Pool Cooling and Containment Spray Modes: Source C 0 Main Steam Isolation Valve-Leakage Control System Steam: Source D (with credit for steam specif ic Activity reduction due to RCIC turbine operation) . 0 Sampling Systems Containment air sample: Source A Reactor coolant sample: Source B Plant vent sample: 1% per day Drywell leakage following the filtration by the Standby Gas Treatment System (see subsection 18.1.20.3.2.1.10 for discussion of SGTS source assumptions) 0 Standby Gas Treatment System Charcoal filter: 1% per day drywell leakage (See Subsection 18.1.20 3.2.1.10 for discussion of source assumptions) . o Drywell: Source A o Wetwell: Source C For each of these systems, piping associated with the appropriate operating mode was identified on piping and instrumentation drawings and traced throughout the plant to thei.r final destination. 18.1 20.3 2.5 Doge Integration factors for Pegsonnel-Cummulative radiation exposure to personnel in vital areas (continuous occupancy) is determined based upon a maximum one year exposure period. The integrated doses are modified using Reference 18.1-8 occupancy factors listed below. Reve 27, 10/81 1 8.1-36
SS ES- FS AB Time daggK Occupancy Factors 0 to 1 1 0 1 to 4 0.6 over 4 0.4 Exposures for areas not continuously occupied (frequent and infrequent occupancy) must be determined case by case, that is, multiply the task duration by the area dose rate at the time of exposure. 18 1.20. 3.3 Shielding Review Methodology
- 18. 1. 20. 3. 3. 1 Radiation Dose Calculation tfodel; The previous sections outlined the rationale and assumptions for the selection of systems that would undergo a shielding design review as well as the .formulation of the sources for those systems. The next step in the review process was to use those sources along with standard point kernel shielding analytical techniques (Bef. 18.1-14 and 18.1-15) to estimate dose rates from those selected systems.
Scattered radiation fe.g. ~ shine over partial shield walls) was considered but was not significant since the net reduction in dose is, several orders of magnitude and no vital area is separated from a high activity source solely by a partial wall. Radiation levels for compartments containing the systems under review were based on the maximum contact dose rate for any component in the compartment. Radiation levels in areas not containinq unshielded sources were based on maximum dose rates transmitted into areas through walls of these adjacent compartments. Checks were also made for any piping or equipment that could directly contribute to corridor dose rates, i.e., pipinq that may be runninq directly in the corr'idor or equipment/pipinq in a compartment that could shine directly into corridors with no attenuation through compartment walls. There is no field routed small piping (i. e., piping less than 2>> in diameter) for FCCS systems. Dose rates are cummulative and are summed over all systems in simultaneous operation in most cases. The exception is steam piping for the RCXC and HPCI systems. Both are high pressure systems and cannot be operated simultaneously with low pressure systems such as core spray. This becomes a moot point, since these steam lines are routed in well shielded compartments, causing no appreciable personnel doses. Rev. 27, 10/81 18 1-37
SS ES- PS AR 18 l. 20. 3.3.2 Post-Accident-radiation Zone Na~s One of the principal products of this review is the series of accident radiation zone maps (Figures 18.1-2 to 83. The zone boundaries used in the maps are defined in Table 18.1-3. The zone maps present the calculated dose rates at one hour after the accident due to the sources described in Subsection 18.1.20.3.2.4 in various areas of the plant site. The principal sources of radiation in each area are identified in Table 18.1-5. The dose rates presented do not include contributions from normal operatinq sources vhich may be contained in the plant at the time of. the accident since these contributions vill be minor outside of well defined and shielded areas. They also do not include dose rate contributions due to potential airborne sources resulting from equipment or drywell leakage. The zone maps vere used to determine the accessibility of vital areas described in Subsection 18.1.20.3.3.4. 18.1.20.3.3.3 personnel radiation Exposure Guidelines In order that doses to occupied areas take on meaningful proportions, it is necessary to establish exposure goals or guidelines. The general design basis for these guidelines is 10CFR50, Appendix A, GDC 19. That material addresses control room habitability, including access and occupancy under worst case conditions. Erposures are not to exceed 5 rem whole body/ or its equivalent to any part of the body, for the duration of any postulated accident. GDC 19 is also used to govern design bases for the maximum permissible dosage to personnel performing any task required post-accident. These requirements translate rouqhly into the objectives to be met in the post-accident review as qiven below. Radiation Exposure Guidelines Occupanc y Dose Bate Objectives Dose Objective Conti nuous 15 mR/hr 5 Rem for duration F requent 100 mR/hr 5 Rem for all activities Infre quent 500 mR/hr 5 Rem per activity Accesswa y 5 R/hr Included in above doses Rev. 27, 10/81 18 1-38
0 SS ES-FS AH 18 ~ 1.20 3 3 4 Vital Area Identification and Access
- 18. 1. 20. 3.3 4 1 V tal Area Clarification Vital areas are those <<which vill or may require occupancy to permit an operator to aid in the mitigation of or recovery from an accident<<. Reference (18.1-16) further defines recovery from an accident as, <<when the plant is in a safe and stable condition. <<'his may eithez be hot or cold shutdovn, depending on the situation. <<The 10 CFR 73.2 definition of vital area shall not apply here.
For the purposes of this study, the evaluation to determine necessary vital areas considers all of those listed in Reference {18.1-3) . Upon examination several plant areas were determined not to be vital. Instrument panels vere excluded because essential equipment control and alignment has been established in the control room and requires no local actions. The radwaste control room is excluded because 1) no local actions are required to prevent spread of postaccident sources into the liquid radwaste system; 2) gaseous radvaste processing is not required, and; 3) activity sources early in the post-accident transient are much too high to be effectively processed through the liquid and eventually solid radvaste systems. Also excluded are the post-LOCA hydrogen control system and the containment isolation'eset control area {which are operator actuated from the main control room) . Lastly the emergency power supply (i.e., diesel generators) was exc1uded since system initiation comes from the control zoom and requires no local actions. The resultinq list of areas considered vital for post-accident operations at Susquehanna appears in Table 18.1-4. Note that security facilities are included as vital areas with regards to maintaininq plant security.
- 18. 1. 20. 3. 3. 4. 2 . Vital Area Access Those operator actions required post-accident vere reviewed to assure that first priority safety actions can be achieved in the postulated radiation fields. This review assures that access is available and required operator actions can be achieved.
Ingress and egress area dose rates to those vital areas identified in Table 18 1-4 vere examined to ensure compatibility with the areas beinq accessed. Plant effluent monitoring stations are located at five (5) plant vents: two (2) for the Reactor Building, two (2) for the Turbine Rev. 27, 10/81 18 1-39
SSES-FS AR Building and one (1) for the Standby Gas Treatment System. The
~
reactor buildinq monitors are automatically isolated post-LOCA and will contain no post-accident activity. The SGTS effluent sample station will contain post-accident activity in sample cartridges: one (1) volumetric and one (1) charcoal filter. The samples are locally shielded and present no access problems in the area of the station. However, transportation and handling of the filter cartridges will require local shielding. The Turbine Building Plant Vent Sample Station (PVSS) may also contain post-accident activity. Doses, if lower maqnitude than that of the SGTS effluent any, will be of a filters because environmental dispersion and re-entry to the Turbine Building of ventilation system. In the worse case, the Turbine Building PVSS doses will be much lower than those of the SGTS. In the best case, control room personnel may shut down the Turbine Building HVAC system (which is non-safety related) . In this case, the Turbine Buildinq PVSS may be void 'of post-accident activity.
- 18. l. 20 3. 4 Results P
18.1. 20. 3.4 1 Radioactive Decgg Fffects Results of the radiation level evaluation for the shielding desiqn review are presented .in Figures 18.1-1 to 8. Table 18.1-5 identifies the sources contributing to dose rates in each of the plant areas shown on those fiqures. This table can be used in conjunction with the decay curves (Figures 18.1-9 and 10) to estimate radiation levels at times other than one hour. The procedure for times less than one day, is to multiply the radiation level fi.e., radiation zone limit) by the decay factor qiven in Figure 18.1-9. For times qreater than one day, it necessary to multiply by the decay factor in Figure 18.1-9 at 24 is hours and by the decay, factor in Ziqure 18.1-20 at the desired decay time. This procedure is conservative for areas in which the sources are shielded because it does not rigorously take into account the softening of the energy spectrum an consequent increase in attenuation for longer times. A decay curve for source D, reactor steam, is not decay included because the depletion -effects due to steam usage by HPCI or RCIC removes much of this source shortly after the accident. Zn addition, HPCI and RCIC piping containing source D is run in shielded cubicles and does not contribute significantly outside those cubicles. Rev. 27, 10/81 18 1-40
SS ES-ZS AR 18.1.20-3.4 g Integrated Pegsognel Exposures Personnel integrated exposures in continuously occupied areas were calculated based on 100% occupancy for the first day, 60% occupancy from day one through four and 40% occupancy for the duration (1 year). These calculations shoved that personnel exposures would be vithin the design objective of 5 Rem. Exposures in Zones I, II and III of the control structure are 0.24, 1.6 and 3.1 Rem, respectively. These doses do no include the shielding effects of interior walls, equipment, etc., therefore they represent the maximum dose to control building personnel due to contained sources. Personnel doses to the North Gate House (ASCC) and Security Control Center from contained sources vere found to be insignificant (i.e, ( 0.1 Rem) . These areas are a minimum of 300 feet from the reactor building whose valls are a minimum of 2.5 feet of concrete. Personnel doses at the Post-Accident Sample Station, Chemistry Laboratory, and Plant Vent Sample Station are calculated based on an estimated task duration at specified times post-accident for a one person task force (Refer to Table 18.1-4) 18.1 20 3.4.3 Reactor Building Accessi'bility The results shov that the reactor building vill be generally inaccessible for several days after the accident due to contained radiation sources. High radiation levels can be expected at Elevation 645 -0" (Figure 18.1-3) regardless of which system (s)
~
is (are) in operation. Radiation levels at Elevation 719'-0" (Figure 18.1-5) and above are expected to generally be within Zone IV limits "if the core spray and RHR containment spray systems have not been-operated following the accident. This is because these are the only unshielded post-accident system sources, at these elevations. Other system sources are contained in shielded cubicles. Exceptions to these general Zone IV levels are 'areas in the vicinity of reactor coolant and containment atmosphere sampling lines which are routed to the reactor building sample station at 'levation 779'-0". The dose rate 10 feet from the reactor coolant sampling line one hour after the postulated accident may exceed 100 R/h r. Results for contained radiation sources show that the vital area in the Reactor Building is accessible post-accident. Rev. 27, 10/81 18 1-41
SS ES-PS AR 18.1.20.3.4.4 Control Building Accessibglity Results for contained radiation sources show that vital areas in the control structure are accessible post-accident. 18 1 21 POST-ACCIDENT SAMPX,ING- (XI B 3L A 18.1. 21 1 Statement of Requirement A design and operational review of the reactor coolant and containment atmosphere sampling line systems shall be performed to determine the capability of personnel to promptly obtain (less than 1 houz) a sample under accident conditions without incurring a radiation exposure to any individual in excess of 3 and 18-3/4 zem to the whole body or extremities, respectively. Accident conditions should assume a Requlatory Guide 1.3 or 1.4 release of fission products. If the review indicates that personnel could not promptly and safely obtain the samples, additional design features or shieldinq should be provided. to meet the criteria. design and operational review of- the radiological spectrum analysis facilities shall be performed to determine the capability to promptly quantify (in less than 2 hours) certain radionuclides that are indicators of the degree of core damage. Such radionuclides are noble gases (which indicate cladding failure), iodines and cesiums (which indicate high fuel temperatures), and nonvolatile isotopes (which indica te f uel melting) . The initial reactor coolant spectrum should correspond to a Regulatory Guide 1.3 or 1.4 release. The review should also
~
consider the effects of direct radiation from piping and components in the auxliary building and possible contamination and direct radiation from airborne effluents. If the review indicates that the analyses required cannot be performed in a prompt manner with existing equipment, then design modifications for equipment procurement shall be undertaken to meet the criteria. In addition to the radiological analyses, certain chemical analyses are necessary for monitoring reactor conditions.. Procedures shall be provided to perform boron and chloride chemical analyses assuming a highly radioactive initial sample {Requlatozy Guide 1.3 or 1.4 source term) . Both analyses shall be capable of beinq completed promptly (i.e. the boron sample
~
analysis within an hour and the chloride sample analysis within a shift). Rev. 27, 10/81 18 1-42
SS ES- PS AR The followinq items are clarifications of requirements identified in NUREG-0578, NUREG-0660, or the September 13 and October 30, 1979 clarification letters. li The licensee shall have the capability to promptly obtain reactor coolant samples and containment atmosphere samples. The combined time allotted for samplinq and analysis should be 3 hours or less from th'e time a decision is made to take a sample. (2) The licensee sha11 establish an onsite radiological and chemical analysis capability to provide, within the 3-hour time frame established above, quantification of the followinq: (a) certain radionuclides in the reactor coolant and containment atmosphere that may be indicators of the degree of core damage (e.g., noble gases: iodines and cesiums, and nonvola tile 'sotopes); (b) hydrogen levels in the containment atmosphere; (c) dissolved gases (e.g., hydrogen), chloride (time allotted for analysis subject to discussion below), and boron concentration of liquids. (d) Alternatively, have inline monitoring capabilities to perform all or part of the above analyses. (3) Reactor coolant and containment atmosphere sampling durinq postaccident conditions shall not require an isolated auxiliary s ystem {e. g., the letdown system, reactor water cleanup system to be placed in operation in order to,use the sampling system. Pressurized reactor coolant samples are not required the licensee can quantify the amount'f dissolved gases if with unpressurized reactor coolant samples. The measurement of either total dissolved gases or hydrogen qas in reactor coolant samples is consi'dered adequate. Measuring the oxygen concentration is recommended, but is not mandatory. The time for a chloride analysis to be performed is dependent upon two factors. (a) if the plant's coolant water is seawater or brackish water and {b) if there is only a single barrier between primary containment systems and the coolinq water. Under both of the above conditions the licensee shall provide for a chloride analysis within 24 hours of the sample being taken. For all other cases, the licensee shall provide for the Rev. 27, 10/81 18 1-43
SSES- FS AR analysis to be completed within 4 days. The chloride analysis does not have to be done onsite. (6) The design basis for plant equipment for reactor coolant and containment atmosphere sampling and analysis must assume that it is possible to obtain and analyze a sample without radiation exposures to any individual exceeding the criteria of GDC 19 {Appendix A, 10 CFR Part 50) (i.e., 5 rem whole body, 75 rem extremities). (Note that the design and operational review criterion was changed from the operational limits of 10 CFR Part 20 (NURZG-0578) to the GDC 19 criterion (October 30, 1979 letter from H.R. Denton to all licensees) .) (7) The analysis of primary coolant samples for boron is required for PWBs. (Note that Revision 2 of Regulatory Guide 1.97, when issued, will likely specify the need for primary coolant boron analysis capability at BMR pla nts. ) (8) Ef inline monitorinq is used for any sampling and analytical capability specified herein, the licensee shall provide backup sampling through grab samples, and shall demonstrate the capability of analyzing the samples. Established planning for analysis at offsite facilities is acceptable. Equipment provided for backup sampling shall be capable of providing at least one sample per day for 7 day's following onset of the accident and at least one sample per week until the accident condition no longer exists. (9) The licensee's radioloqical and chemical sample analysis capability shall include provisions to: (a) Identify and quantify the isotopes of the nuclide cateqories discussed above to levels corresponding to the source terms given in Regulatory Guide 1.3 or 1.4 and 1.7. Mhere necessary and practicable, the ability to dilute samples to provide capability for measurement and reduction of personnel exposure should be provided. Sensitivity of onsite liquid sample analysis capability should be such as to permit measurement of nuclide concentra tion in the ra nge 'f rom approximately 1 p Ci/q to 10 Ci/g. (b) Restrict background levels of radiation in the radioloqical and chemical analysis facility from sources such that the sample analysis will provide results with an acceptably small error (approximately a factor of 2) . This can be Rev. 27, 10/81 18 1-44
SS ES- FS AR accomplished through the use of sufficient shielding around samples and outside sources, and by the use of ventilation system design which will control the presence of airborne radioactivity. (10) Accuracy, range, and sensitivity shall be adequate to provide pertinent data to the operator in order to describe radiological and chemical status of the reactor coolant systems. (ll) In the design of the postaccident sampling and analysis capability, consideration should be given to the followinq items: fa) Provisions for purging sample lines, for reducing plateout in sample lines, for minimizing sample loss or distortion, for preventing blockage of sample lines by loose material in the RCS or containment, f or appropriate disposal of the samples, and for flow restrictions to limit reactor coolant loss from a rupture of the sample line. The postaccident reactor coolant and containment atmosphere following a transient or accident. The sample lines should be as short as possible to minimize the volume of fluid to be taken from containment. The residues of sample collection should be returned to containment or to a closed system. (h) The ventilation exhaust from the sampling station should be filtered with charcoal adsorbers and hiqh-efficiency particulate air (HEPA) filters Operatinq License Applicants Provide a description of the implementation of the position and clarification including PSIDs, together with either (a) a summary description of procedures for sample collection, sample transfer or transport; and sample analysis, or (b) copies of procedures for sample collection, sample transfer or transport, and sample analysis, in accordance with the proposed review schedule but in no case less than four months prior to the issuance of an operating license. 18.1. 21. 2 Interpretation None required. Rev. 27, 10/81 18 3.-45
SSZS-FS AR
- 18. l. 21. 3 Statement o f Response 18 g. 21. 3 1 ~
Introduction A design and operational review of the existing reactor coolant and containment atmosphere sampling system vas performed to determine its ability to meet this requirement. The existing sampling system does not meet this requirement and therefore an additional system dedicated to post-accident sampling installed. This system vas designed to satisfy all the vill be requirements as stated in NUREG-0578 and the clarification of item IT..B.3. The system vill be installed and operational by fuel load. The Post-Accident Samplinq System tPASS) concept is based upon obtaininq grab samples for remote laboratory analysis, having a minimum of operating complexities, having very little "in-line" instrumentation, having modular construction for maintenance and contamination control purposes, and being compact in size so as to require less shieldinq and to better fit into existing plants. This concept results in a three-step sampling/analysis process. The samples are obtained via a Post Accident S'ample Station located adjacent to secondary containment. They are then transported to a sample preparation area which consists of a vet chemistry laboratory with the capability to perform the required chemical analyses as well as prepare the samples for radioisotopic analysis. The final step involves transporting the samples to a counting area with a sufficiently low background to permit accurate gamma-ray spectroscopic analysis. 18.1.21.3 2 Descriotion of Samnlina System The underlvinq philosophy in the design of the sampling system is to meet the requirements of item IX.B.3, to minimize exposure by minimizing the required sample sizes, to optimize the weight of the shielded sample containers in order to facilitate movement throuqh potentially high-level radiation areas, and to provide adequate shielding at the sample station. The system is designed to provide useful samples under all- conditions, ranging from normal shutdown and power operation to post-accident conditions. The PAID for the PASS is shovn in Figure 18.1-11. The equipment includes isolation and control valves, piping station, sample station, and control panels. Rev. 27, 10/81 18+i-06
SS ES-PS AR
.3.2 1- Sy~mle~oz.nts 8.1.22~3.2
$ 8.1. S m le oz.nts a) Retwell and,Drywell Atmosphere Provision will be made to obtain gas samples from two separate areas in both the drywell and wetwell. The sample lines will tap into the containment air monitoring system saaple lines outside of priaarr containaent and after the second containment isolation valve. The two drywell sample taps are on the highpoint line, sampling at elevation 790.~, and the midpoint line, sampling at elevation 750'. Secondary Containment Atmosphere J A sample line will be installed to allow sampling of the secondary containment atmosphere. The location of this point has yet to be determined. This sample point would be useful in determining the post accident accessibility of the reactor building. c) Reactor Coolant and Suppression Pool Liquid Samples. Rhen the reactor is pressurized reactor coolant samples vill be obtained from a tap off the get pump. pressure instrument system. The sample point will be on a non-calibrated )et pump instrument line outside of primary containment and after the excess flow check valve. This sample point location is preferred over the normal reactor sample points on the reactor water clean up system inlet line and recirculation line since the reactor clean-up system is expected to remain isolated under accident conditions, and it is possible that the recirculation line containing the sample line may he secured. The get pump instrument line has been determined to be the optimum sample point for accident conditions since: 1) the pressure taps are well protected from damage and debris, 2) if the recirculation pumps are secured, there is normally excel.lent circulation of the bulk of the coolant past these taps (natural circulation), and 3) the taps are located sufficiently low to permit sampling at a reactor water level wliich is even below the lower core support plate. A single sample line is also connected to both loops in the RHR system. The sample-lines will tap off the high pressure switch instrument lines coming off the common section of the RHR system return line. This sample point provides a means of obtaining a reactor coolant sample when the reactor is not pressurized and at least one of the RHR loops is operated in the shutdown coolinq mode.. Similarly, a suppression pool sample can be obtained from an RHR loop lined up in the suppression pool cooling mode. Rev. 30 5/82 18 1-47
SS ZS-PS AR 18.1. 21 3 2.g -Isglatjon- Valvey-and Sample Lines Containment isolation for the dryvell and wetwell gas sample lines is provided by the existing containment air monitoring sample line isolation valves. The get pump instrument sample line containment isolation is provided by an existing isolation valve and excess flow check valve upstream of the sample tap. All gas sample lines from the sample taps to and including the first flow control valves are seismic category 1 except for the secondary containment sample line which has no control valve before it enters the sample panel. The sample lines from the RHR system are seismic cateqory 1 through . both system isolation valves and a flow restricting orifice. The sample, line from the jet pump instrument system is seismic category 1 to the flow control/isolation valve. All containment isolation valves upstream of the sample taps can be overridden from the control room. All isolation and control valves shovn in Piqure 18 1-11 which are within the Q boundary are controlled by a single permissive switch in the control room and individually controlled at the sampling control panel located adjacent to the sample station. The solenoid isolation and control valves which are part of the post accident sample system to the g boundary will be environmentally qualified. The gas sample lines are heat traced to prevent precipitation of moisture and the resultant loss of iodine in the sample lines. ~18,~l. 3./~3. +ipQg Stat~on The piping station, which is to be installed within the'eactor building, *includes sample coolers and control 'valves vhich determine the liquid sample flow path to the sample station. The location for the piping station is shown in Pigure 18.1-12. Cooling water will come from the Reactor Building Closed Cooling Rater Syste m. 18.1,~2~8. sn sdm8~ std~t'~odPd C~ont o1 Panels The location of the sample station, control panels and associated equipment is shown in Piqure 18.1-13. The sample station consists of a wall mounted frame and enclosures. Included within the sample station are equipment, trays which contain modularized liquid and gas samplers. The lover liquid sample portion of the sample station is shielded with 6 inches of lead brick, whereas the upper qas sampler has 2 inches of lead shielding. The control instrumentation is installed in two control panels. One Rev. 30, 5/82 18 1-48
SS ES-PS AR of these panels contains the conductivity, and radiation level readouts. The other control panel contains the flow, pressure, and temperature indicators, and various control valves and switches. A graphic display directly below the main control panel which shows the status of the pumps and valves at all times. 'Xhe panel also indicates the relative position of the pressure qauges and other items of concern to the operator., The use of this panel will improve operator comprehension and assist in trouble shootinq operations. The various sample lines and return lines enter the sample station enclosure (which is mounted flush against the secondary containment wall) throuqh the back by way of a penetration in the steam tunnel wall. Samplers 18 ~ 1 21. 3.2 4.1 Gas The gas sample system is desiqned to operate at pressure ranging from sub-atmospheric to the desiqn pressures of the primary containment one hour after a loss-of-coolant accident. The gas samples may be passed throuqh a particulate filter and silver zeolite cartridqe for determination of particulate activity and total iodine activity by subsequent gamma spectroscopic analysis. A radiation monitor is mounted close to the filter tray to measure the activity buildup on the cartridges. Alternately, the sample flow bypasses the iodine sampler, is chilled to remove moisture, and a 15 milliliter grab sample can be taken for determination of qaseous activity and for gas composition by gas chromatography. The qas is collected in an evacuated vial using hypodermic needles in a manner analogous to the normal off-gas samples. When purqinq the drywell and wetwell gas sample lines to obtain a representative sample, the flow is returned to the wetwell; however, durinq purging of the secondary containment line and when flushinq the sample panel lines with air or nitrogen, flow is returned to secondary containment. The sample station design allows for flushing of the entire sample panel line from the four position selector value through the needles with either air, nitrogen, or the qas to be sampled. This capability will minimize any possible cross contamination between the various samples. 18.1. 21 3. 2 4.2 Li uid Sa miler The liquid sample system is desiqned to operate at pressures from 0 to 1500 psi. The design purge flow of 1 gpm is sufficient to maintain turbulent flow in the sample line and serves to alleviate cross contamination between samples. The purge flow is returned to the suppression pool. The liquid sampling system is desiqned to allow routine demineralized wa ter flushing of the system lines from a point between the two coolers in the piping Rev. 27, 10/81 18.1-49
SS ES-PS A R station throuqh the sampling needles. Using the hydro-test connection which is outside the sample panel, it is also possible to backf lush all the liguid sample lines through the sample tap point. This vill allow for clearing of plugged lines. All liquid samples are taken into 15 milliliter septum bottles mounted on sampling needles. Xn the normal lineup, the sample flows through a conductivity cell (0.1 to 1000 micromhos/cm and through a ball valve bored out to 0.10 milliliter volume. After flow through the sample panel is established, the ball valve is rotated 90O and a syringe, connected to a line external to the panel, is used to flush the sample plus a measured volume of diluent (generally 10 milliliters) through the valve and into the sample bottle. This provides an initial dilution of up to 100:l. The sample bottle is contained in a shielded cask and remotely positioned on the sample needles through an opening in the bottom of the sample enclosure. Alternately, the sample can be diverted through a 70 milliliter bomb to obtain a large pressurized volume. This 70 milliliter volume can be circulated and depressurized into a qas samplinq chamber. A 15 milliliter gas sample can then be obtained through a hypodermic needle for gas chromatographic and radioisotopic analyses of the dissolved. gases associated with the 70 milliliter liquid volume. Ten milliliter aliquots of this degassed liquid can then be taken for off-site (or on-site depending on activity level) analyses which require a relatively large undiluted sample. This sample is obtained remotely using the large volume cask and cask positioner through , needles on the underside of the sample station enclosure. 18,1,21. 3.2.4.3 ~ Sample-Station Ventilation. The sample station enclosure will be vented to secondary containment via the main steam line tunnel. Ventilation is motivated by differential pressure between the turbine and reactor buildinqs. The ventilation rate required for heat removal durinq operation is about 40 scfm. The ventilation duct is sized for less than 100 scfm at 1/4 inch of water differential pressure when the enclosure is opened for maintenance Standby air flow vill be about 3 scfm and can be reduced by taping all openings. A pressure gauqe is attached to the sample station enclosure to monitor the pressure differential between the enclosure and the general sampling area in the turbine building. This vill assure the operator that airborne activity in the sample enclosure will be swept into secondary containment. I 18- l. 21. 3. 2. 4. 4 Sample Sta tion Sump The sample station is provided with a sump at the bottom of the sample enclosure which will collect any leakage within the Rev. 27, 10/81 18 1-50
SS ES-PS AR enclosure. This sump can be isolated and pressurized, discharging into the sample station liquid return line to and hence into the suppression pool. 18 1-21.3 2 4.5 Sample Handling Tools and Transport Contaigers Appropriate sample handling tools and transporting casks are provided. Gas vials are installed and removed by use of a vial positioner throuqh the front of the gas sampler. The vial is then manually dropped into a small shielded cask directly from the positioning tool. This allovs the operator to maintain a distance of about three feet from the unshielded vial. This cask provides about l-l/8 inches of lead shieldinq. A 1/8 inch diameter hole is drilled in the cask so that an aliquot can be withdrawn from the vial with a qas syringe vithout exposing the analyst to the unshielded vial. The particulate and iodine cartridges are removed via a drawer arranqement. The quantity of activity which is accumulated on the cart idge is controlled by a combination of flow orificing and time control of the flow valve opening. In addition the deposition of iodine is monitored durinq sampling using a radiation detector installed in the sample station next to the cartridqe. These samples vill hence be limited to activity levels which will not require shielded sample carriers. The small volume (diluted) liquid sample cask is a cylinder with a lead wall thickness of about tvo inches. The cask weighs approximately 65 pounds and has a handle which allovs carried by one person. it to be The 10 milliliter undiluted sample is taken in a 700 pound 1ead shielded cask which is transported and positioned by a four-wheel dolly. The sample is shielded by about 5-1/2 inches of lead.
- 18. 1. 21. 3. 2. 4. 6 Sample Station Power Supply The PASS isolation and control valves, 'sample station control panels, and auxiliary equipment are connected to an Instrument AC Distribution Panel which is powered from an Engineered Safeguard System fESS) bus. Following a loss of off-site power, the ESS bus is powered from the on-site diesel generators and backed up by batteries. The Reactor Building Closed Cooling Mater System, which is needed for the sample coolers, is also powered from the emerqency diesel generators following a loss of off-site pover.
Compressed air for the air-operated valves comes from compressed Rev. 27, 10/81 1 8. 1-51
SS ES- PSAR air cylinders, thus eliminating any dependence on the plant compressed air system.
- 18. 1. 21. 3. 3 Description of Sampl e Preparation/Chemistry and gucleag Counting gacilifies After the samples are obtained from the sample station, they will be transported to a sample preparation/chemistry area. There they vill be diluted as necessary and appropriate aliquots taken for chemical and radioisotopic analyses. The radioisotopic analysis will be done in a separate counting area vhere background radiation can be kept to a minimum. Tvo different facilities vill be available to plant personnel to perform the above tasks. The primary facility is the existing chemistry laboratory and counting room which is at elevation 676 ' the ground level of the control structure. A backup sample preparation/chemistry area and counting room will be built as part of the Emergency Operations Pacility (EOP) which is located 2500 feet south-vest of the control structure. Tn addition to these on;site and near-site facilities, which are intended to handle the qas samples and the diluted liquid samples, prior arrangements vill be made vith an independent off-site laboratory for analysis of the undiluted 10 ml liguid samples.
18.1 21 ~ 3. 3.1 On-Site Chemistry Laboratory and Counting Room The plant shielding study results, presented in Subsection 18.1. 20. 3, show that following an accident, the chemistry laboratory will be a Zone 1X area (<100 mR/h) . Therefore, the existinq facilities will be accessible at least for intermittent use followinq an accident. The most direct route between the sample station and these facilities is- through areas of the turbine buildinq which should be Zone I areas (<15 mR/h) followinq an accident. ~ The chemistry laboratory is or will be equipped to provide the capability to handle the gas samples and the O.l ml diluted liquid samples. The maximum activity of these samples vill be 0.7 Ci and 0.3 Ci, respectively, using one-hour decay and the fractional releases of core inventory specified by NUREG-0578 (see Section 18.1.21.3.5). The laboratory will maintain a dedicated inventory of items such as lead bricks for shielding, qas syringes, gloves, reagents for analyses, etc., which vill be needed in case of an accident. The laboratory will be equipped with a gas chromatograph, pH meter, conductivity meter, turbidimeter and other instrumentation needed to perform the required analyses. This equipment however, may not be dedicated exclusively to post-accident analysis. Supplied air or self-contained breathing masks will be available in the Rev. 27, 10/81 18. 1-52
SS ES- PS AR event of hiqh activity levels in the ventilation supply or accidental spills in the laboratory. The existinq counting facility located adjacent to the chemistry laboratoxy is veil eguipped to handle the gamma spectra analyses required for post-accident samples. The counting room is equipped vith tvo Ge (Li) detectors with four inch lead shields connected to a computer based analyzer system. The system has automatic peak search and isotope identification capabilities. The Ge (Li) detector and shelf assembly in the lead shield can be veil isolated and the capability to purqe the volume within the shield with compressed qas will be provided. This will help prevent atmospheric noble qas activity released during an accident from swamping the detector. 18.1. 21. 3. 3. 2 EOP Sample Preparation/Chemistry and Counting facilities The sample preparation and countinq rooms located in the near-site EOP will serve as backups to the on-site facilities. The EOF is 2500 feet from the contxol structure and is directly accessible from the site by road. Travel time from the sample station to the EOF vill be less than 30 minutes. The backup facilities will be activated whenever the on-site facility becomes inaccessible or if additional 1ab space'or counting equipment is needed to handle the increased work load in the on-site facility resulting from an accident. The sample preparation/chemistry room vill be furnished with a radioisotope laboratory hood, about 14 feet of laboratory cabinets and benchtop working space, a small sink draining to a removable carboy, and at least a 5-qallon supply of demineralized vater in plastic carboy mounted on the va11 ovex the sink. The hood vill be equipped vith a HEPA filter unit. Although some analytical instrumentation may be kept in this room, it is not meant to completely duplicate that in the on-site laboratory. However, the facility vill be fully equipped to handle the necessary dilutions and manipulations to prepare samples which come directly from the sample station for gamma spectroscopic analysis. Additional instrumentation for the required chemical analyses vill be brought from the on-site laboratory as needed. Chemical reaqents, glassware and other miscellaneous eguipment vill be stocked in the facility. A supply of lead bricks will also be kept in this room for use as temporary shielding. A lead brick cave for storage of samples vill also be provided. The EOP countinq room vill contain .as a minimum a'high resolution gamma-ray spectrometer system. The system will be capable of characterizing and quantifying the gamma activities of reactor coolant and containment atmosphere samples. The intent is to make this system similar to the on-site system. Rev. 27, 10/81 1 8.1-53
SS ZS- FS AR The EOF will have its own diesel generator which vill be capable of supplying the electrical power needs for the facility during loss of off-site power. 18.1. 21. 3.3. 3 - Arrangements for:Off-Site Analyses A key part of the SSES approach to post-accident sampling is the establishment of prior arrangements with an off-site independent laboratory for confirmatory and supplemental analyses. The capability of the off-site laboratory vill also be used to meet the requirement for chloride analysis. The reason for using the off-site laboratory for chloride and as a backup for other analyses is to prevent having to handle and analyze undiluted coolant samples which may have activity levels in the curie per milliliter ranqe. The on-site and EOP facilities are not designed to handle sources of this magnitude. The analyses of undiluted. samples can be done in a safer manner by laboratories with facilities and personnel specifically built and trained to handle hiqh-activity sources. The following is a description of the siqnificant features being requested of the off-site laboratory: a) A formal mechanism will be established to allow for initiation of post,-accident services at any time (24 hoursj'day) . b) Written procedures will be established, controlled, and maintained for each of the analyses described in Table 18.1-
- 6. The analysis procedures must be qualified for use at the activity levels qiven in the table. This requirement may be satisfied by referencing the appropriate literature, by calculations, or 'by undertakinq a testing program.
c) Laboratory equipment and facilities for the required analyses must be available and maintained in working order such that analyses may be completed within 24 hours of the receipt of the sample. d) Provision will be made for the practice or exercise of each aspect of the off-site analysis work at the option of the utility. e) Eguipment will be available for the timely transmission and rec eipt of infor mati on an d res ults (telecopier a nd/or telex) f) The laboratory will be operational for at least chloride analysis by fuel load. Rev. 27, 10/81 18 1-54
SS ES-FS AR 18-1 21 3.4 Summary Desc rip tip n. of~Poced use s 18.1. 21. 3.4 1 Sample Collection and Transport Procedures After a decision is made to obtain, a sample, the designated sample station operators (2) will proceed to the sample station with the necessary equipment. Since all the post-accident sample lines (except for the secondary containment atmosphere) tap off-lines which are isolated followinq a containment isolation signal, the sample station operator must confirm with the control room that the necessary isolation valves are open. (A telephone extension to the control room will be installed close to the sample control panels for this purpose). The control room must also activate the "Accident Sample Station Permissive Switch<< to allow the sample station operator control, of the <<isolation and control valves" which are part of the post-accident sampling system. After switchinq the <<Master Shutoff Valve Control" to the "open" position, the operator is ready to open the valve(s) controlling flow from the desired source to the sample station..After opening the necessary control valve (s), the operator goes to the "sample station control panel<<. This panel controls the valves which are part of the pipinq station and those i.n the sample station enclosure in the turbine buildinq. Following a series of presampling checks and procedures includinq: adjustment of the enclosure damper to insure adequate cooling, checks of demineralized water and nitrogen supplies, flushing of system with demineralized water, draining the trap and sump, etc.; the system is ready for obtaining the samples. 18 1 21. 3.4. 1. 1 P~ocgduge for Obtaining l:as Sample 8 A standard 14 7 milliliter off-gas vial is placed in the gas vial positioner and inserted into, the gas port on the front of the sample station. The desired sample location is selected by switch and the qas is circulated until the sample lines are flushed out with the qas being sampled. The vial and a small volume of tubinq remains unflushed; however, the vial and this tubing volume are then evacuated. The sample is then drawn into the vial by pressing and holding a pushbutton switch. Xf cross-contamination is suspected due to incomplete evacuation of the vial, the evacuation and fill sequence can be repeated using air or'itrogen flush before taking the final sample, or the sequence can be repeated with the desired sample gas until the operator is assured that he has a representative sample. Following an air or Rev. 27, 10/81 1 8.1-55
SS ZS-FS AR nitrogen purqe of the sample lines, the gas vial positioner is then removed from the port and the vial inserted into the gas vial cask. The length of the vial positioner allows the operator to remain about three feet from the vial during this operation. The cask has a 10-inch carrying handle and can be easily carried by one @erson down the stairs in the turbine building to the chemistry laboratory.
- 18. l. 21. 3 4. l. 2 Procedure for Obtaining an Iodine Particulate Sample The desired filter cartridge fs) are placed into a cartridge retainer which is placed into the qas filter drawer. This drawer slides into an opening in the front of the sample station enclosure. The appropriate critical orifice is also chosen and placed in the cartridge retainer. This will determine the flow rate through the sampler and thereby control the amount of activity deposited on the filters. The operator then selects a sample location and flushes the sample line except for a short piece of tubing qoinq to the sample drawer. However, this line can be flushed with air or nitrogen prior to sampling if between samples is suspected. In addition, as part cross-'ontamination of the normal samplinq procedures, this line is flushed with air or nitrogen after completion of each sample seguence and should therefore be free of contamination for the following sample. The operator has the option of usinq an automatic timer to obtain samples with collection times between 0 and 30 seconds or of manually timing the sample for longer collection times. After startinq the sample collection sequence, the operator will be able to follow activity buildup on the filters by observing the radiation level readout, on the control panel from the probe inserted next to the. cartridges in the gas sample panel. After sample collection is completed, the cartridges are evacuated using the vacuum from the qas pumps and then flushed with air or nitrogen to remove the noble gases. The filter drawer is withdrawn and the cartridqe retainer with filters is placed in a plastic baq. The. baq is then closed, and depending on the measured dose rate, it is carried by hand or attached to a pole and carried to the chemistry laboratory. No shielding cask is provided for these samples since amount of activity deposited on them.
it is possible to regulate the In addition, for ease of
- counting, samples low.
it is desirable to keep the activity levels on these 18 l. 21 3. 4. ~3 p~oceduge for O~baining a Qiluted Liquid Sample A 15 milliliter sample bottle with a neoprene cap is placed in the small volume cask which is then placed into a positioner Rev. 27, 10/81 18 1-56
SS ES-PS AR attached to the sample station support frame. The sample needles are exposed by pullinq out the lead shielding drawer under the sample station enclosure. The cask holding the sample bottle is then swung into position under the sample station and the sample bottle raised into position so the needles penetrate the neoprene cap. After aliqning the proper valves, the sample lines from the selected source through the pipinq station are flushed with return flow to the wetwell. A fter these lines are flushed, the bypass valve in the pipinq statio'n is closed and the sample flows to the sample station through the calibrated volume sample valve and back to the wetwell. After sufficient flushing, the calibrated valve is rotated 90o into alignment with the line to the samnle bottle. A syringe filled with up to 10 ml of demineralized water is connected onto a line at the front of the sample station and this water is injected to wash the sample captured in the ball valve into the sample bottle. The syringe is then removed, filled with air, re-attached and the air injected to force out all water remaining in the line through the sample needle and into. the sample bottle. The rinsing action of the water followed by the air purge of'he line should reduce cross-contamination between different samples. The calibrated sample valve is returned to the purge position and the sample lines, from the second cooler in the piping station, through the sample valve and back to the suppressor pool are rinsed with, demineralized water. The operator then returns to the sample station, remotely lowers the sample bottle'nto the cask, screws a top plug with carrying handle into the cask. The cask is then carried down the stairs to the chemistry laboratory. Although one person can carry the cask, a pole with a hook in the middle will be available to allow two people to carry the cask more easil y.
- 18. l. 21. 3. 4. l. 4 Procedure for Obtaining a Large Liquid Sample
/undiluted),and~or a Dissolved Gas Sample A standard off-gas sample vial is placed in the gas vial positioner and inserted into the dissolved gas sampling port on the front of the liquid sample panel and a 15 milliliter sample bottle is placed in the larqe volume sample cask. The sample cask is Dositioned under the sample enclosure using a four-wheeled cart. The cask is raised into position and the sample bottle raised out of the cask and onto two needles using a remote mechanism. When the cask is properly positioned, the operators vill be shielded from the sample during all subsequent operations. After attaining the proper valve lineup, the sample lines are first flushed through the piping station and then through the sample station lines including the 70 milliliter hold up cylinder and gas breakdown circulation loop. After completing the flush cycle a fixed volume of the pressurized liquid is isolated and a measured amount of a tracer gas is injected. The Rev. 27, 10/8l 18.1-57,
isolated volume is then depressurized by opening a valve to a previously evacuated 15 milliliter gas collection chamber. The operator nov has the option of either collecting the dissolved gas sample in an evacuated vial or releasing it to the suppression pool atmosphere. collected, it If a dissolved gas sample is is handled and transported in the same manner as the containment qas sample discussed previously. The operator also has the option of collecting a 10 milliliter sample of the degassed liquid or allowing it to be flushed to the suppression pool during the subsequent demineralized water flush cycle. If a large volume sample is desired, it is dravn into the evacuated 14.7 milliliter sample bottle. To minimize cross-contamination, the system can be cycled several ti~es through all the above steps before takinq the final large volume sample. -The dissolved qas and liquid sample system is then flushed with demineralized water to minimize radiation levels vhile removing samples from the station. The sample bottle is then remotely lovered from the needles into the shielded sample cask which is lowered on the cart and pulled out from under the sample enclosure. A lead plug is then inserted in the opening of the cask and the cask can be easily moved to the elevator in the control structures using the positioninq cart. By using this elevator no steps are encountered vhen moving the cask from the sample station to qround level. The shielding study results (see Subsection 18.1.20. 3) indicate that this eleva'tor should be accessible from a radiation level standpoint. In case of loss of off-site power, the elevator vill be out of service since no emergency pover is provided. Hovever, the undiluted sample is only essential for determininq the chloride concentration which is not required until four days after sampling. This vill allow a reasonable time for the restoration of off-site power. However, if after two days off-site pover is not restored, arrangements can be made to lower the sample cask from the turbine operating floor to ground level through one of three open hatches. Since the undiluted sample is to be sent to an off-site laboratory, prior arrangements will be made to have a shipping container sent from the off-site laboratory or have one available on-site. The current intent is to have several shipping containers built which will hold the large volume casks, thus avoidinq the exposure which vould result from trying to transfer the sample from the sampling cask to another container. Rev; 27, 10/Sl 18.1-58
SS ES-PS AR 18.1. 23.. 3. 4. 2 Chemicalggadiochem ical Procedures 18 1 21.3 4 2 1- Introduction The PASS provides a means of obtaining primary coolant, suppression pool, and primary and secondary containment air samples for radiochemical and chemical analysis following a major reactor accident. Because of the extremely high radioactivity levels associated vith extensive fuel damage, the PASS and its auxiliary support was developed with the philosophy of providing the capability of obtaining the necessary" samples and of performing on a timely basis those analyses, as required, for immediate plant needs, or as defined by regulatory requirements. Procedures and arrangements vill be established for shipping samples to facilities having the experience and equipment appropriate to performinq detailed and accurate chemical analyses on multi-Curie level samples. The analytical procedures chosen vill satisfy the philosophy of performing only those analyses as reguired for operational support, of minimizing personnel exposure and contamination hazards, and of dependinq upon outside analysis for extensive analysis and long-range operational needs. Tests were performed by General Electric to assess the effects of high fission product levels on the suggested analytical methods. The type of fuel damage associated vith the release of megacurie quantities of iodine and other activities also has the potential for releasing kilogram quantities of stable or very long lived fission products. Xt is conceivable that the primary coolant might contain 10-20 ppm of iodide and bromide. Also, the release of a major fraction of the core inventory of cesium and rubidium may sliqhtlv raise the primary coolant pH. Such releases vill also cause an increase in the coolant conductivity while radiolysis of the vater vill probably contribute to the formation of low levels o f hydrogen peroxide. Depending upon the concentrations, these are all possible analytical interferences,with the required analysis. Of these, the iodide/bromide interference with the chloride procedure is probably the most severe. 'owever, since the requirement for chloride analysis will be satisfied by sendinq the samples to an off-site laboratory, the chloride procedure being proposed for the on-site laboratory is only to obtain a rough upper limit. The ef fects of radiation interference have been qenerally evaluated and are summarized in S uhsect ion 18. l. 21. 3. 6. Rev. 27, 10/81 18.1-59
SSES-FSAR 18 1-. 21 3. 4. 2~/ Sample Preparation All. sample bottles, iodine cartridges, etc., will be numbered or otherwise identified prior to sampling. This will eliminate unnecessary exposure as a result of handling high level samples for the purpose of attaching labels. A centralized logging system will be developed to keep track of sample aliquot identification, dilution factors, sample disposition, etc. Liquid samples will be taken at the sample station in septum type bottles and transported to,the analysis facility in lead containers.. Sample aliquots are then taken from the septum bottles for analysis or further dilution. Aliguotinq and transfer will be performed using shielded containers, or behind a lead .brick pile. Calibrated hypodermic syringes will be used for aliquotinq the higher activity samples. Tongs or other holding/clampinq devices will be available for holding the bottle Rurinq the transfer and di1utions to reduce hand and sample body exposure. Unless prohibited by the intended analysis, dilutions vill be done using very dilute fabout 0-01N) nitric acid as the diluent to minimize sample plate-out problems. Reactor coolant activity levels on the order of 1 to 3 Curies per qram would require a dilution factor of lxl0~, or larger, for gamma ray spectroscopy samples. As an example, a typical series of dilutions miqht be 0.1 ml (100 lambda) added to 10.0 ml at the sample station, followed by further diluting of O.l ml to 100 ml in the laboratory. An aliquot of 0.1 ml would then be taken from the second dilution for counting purposes. Gas samples are taken at the sample station in the same 14.7 ml septum bottle used in the normal offgas sampler. is furnished with a small hole at the septum end so that carrier A lead a gas sample can be withdrawn from the carrier using a hypodermic syrinqe without having to handle the bottle. Samples taken from the qas sample bottle wil either be injected into a qas chromatoqraph qa seo us activity for gamma spectroscopy purposes. will be performed in a manner analoquous to the liquid The 'i for analysis or used to dilute the lutions samples. Fractional milliliter samples can be transferred to new 14.7 ml qas bottles without concern for sample leakage due to pressurization. For larger volume aliquots a gas syr inge will be used to draw a partial vacuum in the bottle prior to sample trans fer. Since there is no initial dilution of the gaseous activity at the sample station, extensive dilution may be required in the laboratory. Rev. 27, 10/81 18 1-60
SS ES-PS AR 18 1 21 3.4~2 3 Chemical'. A~na gsis
- a. Introduction The chosen procedures are not necessarily the most sensitive nor the most accurate. They vere chosen primarily on the basis of simplicity, stability and availability of reagents, minimum radiation exposure, and least likely to cause major contamination problems. They have been tested for radiation sensitivity and are suitable for use, at the PASS design basis source term of 2.8 Ci/qm, and where applicable, with the design basis 0. 1 ml to 10 ml dilution at the sample station.
- b. Boron Analysis Carminic Acid Method The chosen HACH method closely follows the ASTM D3082-74, "Standard Test Method for Boron in Water, Method A Carminic Acid Colorimetric Method." The HACH procedure is suggested because the reagents and standards are available in small quantities, are conveniently packaged, and can be quickly prepared. It is estimated that the complete analysis, including reaqent preparation, can be performed in 40 minutes.
This method was tested to be satisfactory for use at the maximum expected activity levels. The analysis is designed for boron concentrations in the range of 0.1 to 10 ppm of boron. This sensitivity is particularly suited to the sample station s 0. 1 ml to 10.0 ml dilutions since this corresponds to a range of 100 to 1000 ppm in the undiluted coolant.
- c. Chloride Analysis Turbidimetric Method (see also the discussion on conductivity)
The chosen method was developed by the General Electric Reactor Chemistry Traininq group. The procedure is very similar to a HACH Chemical Co. procedure, "Turbidimetric Determination of Trace Chloride in Water". measurable chloride by this procedure is If 5quantity of The minimum 0.5 q. ml of the 0. 1 to 10 ml primary coolant dilution is used for analysis, the minimum measurable concentration would be 10 ppm. Using the 10 ml. direct primary coolant sample greatly increases the sensitivity for measuring chloride. A one ml of aliguot of this sample could be analyzed at the 0.5 to 1.0 ppm level. r Tests of the radiation sensitivity of the method showed that activity levels comparable to the PASS design basis source terms resulted in the equivalent of 1.8 ppm Cl- in the primary coolant Rev. 27, 10/81 18 1-6't
SS ES-PS AR for the O.l to 10 ml dilution. This was deemed to be insiqnif icant, importantly, as it is below the sensitivity limit, and interference from the more large amount of stable fission product halides potentially associated vith the source terms vill far out-shadov the radiation effect itself. Tests were also performed on the addition of 500 p g of boron added to 0. 5 to 20 p g of chloride. No interference was observed with the turbidimetric procedure.
- d. measurement of pH Indicator paper for pH vill be used for activity levels belov 10%
of the design basis source terms. The irradiation tests indicated that at 10% of the design basis source terms, the color stability vas adequate given only a drop of solution and less than a 5-minute exposure. Using this method, pH measurements can be taken at the small volume sampler by placing a piece of the into the sample bottle and using an air filled syringe to paper blow several approximately O.l ml aliquots from the sample valve into the bottle to moisten the paper. This type of sampling approach can also be used to obtain a small sample for possible electrochemical pH measurement. Lazar Research Labs, Inc. manufactures a micro-pH electrode which functions on microliter samples. This electrode or similar micro-probe is currently being evaluated for use at source term greater than 10% of desiqn basis. Indicator paper for pH can cover the range from l-ll and distinqu ish differences of 0. 25 pH units. At very low 'conductivities, conductivity itself may be the best indicator of the pH. Por instance, at 0. 2 micromho/cm, the pH is bounded by 6.3 to 7.6, which is well within the technical specifications for normal operaton. Thus, the conductivity should serve as an adequate indicator of pH as long as is sufficiently lov that it is impossible to be'onductivity outside, the technical specifications limit.
- e. Conductivity Measurements The Post Accident Sample Station is equipped vith a 0.1 cm-i conductivity cell. The conductivity meter has a linear scale with a~ six position range selector switch to give conductivity ranqes of 0-3, P-10, 0-30, 0-100, 0-300, and 0-1000. micromho/cm vhen using the O.l cm-i cell. This conductivity measurement system vill be used to determine the primary coolant or suppression pool conductivity. During normal operation, the BMR Rev. 27, 10/81 18 1-62
SSES-FS AR technical specifications require maintaining the primary coolant below 1 micromho/cm, and conductivity measurements are the primary method of coolent chemical control. Conductivity measurements are, of course, non-specific, but they serve the important function of indicating changes in chemical concentrations and conditions. perhaps even more important, in the case of the BMR primary coolant, the conductivity measurements can establish upper limits of possible chemical concentrations and can eliminate the need for additional analyses. For example, if the conductivity is measured to be 5.0 micromho/cm, the upper limit on the chloride concentration is 1.4 ppm The conductivity measurement can also be used to bound the possible range of pH values. This relationship is shown in F ig ur e 1 8. 1-14. At a specific conductance of 1 0 micromho/cm the pH must be between 5.6 and 8.7. Furthermore, a pH of 5 and a specific conductance of 1.0 is an impossible situation since the conductivity is not large enough to support a hydrogen ion concentration of 10-~N. Figure 18.1.21-4 can< therefore, be used to qreat advantage in checking on agreement between pH and conductivity measurements and possibly eliminating the need for pH measurement if the conductivity is very low. In general, accurate pH measurements are difficult to make in very low conductivity water as the impedance of the solution may be significant compared to the impedance of the measuring device, and conductivity measurements are usually considered a better indicator of the maximum H4 or OH- concentration.'.
- 18. 1. 21 3 4 2.4 Radiochemical A~nal sis--Gamma R~a Spectroscopy After the samples have been brought to the chemistry laboratory and appropriately diluted, they can be carried without shielding to the counting room which is adjacent to the chemistry laboratory. The appropriate dilution factors w'ill be somewhat dependent upon the detector and shelf arrangements available. A prior determination of the maximum desirable dose rates f or the various shelf configuration will be made to minimize this problem. The present hiqh resolution, high eff iciency Ge (Li) detectors, coupled with the multichannel analyzers, and computer data reduction in the on-site counting room will easily handle the analysis of these samples.
The gas samples will be counted in the standard off-gas sample vials and the liquid samples will be counted in the standard sample bottles used durinq normal operation since calibration curves for these qeometries will be available and regularly Rev. 27, 10/81 1 8.1-63
SS ES- FS AR updated. Calibration curves vill also be available for the particulate filter and iodine cartridge geometries. Xn general, the countinq of the past-accident samples vill follow the normal counting room procedures. A special post-accident library will have to be developed for use by the computer peak search and identification routine to supplement the normal isotope library. The post-accident peak search and identification library vill contain the principal gamma rays of the followinq isotopes in addition to the standard activated corrosion products: a Noble gases: Kr-85, Kr-85m, Kr-87, Kr-88, Xe-131m, Xe-133, Xe-133m, Xe-135 Iodines: I-131, I-132, I-133, I-135 Cesiums: Cs-13 4, Cs-1 37 Others: Ba/J.a-140, Ce-141, Ce-144, Ru-106, Te-129, Te-129m, Te-131, Te-131m, Np-239 If the levels of noble gases in the ambient atmosphere surrounding the detector is hiqh enough to cause significant interference or overload the detector, a compressed air or nitroqen purge of the detector shield volume will be maintained. 18 1. 21-3.4 2 5 Gas Ana1ysis-Gas Chromatography A qas chromatograph vill be used to measure hydrogen, nitrogen and oxygen concentrations in containment atmosphere and dissolved qas samples. The gas chromatograph will be located in the chemistry laboratory and vented to a laboratory hood. Samples for gas analysis will be used undiluted from the sample vials and injected into the gas chromatoqraph. Since the sample sizes needed for the analysis vill range from O.l to 1 milliliter, it may be necessary to place a temporary lead shield around the instrument. The analysis of the drywell, wetwell, and secondary containment samples will be done using standard procedures. Calibration curves for the instrument will be prepared and periodically updated. In the mixture of hydrogen, oxygen, nitrogen, and possibly krypton, the analysis sensitivity should be sufficient to detect any of these constituents at the 0.1% by volume level, or lower, providinq the Kr:N ratio in this mixture does not vary by more than a factor of 10 in either direction. At the 0.5% level the analysis should be accurate to within 20% of the measured concentration. At concentrations above 1%, the analysis should be accurate to within 5$ of the measured concentration. The dissolved gas sample vill contain krypton or other tracer in addition to oxyqen, nitrogen, and possibly hydrogen. Although the analysis of the dissolved gas sample for hydrogen should be Rev. 27, 10/81 1 8.1-64
SS ES-FS AR reliable, the analysis for oxygen and nitrogen presents several difficulties. The major problem is due to the incomplete evacuation of the sample vial which initially contains air., A partial vacuum (4-5 psia) is drawn on the vial before the sample is taken, however, this leaves a significant of air in the vial. This may not be a significant problem amount if 'the amount of dissolved oxygen or nitrogen stripped from the coolant is large compared to that left in the evacuated vial, since a correction can be made based on the pressure measurements taken before and after taking the sample. However, dissolved oxygen and nitrogen is not required by NUREG-0737, which states that determination of dissolved hydrogen gas in the coolant is adequate. In case the need should arise, a procedure will be established to tap off the sample line in, the sample station and run this to an in-line oxygen monitor. The flow would then return to the liquid'eturn line to 'the wetwell. 18,1.21.3.4.3 Stoppage and Djsgosag of Sample ~ Short term sample storaqe areas will be provided in the chemistry laboratory and countinq rooms facilities. An area for long in both the on-site and EOF term storage of the samples will be designated at a later date. Low level wastes qenerated by the chemistry procedures will be flushed to radwaste in the on-site chemistry laboratory and collected in removable carboys in the EOF. The carboys will then be taken to an on-site location for disposal to the radwaste system. Ultimate procedures for disposal of the samples will be determined later; however, after a sufficiently long decay period, the activity levels will be significantly reduced. This will ease exposure problems during disposal. 18.1. 21. 3. 4~4- System Testing and Operator Traini~n To ensure the lonq-term operability of the PASS, it will be tested semiannually. Samples vill be taken from all gas sample points; however, the number and type of liquid samples taken will be based on the operating status of the reactor at the time. The semiannual functional testing will also serve to maintain operator proficiency In addition to the scheduled tests, the system will be used for operator training on an as-needed basis. To ensure an adequate pool of qualified PASS operators, a formal traininq program vill be established. This program will be of the chemistry technician qualification program. All plantpart chemistry. technicians and chemistry management personnel will be required to show competence in the operation of the sample station and the chemical analysis procedures. Rev. 27, 10/8l 18.1-65
SSES-PS AR 18.$ .21. 3.5 - Dose Rate Analysis-Radioactivity source terms were calculated for use in design of the PASS shielding. These source terms are for a LOCA assuming a release of fission product activity as defined by NUREG 0578. Source terms were calculated for a. three year reactor operation at 3293 MWt. Por the purposes of specifying shielding design source terms, a decay period 'of one hour has been assumed between reactor shutdown and initial sampling. Although there is no decay period specified, in NUREG 0578 the source terms calculated for PASS still result in a conservative design. The PASS is designed to limit operator whole body exposure to 100 mRem as a result of taking and analyzinq the sample. NUREG 0737, on the other hand, limits the operator exposure to less than 5 Rem whole body exposure for the entire operation. Using a one hour decay and the fractional releases of core inventory specified by NUREG 0578, the primary coolant and primary containment atmosphere fission product concentrations are calculated to be 2.6 Ci/gm and 0.046 Ci/cc, respectively. Using these fission product concentrations, gamma radiation source terms were determined in terms of MeV/sec for ten gamma energy groups. These radiation source terms were used for shielding design and sample dose rate ca'lculations. Assuming point sources, the calculated dose rates per unit volume of coolant and containment atmosphere are 125 R/h/gm and 1.8 R/h/cc at 4 inches, respectively. Thus, the 0.1 milliliter reactor sample would have a maximum exposure rate of about 12 R/h at 4 inches and 14.7 milliliter vial of containment atmosphere at STP would have an exposure rate of 25 R/h at 4 inches. Using the calculated source terms, dose rate estimates resulting from activity in the sample station and sample casks were calculated for various distances. The results are given in Table 18.1-7. These dose rates vill be used in a time-motion study to estimate the total integrated dose expected, during sampling and analysis after the sample station is opera tiona l. 18,1.21 3.6 Irradiation Effect On Analytical Procedures Some scopinq tests were performed to study the effect of high fission product levels on the proposed analytical procedures. The core inventory of individual nuclide beta energies in terms of HeV/second/NWt after one hour decay was taken from the same CINDER run as used to calculate the PASS activity source terms. The NUREG-0578 release fractions were used to determine the fraction of the core inventory dissolved in the primary coolant. The <<all other<<category was ignored as at a 1% release fraction Rev. 27, 10/81 18 1-66
SS ES-FSAR the dose contribution from these nuclides is negligible compared to the", 50% halogen and 100% noble gas releases. The results are shown in Table 18.1-13. For the sake of simplicity, assumed that the gamma energy deposition in the. sample was it was negligible compared to'the beta energy deposition. assumed that 100% of the beta energy was absorbed in the It was also net result, 1.92x10~ Rads/hr, is conservative as the gamma sample.'he energy absorption for small samples vould be much less than the beta energy escaping the solution. Dose rates approaching 2X10~ R/h are available in the VNC Co-60 irradiation facility. At 93 ergs/g/R/h, this corresponds to 1.8xl0~ Rads/hr, and approximates the calculated maximum energy deposition possible for the reactor coolant. Tests were run to determine the effects of radiation on the conductivity, pH, chloride, and boron analytical procedures. The true energy deposition vithin the irradiated sample holders was determined by Fricke dosimetry using the sample holders as dosimeters. Except for conductivity and pH measurements, the dose rates were considerably larger than vould be encountered with the PASS source terms. These higher dose rates vere used to achieve a better measurement of the radiation effect, and assumed that this effect would be linear with dose rate. it was then It is hoped to ver].fy this assumption in later studies.
- 18. l. 21. 3. 6. 1 Cond uctivitg Cell A O.l cm Balsbaugh conductivity cell and stainless steel holder was irradiated at various positions in the 4 1/4-in. dia. Co-60 irradiation tube. The flow path from this conductivity cell vas connected to a O.l cm Beckman conductivity cell downstream of the cell under irradiation. Both static and flowing irradiation tests were performed. The flov tests vere performed at ca. 125 cc/min vith a 3 to 4 min flow delay betveen the Balsbaugh and Beckman cells. The Beckman cell, therefore, served to determine if there vere any relatively long lived radiation products remaining in solution. An in-line thermometer was mounted in the flow system downstream of the Beckman cell.
18.1. 21. 3.6. 2 Purification A Gelman Water-I purification unit was installed in the conductivity cell flow loop. The output conductivity of the water from the purification unit was 0.055 y 5/cm, as indicated by the purification units built in the conductivity meter. The water flow was from the purification unit through the two conductivity cells under study and back to the reservoir of the purif ication unit. The output of the conductivity meter Rev. 27, 10/81 18.1-67
SSES-PSAR associated with the irradiated cell vas continuously recorded. The highest radiation field in the 4 1/4 in. irradiation tube, as measured by a Victoreen R Heter, was 7. 4xl0~ R/h. The actual cell energy absorbtion rate at this position was determined by the conductivity element and using the cell holder as a 'emoving Fricke dosimeter container. The result, 9.8xl05 Rads/hr was also used to convert the R/h measurements at the other elevations to Rads/hr by assuming a constant ratio between the field intensity and t.he energy absorbtion. (This is not strictly true as the photon energy distribution varies with the elevation in the irradiation facility. Consequently, the fraction of the photons penetrating the stainless steel cell holder vill vary slightly.) The results of these experiments are summarized in Table 18.1-14. There was apparently some pickup of impurities from the flov loop materials as 0.10 p S/cm was the lowest loop conductivity observed The 0.06pS/cm at the output of the purification unit was confirmed by connectinq one of the flow cells immediately as the output. In the case of the floving measurements, there was a steady increase in conductivity from O.ll to 0.65 p S/cm as the irradiation intensity increased from 1.3xl04 to 6.6x10~ Rads/hr. The conductive species which were formed were relatively stable as there was little difference between the conductivity as measured at the irradiated cell and the downstream cell. In fact, when the flow was stopped and the conductivity of the irradiated cell was allowed to come to equilibrium, the cell could be removed from the radiation field and the conductive would remain constant, at least up to several hours, the longest period observed. The flow was secured at each irradiation intensity and the conductivity was monitored until a steady-state condition was attained. From the data in Table 2 it vould appear that a maximum conductivity is attained at about 2.2 S/cm, and that the conductivity diminishes vith increasing radiation intensity. The steady-state difference in cell behavior at 6.6xl05 and 9.8xl05 Rads/hr is unexplained. Tt is suspected that the conductivity is due to the formation of hydroqen peroxide, but this has not been confirmed. It is obvious that there will be some radiation effect on the conductivity at very hiqh f ission product concentrations. This does not appear too serious, however, as 2.2 p S/cm corresponds to a NaC1 concentration of 1.0 ppm. The concentration of stable f ission products, particularly I-127 and I-129, associa ted with the high Curie concentrations will at the same time result in considerably higher conductivities. Rev. 27, 10/81 18.1-68
SSES-PSAR 18.1. 21.3.6. 3 Conductivity of 10 gym Chloride QC~l- Solution 'Irradiation tests were performed to determine the radiation effect on the conductivity of a dilute NaCl solution. It was anticipated that if the pure water conductivity increases under irradiation were due to the formation of H~O~, this might be suppressed by the presence of the Cl- ions. In this experiment the NaCl solution was pumped from a reservior throuqh the two conductivity cells and back to the reservior. A common conductivity bridge was used to alternately determine the conductance of each cell-, and thereby eliminate any bias between different bridges. The testing was done at the highest available irradiation level, 9.8x105 Rads/hr. The solution temperature, as indicated by a flow thermometer downstream of 'the unirradiated cell, ranged from 59.5 to 60.2oF. Several alternate conductivity readinqs were taken on each cell approximately five minutes after each change in condition, and when the cell conductances had reached a steady value. The average result for each condition is qiven in Table 18.1-15. The difference between the cell readings for any qiven set conditions is attributed to errors in the stated cell constants. The conductivity of the flowing stream increased by approximately 0. 6 S/cm for both cells before and after irradiation, which may bep the result of the generation of some long lived species. This possibly is supported by the Beckman cell, which althouqh located outside the radiation field, showed a 0.6 p S/cm increase in conductivity during irradiation. The puzzlinq observation was the large drop in conductivity of the static solution during irradiation. This should be investiqated further. 18.1. 21. 3.6 4 pH Solutions of pH 3.8 and 10.0 were made up using HC1 and NaOH, respectively. LO-Ion pH test paper was placed. in aliguots of these solutions and the solution was inserted into the 9.8xl0~ Rads/hr position fas determined by Pricke dosimeter) . A 10 0 minute exposure for a total dose of 1.6x10~ Rads completely destroyed the color in the acid solution and reduced the color intensity of the basic solution to a pale green. This test was then repeated using a 1.0 min exposure at the same intensity level for an exposure of 1.6xl0~ Rads. This exposure shifted both solutions about 1/2 pH unit to the more acid side. The results would not necessarily indicate that pH indicator paper cannot be used at the highest dose rates, but more importantly, that the paper cannot be immersed in a relatively large volume of solution. Xf the paper were merely moistened by a drop or so of solution, most of the beta particles would escape the paper with little energy deposition and the paper would not be surrounded by a highly radioactive solution with the resultant beta field and 18 1-69 Rev. 27, 10/81
SSES-FSAR water excitation products. consideration. This subject is still under At source terms on the order of 10% or less of the maximum*, the irradiation effect, for even an immersed strip, would be tolerable at exposures less than 5 min, as it would result in less than an 0.5 pH unit shift. Some measurements were also made to determine the effect of irradiation on pH electrodes. Long leads are needed on the pH electrodes in order to reach in the Co-60 irradiation facility, and these electrodes were not available. We intend to order some new electrodes and will continue this study. In the meantime, we have irradiated a glass membrane pH electrode to 1.6x10& Rads at a 9.85x10& Rad/hr intensity and found following irradiation. it still functions 18.1.21.3.6.5 Turbidmetric Chloride Procedure Using the maximum source term of 2x18& Rads/hr, ml diluted primary coolant sample would have an internal beta exposure of 2x10& Rad/hr. The turbidimetric method calls for a total volume of 25 ml. Therefore, even if the entire 10 ml of diluted sample were used, the dose rate of the final analysis solution would be less than 8xlO& Rad/hr. Test solutions containing 0, 1, 5, and 20 /gm of chloride in 25 ml were processed through the chloride test methods in pairs'uring the 15 min turbidity-formation period, one sample of each set was irradiated at an absorbed dose rate of 4.4xlO& Rad/hr as determined by Fricke dosimetry. The The originally calculated source -term was 1.9x10& Rads/hr. Thirty-five percent of this source intensity, however, is due to noble gases which would escape solution in the sampling process. A 10% source term for pH measurement would then be approximately 1.2xl0& Rads/hr and a 5-min exposure would correspond to a lxlO& Rad energy absorption, which is approximately the exposure causing a 0.5 pH shift. Rev. 27, 10/81 18.1-70
SSES-FSAR maximum observed radiation effect was a. difference of about 10 turbidity units between the irradiated and unirradiated 1 gm Cl solutions. This difference is equivalent to about 10 p/gm of chloride in the 25 ml of solution being processed. Assuming this increase in turbidity is proportional to the dose, the maximum effect would be (10 pgm) {8x103/4.4x105) = 0. 18 gm. Zf only 0.1 ml of reactor water were used -for the original sample, this would be equivalent to 1.8 ppm of Cl- in the primary coolant. This error is probably insignificant as the interference from all the stable iodine associated with the high radiation intensity is likely to be far larger., The test data also indicates that as little as 5 pgm of Cl= in the 25 ml of test solution inhibits the formation of the radiation-induced turbidity. Xt is suspected that the increased turbidity is due to the precipitation of silver peroxide and the 5 pqm Cl- inhibited the formation of hydrogen peroxide. In any event, it was concluded that the test method is useful for hiqhyly radioactive solutions above the 10 ppm level, or for less radioactive solutions above the 1 ppm level. Por low activity samples which do not need to be diluted and where at least a 1 ml of sample is available, the method is useful above the 100 ppb level. 18.1.21. 3.6.6 Carminic Acid Boron Analysis Using the maximum source term of 2xl0~ Rad/hr, an 0.1 ml to 10 al diluted primary coolant sample would have an internal beta exposure of ca. 2xl04 Rad/hr. The colorimetric method calls for a total volume of 25 ml. Therefore, even if the entire 10 ml of diluted solution were used, the dose rate of the final analysis solution would be less than Sxl03 Rad/hr. Test solutions containing 0 and 20 gm of boron were processed through the boron test methods in pairs. During the 40-min color development phase, one sample of each pair was irradiated at an absorbed gamma-radiation dose level of 4.4xl0~ Rad/hr as determined by Pricke dosimetry. The maximum irradiation effect observed was a difference of 0.854 absorbance units between the irradiated an unirradiated blank solutions. This difference is equivalent to about 27 p qm of boron in 25 ml of solution being processed. Assuminq this difference is absorbance is proportional to the dose, the maximum affect would be (27 pgm) (Sxl03/4.4x10~) = 0.49@ qm. If only 0.1 ml of reactor water were used for the original sample, this is equivalent to a 5 ppm error in the primary coolant analysis. This error is totally negligible in terms of the levels of boron required for reactor shutdown. Rev. 27, 10/Sl 18 1-71
SSES-PS AR 18 g 22 TRAINING FOR HITIGhTING CORE DANZIG/ /XI B 0} 18.1.22 1 Statement of Reauirement Licensees are required to develop and implement a training program to teach the use of installed equip~ent and systems to control or mitiqate accidents in which the core is severely damaqed. Shift technical advisors and operatinq personnel from 'the plant manaqer through the operations chain to the licensed operators shall receive all the training indicated in Table 18.1-8. Nanagers and technicians in the instrumentation and control, health phvsics, and chemistry departments shall receive training commensurate with their responsibilities. Applicants for operating licenses should develop a training proqram prior to fuel loadinq and complete personnel training prior to full-power operation. 18.1.22.2 Interpretation None required.
- 18. 1. 22 3 Statement of Response A course titled >>Mitigating Core Damage>> has been developed.
This course or a similar one will have been given to all shift technical advisors and operations personnel from the plant manaqer throuqh the operations chain to and including licensed operators prior to fuel load to outline is fulfill this training provided in Table 18.1-9.. requirement. A course Nanaqers and technicians in instrumentation and controls, health physics, and chemistry will be given training commensurate with their responsibilities during accidents which involve severe core da maqe. Rev. 32, 12/82 18 1- 72
SSZS-ZS AR 18 1 23 ~ BELIEF AND ~SFJTY-VA~LV TEST REQUIBEEENTS
~ ~
/II.D~1 18.1. 23.1 .Statement of Requirement Bailing-water reactor licensees and applicants shall conduct testing to qualify the reactor coolant system relief and safety valves under expected operating conditions for design-basis transients and accidents.
Licensees and applicants shall determine the expected valve operatinq conditions through the use of analyses of accidents and anticipated operational occurrences referenced in Regulatory Guide 1.70, Revision 2. The sinqle failures applied to these analyses shall be chosen so that the dynamic forces on the safety and relief valves are maximized. Test pressures shall be the highest predicted by conventional safety analysis procedures. Reactor coolant system relief and safety valve gualificaiton shall include qualification of associated control circuitry, piping, and supports, as well as the valves themselves. Preimplementation review vill .be based on EPRI, BHR, and applicant submittals with regard to the various test programs. These submittals should'e made on a timely basis as noted below, to allow for adequate review and to ensure that the following valve qualification date can be met: Final BUR Test Program October 1, 1980 will be specific submittals for gualification of safety applicants'lant-Postimplementation review based on the relief valves. To properly evaluate these plant-specific applications, the test data and results of the various programs will also be required by the following dates: BMR Generic Test Program Results July 1, 1981 plant-specific submittals confirming adequacy of safety and valves based on. licensee/applicant preliminary review of generic test program results
'elief July 1, 1981 Plant-specific reports for safety and relief valve qualification--October
'lant-specific submittals 1,for1981 piping and support evaluations January 1, 1982 18 1~23. ~2- I ter~ygytion.
None required. Rev. 27, 10/Sl 18 1-73
SSES-PS AR 3.8.3.. 23. 3 Statement of - Ressonse-PPCT. is participating in the BQB Ov'ner's Group {BMROG) progra'm to test safety/relief valves (SBVs). Hyle Laboratories in Huntsvi3.le, Alabama has been contracted to design and build a test facility. The design is complete and construction is well underway. The facility vill be capable of high .and lov pressure valve tests. Docunentation of the BQBOG testing program was sent to the NBC on September 17, 1980 by a letter from D.B. Haters to R. N. Vollmer. A summary of this document is provided belov. An enqineering evaluation vas done to identify the expected operatinq conditions for SRVs during design basis transients and accidents. This evaluation indicates the SRVs may be required to pass low pressure liquid as a result of the Alternate Shutdown Mode (described in Subsection l5.2.9) . No other significantly probab1e event, even combined with a single active failure or single operator error, produces expected operating conditions that justify qualification of SRVs for extreme operating conditions. Therefore a test program vas developed to demonstrate the SRVs'apabilities as may be necessary during the Alternate Shutdown Node'. The test results were submitted by a letter to A. Schwencer frog N. W. Curtis on July 1, 1981 {PLA-'865). A plant specific SBV qualification report was, submitted to the NRC on October 1 ~ 1981 ) (PLA-900) . This report includes all necessary evaluations of pipinq and supports. l8 l. 20 ~ - SAPRT YQQQLXgg V~LV~OSITZON INDICATION~II D 3). 18 1 70 1 Statement of Reauirement Reactor coolant system relief and safety valves shall be provided with a positive indication in =the control room derived from a reliable valve-position detection device or a reliable indication of flow n the discharge pipe. The basic requirement is to provide the operator vith unambiguous ind cation of valve position (open or closed) so that appropriate operator actions can be taken. The valve position should be indicated in the control room., An alarm should be provided in con/unction with this indication. Rev. 3n, 5y82 18 1-70
SS BS-FSAR The valve position indication may be safety grade. reliable If .the single-position ind,ication is not safety grade, a channel direct indication-powered from a vital instrument bus may be provided if backup methods of determining valve position are available and are discussed in the emergency procedures as an aid to operator diagnosis of an action. The valve position indication should be seismically qualified consistent with the component or system to which it is attached. The position indication 'should be qualified for its appropriate environment (any transient or accident which would cause the relief or safety valve to Commission order on Hay 23rd, lift) and in accordance with the 1980 (CLI-20-81) . It is important that the displays and controls added to the control room as a result of this requirement do not increase the potential for operator error. A human-factor analysis should be performed taking into consideration: fa) the use of this information by an operator during both normal and abnormal plant conditions, (b) inteqraCion into emergency 'procedures, (c) inteqration into operator training, and fd) other alarms during emergency and need for prioritization of ala rms. Documentation should be provided that discusses each item of the clarification, as well as electrical schematics and proposed test procedures in accordance with the proposed review schedule, but in no case less than four months prior to the scheduled issuance of the staff safety evaluation report. Implementation must be completed prior to fuel load. 18.1. 24. 2. In tergretat jon-Hone required. 18 1. 24. 3 Statement of Regponge Each of the 16 safety/relief valves (SBYs) will be provided with a safety qrade acoustic monitoring system to detect flow through the valve. An acoustic sensor will be mounted on the discharge piping, downstream of each valve. Rev. 27, 10/81 1 8.1-75
SS ES- PS AR The monitors will be qrouped into two divisions with 8 valves each. Each division will have qroup annunciation for valve opening and for division loss of power. A red annunciator window will be provided for valve opening and white annunciator window for loss of power on a front row control panel for these vital annunciations. Each division will be powered from a lE instrument bus. Individual indication of an open valve will be provided by a red liqht (1 light for each valve) on front row control room panel 1C601. Individual indication of valve position is also available on a hack row control room panel where the signal conditioning instruments are located. The acoustic monitorinq system is designed to be safety grade. This equipment has been qualified to IEEE-344-1975, IEEE-323-1974 and NUREG-0588 in accordance with the Commission order on May 23, 1980 (CLI-20-81) . Additional desiqn information vill be presented in Subsection
- 7. 6. 1b. 1. 7.
A human factors review of the front row control panel on which these indicators are located has been 'completed. This same analysis is beinq applied to the SRV position indicators which are beinq added to this panel. Installation of this system will be complete by fuel load. For modifications to plant systems and components such as the SRV position indicators, procedures are developed or revised as necessary and appropriate traininq is provided when the final desiqn documents are approved and the equipment is available for use ~ The use of tailpipe temperature detectors in the emergency procedures is discussed in a letter from N. M. Curtis to B. J. Younqblood on April 30, 1981 (PLA-736) . 18 l. 25 AUXILIARY PEEDRATER SYSTEM EVALUATION /II E 1.1) This requirement is not applicable to Susquehanna SES. 18 1 26 AUXILIARY PEEDRATER SYSTEM INITIATION AND FLOM XXI=I=3,~2K This requirement is not applicable to Susquehanna SES. Rev. 31, 7/82 18 1-76
SSES-PSAR 18 1 27 - ENERGENCY POMER FOR PRESSURIZER HEATERS /II E 3~1 This requirement is not applicable to Susquehanna SBS. 18 1 28 DEDICATE/ HYDROGEN PENETRATIONS /II. E 4 1)
- 18. 1. 28. 1 Statement of /equipment Plants 'using external recombiners or purge systems for postaccident combustible gas control of the containment atmosphere should provide containment penetration systems for external recombiner or purqe systems that are dedicated to that service only. These systems must meet the redundance and single-failure requirements of General Design Cr'iteria 54 and 56 of Appendix A'to 10 CPR 50, and that are sized to satisfy the flow requirements of the recombiner or purge system.
The procedures for the use of combustible gas control systems followinq an accident that results in a degraded core and release of radioactivity to the containment must be reviewed an revised, if necessary. Operatinq license applicants must have design changes completed by July 1, l981 or prior to issuance of an operating license, whichever is later.
- 18. l. 28. 2 In teroreta tion None required.
18.1.28.3 Statement ~o Response Susquehanna SES desiqn includes 100'5 redundant internal hydrogen recombiner systems for postaccident combustible gas (hydrogen) control. Therefore this requirement is not applicable to Susqu eha nna SES. Rev. 27, 10/81 1 8. 1-77
SS ES- FS AR 18 ~ 1-29 CONTAINMENT ISOIQQION DEPENDABILITY /II.E.4 2) 18.1.$ 9. 1 Statement of Beguigement (1) Containment isolation system designs shall corn'ply with the recommendations of Standard, Review Plan (SRP) Section 6.2.4 {i.e., that there be diversity in the parameters sensed for the initiation of containment isolation) . (2) All plant personnel shall given careful consideration to the definition of essential and nonessential systems, identify each system determined to be essential, identi'fy each system determined to be nonessential, describe the basis for selection of each essential system, modify their containment isolation desiqns accordingly, and report the results of the reevaluation to the NRC. (3) All nonessential systems shall be automatically isolated by the containment isolation signal. (4) The desiqn of control systems for automatic containment isolation valves shall be such that resetting the isolation signal will not result in the automatic reopening of containment isolation valves. Reopening of containment isolation valves shall require deliberate operator action. (5) The containment setpoint pressure that initiates containment isolation for nonessential penetrations must be reduced to the minimum compatible with normal operating conditions. (6) Containment purqe valves that do not satisfy the operability criteria set forth in Branch Technical Position CSB 6-4 or the Staff Interim Position of October 23, 1979 must be sealed closed as defined in SRP 6.2.4, item II.3. f during operational conditions 1, 2, 3, and 4 Furthermore, these valves must be verified to be closed at least every 31 days. (7) Containment purge and vent isolation valves must 'close on a high radiation siqnal. Applicants for an operating license must be in compliance with positions 1 through 4 before receiving an operating license. Applicants must be in compliance with positions 5 and 7 by July 1 ~ 1981, and position 6 by January 1, 1981 or before they receive their operatinq license, whichever is later for each position. Rev., 27, 10/81 18 1-78
SSBS-PS AR 18~$ . 29. 2 Xnte~gegat+ons Prom item 4, the -opening of containment isolation valves must require a deliberate operator action.. Prom item 5, the containment isolation setpoint pressure should be optimized to prevent unnecessary isolations .during normal operations. However, containment isolation must not be prevented or delayed during an accident. 18 1,29.~Statement-of Re~s onse. Containment, isolation signals are actuated by several sensed parameters (refer to Table 3.3.2-1 in the Technical Specifications) . This complies with'RP Subsection 6.2. 4, Paragraph IE-6. {2) Each process line penetrating containment was reviewed to determine whether it is an essential or non-essential line for purposes of isolation requirements. The classification for each line is given in Table 18.1-10. Justification for the classification as an essential or non-essential line was alamo developed and is provided in Table 18.1-11. Systems identified as essential are those which may be required to perform an indispensable safety function in the event of an accident. Non-essential systems are those not reguired during or after an accident. Since instrument lines are not governed by isolation signals but are equipped with a manual isolation valve followed by an excess flow check valve outside the containment, the review of these lines was limited to ensure compatibility with the penetration listinq in Table 6.2-12a., All lines to non-essential systems are provided with isolation capability. All isolation valves in these lines, except the reactor water clean-up system (RWCU) discharge valves {G33-1PC042 and 1P104 receive auto-isolation signals (refer to Table 18.1-10). The isolation function for the RVCU discharqe lines is provided by three series check valves (141-1F010A,B, HV-14107A,B and 633-1P039A,B) which prevents back flow from the reactor vessel. The RWCU discharge isolation valves are not closed to prevent the loss of the filter cake in the RWCU filter demineralixer system and injection of resin into the vessel on restart of the 'RWCU system. (4) All containment isolation valves, except those listed below, vill not automatically open on logic reset. Some valves Rev. 27, 10/81 18 1-79
SS ES- PS AR require corrective action to camply with this requirement. All such actions will be completed prior to fuel load. Refer to a letter from N. M. Curtis to B. J. Youngblood on April 10, 1981 (PLA-715) for this commitment. An override of any isolation signal will not cause automatic opening of any isolation valve. a) The folloving valves in the Liquid Radwaste, Reactor Mater Sample, and Reactor Building Chilled Mater systems are normally open valves, and vill close upon a containment isolation signal HV-16116 Al 8 A2 HV-16108 Al S A2 HV-18781 Al S A2 S Bl S B2 H V-18782 Al S A2 S Bl S B2 HV-18791 Al S A2 S Bl S B2 HV-18792 Al S A2 S Bl*S B2 B31-1F019 B31-LP020 Mhen the containment isolation logic is reset the above valves would have reopened. The logic for these valves will be modified by fuel load to ensure that they vill not reopen an logic reset. Table 18.1-10 reflects, the modified configuration of these valves. The RCIC and HPCI turbine steam supply line isolation valves (HV-lP007, HV-1P008, HV-1P002 and HV-LF003) are normally open valves and vill close upon a steam line break isolation signaL. These valves are essential valves and do not receive a containment isolation siqnal. Reopening of these valves vill occur if the hand switches are not placed in the closed position by the operator prior to actuation of the reset switch and the isolation parameters have cleared. These valves are equipped with key-locked maintained contact switches to insure that these valves are open durinq BCCS initiat'ion. If a pi,pe break condition vere detected, then these valves vill be automatically closed. After the pipe break problems are cleared these valves can be reopened to their normal emergency positions by deliberate operator action usinq the key-locked. reset switches for each system. The operator is required to ensure that the valve switches are in the correct position prior to operating the keylock reset switch. c) The inboard HPCI and RCIC isolation valves each have a pressure equalization valve (HV-1P100 and HV-1P088j around them. The equalization valves are normally Rev. 30 ~ 5/82 18. 1-80
SS ES- FS AR closed and are only used to equalize the pressure a round the inboard isolation valve in order to open them. If open, the valves vill close upon a steam line break isolation signal. Reopening of these valves vill occur if the hand svitches are not placed in the closed position by the operator prior to actuation of the reset switch and the isolation parameters have cleared. As with the HPCI/RCXC isolation valves the equalization valves vill reopen upon deliberate manual logic reset using the key-locked reset switches. These valves must open in order to allow the inboard isolation valves to reopen to their normal emergency positions when the pipe break problems have cleared. If t;he egualization valve svitches are not i.n the open position the operator must manually open them to egualize the pressure around the inboard HPCI/RCIC valves. The RHR containment isolation valves {HV-1P016A,B, and HV-lF028A,B) associated with the drywell and suppression pool spray lines will reopen if their handsvitches are placed in the open position prior to actuation of the reset switch, the LPCI injection signals are clear, and the LPCI injection valves are closed. These spray line valves are normally closed and are provided key-locked hand switches and receive an isolation siqnal as described in Tables 18.1-10 and 18 1-12. If t: he va1ves were open before an LPCI injection event, these valves vill automatically close and can not be reopened if the LPCI injection signals still exist or the LPCI injection valves are still open. This is to insure that the LPCI injection function vill not be inadvertently jeopardized by openinq of the spray line isolation valves. If these spray line valves were closed before the LPCI injection event. the valves vill remain closed after reset even after all injection signals are clear and the LPCI in jection valve are closed. hs noted in Table 18.1-10 only the outermost valve is considered a containment isolation valve for these penetrations. The three inboard valves HV-lP021A, HV-1P-27A and HV-1P024A are spring return to "AUTO" switches and will not automatically reopen after logic reset and all signals clear. These inboard valves have not been considered containment isolation valves because they can not be leak tested in the "forward" direction. Since these valves ef fectively function as containment isolation valves, a logic reset will not automatically result in a breach of containment inteqrity f or these penetrations. 10/81 18 1-81'
SS ES- FS AR
- 5) The BMR Owners'roup has performed a generic analysis which is summarized as follows. The containment isolation analytical setpoint pressure for Nark I, XI, and XII containments is approximately 2 psig (drywell pressure). Under normal operating conditions, fluctuations in the atmospheric barometric pressure as well as heat inputs {from such sources as pumps} can result in containment pressure increases on the order of 1 psi. Consequently, the isolation setpoint of 2 psiq provides a 1 psi margin above the maximum expected operating pressure. The 1 psi margin to isolation has proved to be a suitable value to minimize the possibility of spurious containment isolation'. At the same time, it is such a low value {particularly in view of the small drywell volume of Nark I, II, and XXX containments) that it provides a very sensitive and positive means of detecting and protecting against breaks and leaks in the reactor coolant system. No chanqe of the setpoint is necessary for these containment types.
PPGL concurs with this position. Therefore, no modif ications to the containment isolation pressure setpoint are necessary in response to this requirement.
- 6) The design of the containment atmosphere purge valves was reviewed against Branch Technical Position CSB6-4.
This review identified several valves that do not meet this criteria. These valves will be qualified to meet this criteria as stated in a letter to B. J. Youngblood from N. Q. Curtis on April 1, 1981 (PLA-700). Valves will be qualified to the interim criteria in NUREG-0737 item XI.E.4.2 by fuel load. Valves will be fully qualified prior to the first refueling. (7) Tvo redundant safety grade radiation monitors are installed down stream of the Standby Gas Treatment System. A high radiation level vill trip the Standby Gas Treatment System. This signal will be used to close the followinq containment isolation val'ves in the vent and purqe system: HV-15703, HV-15704, HV-15705, HV-15711, HV-15713, HV-15714, HV-15721 HV-15722>> HV-15723, HV-15724, HV-15725, SV-15736A, SV-15737, SV-15767 and SV-15776A. The radiation setpoint vill be set to so that the 10CFR
.100 limits are not exceeded. The high radiation alarm for these detectors is annunciated on control room front rov panel 1C653. The radiation level measured by these detectors is recorded on control room backrov panel 1C600.
Rev. 27, 10(81 18 1-.82
SS ES-PS AR These modifications vill be corn'piete by fuel load. 18 1.30 ACCIDENT-NOHITORXNG XNSTRUNENTATIOH (II 7.1) 18.1. 30. 1 Statemeng of Requirement The follovinq equipment shall be added: (1) Noble gas effluent radiological monitor; (2) Provisions for continuous sampling of plant" effluents f or postaccident releases of radioactive iodines and particulates,and onsite laboratory capabilities; (3) Containment high-range radiation monitor; (4) Containment pressure monitor; (5) Containment vater level monitor; and (6) Containment hydroqen concentration monitor. It is important control room as' that the displays and controls added to the result of th'is requirement not increase the potential for operator error. A human-factors analysis should be performed which considers: t (a) the use of this information by an operator luring both normal and abnormal plant conditions, (b) integration into emergency procedures, (c) inteqration into operator training, and (d) other alarms durinq emerqency and need for prioritization of alarms. Each piece of equipment is further discussed below. 18.1. 30. 1.1 Noble Gas Ef fluent monitor Noble. qas effluent monitors shall be installed with an extended ranqe designed to function during accident conditions as veil as durinq normal operating conditions. multiple monitors are considered necessary to cover the ranges of interest. Rev. 27, 10/Sl 1 8.1-83
SSES-PS AR (1), Noble gas effluent monitors with an upper range capacity of 10~ p Ci/cc (Xe-133) are considered to be practical and should be installed in all operating plants. (2) Noble qas effluent monitoring shall be provided for the total range of concentration extending from normal condition {as low as reasonably achievable concentrations to a maximum of 10~ p Ci/cc (Xe-133) . Nultiple monitors are considered to be necessary to cover the ranqes of interest. The range capacity of individual monitors sho'uld overlap by a factor of ten. Licensees and licensing applicants should have available for review the final design description of the as-built system, includinq piping and instrument diagrams together with either (1) a description of procedures for system operation and calibration, or (2) copies of procedures for system operation and calibration. License applicants will submit the above details in accordance with the proposed review schedule, but in no case less than four months prior to the issuance of an operating license.
- 18. l. 30. 1. 2 Sa mgli~n a nd An algsis of Plant Ef f1 uen ts Because iodine qaseous effluent monitors for the accident condition are not considered to be practical at this time, capability for effluent monitorinq of radioiodines for the accident condition shall be provided with sampling conducted by adsorption on charcoal or other media, followed by onsite laboratory analysis.
Licensees shall provide continuous sampling of plant qaseous effluent for postaccident releases of radioactive iodines and particulates to meet the requirements of Table II.P.1-2 in NUREG 0737. Licensees shall also provide onsite laboratory capabilities to analyze or measure these samples. This requirement should not be construed to prohibit design and development of radioiodine and particulate monitors to provide online samplinq and analysis for the accident condition. If qross gamma radiation measurement techniques are used, then provisions shall be made to minimize noble gas interference. The shieldinq desiqn basis is qiven in Table IX.P.1-2 of NUREG 0737. The samplinq system design shall be such that plant personnel could remove samples, replace sampling media and transport the samples to the onsite analysis facility with radiation exposures that are not in excess of the criteria of GDC 19 of 5-rem whole-body exposure and 75 rem to the extremities during the duration of the accident. Rev. 27, 10/Sl 18. 1-84
SSES-FS AR The design of the systems for the sampling of particulates and iodines should provide for. sample nozzle entry velocities which are approximately isokinetic (same velocity) with expected induct or instack air velocities. For accident conditions, sampling may be complicated by a reduction in stack or vent effluent velocities to below design levels, making it necessary to, substantially reduce sampler intake flow rates to achieve the isokinetic condition. Reductions in air flow may well be beyond the capability of available sampler flov controllers to maintain isokinetic conditions; therefore, the staff will accept flov control devices which have the capability of maintaining isokinetic conditions vith variations in stack or duct design flow velocity of +20%. Further departure from the isokinetic condition need not be considered in design. Corrections for non-isokinetic sampling conditions, as provided in Appendix C of ANSI 13.l-1969 may be considered on- an ad hoc basis. Effluent streams which may contain air vith entrained water, e.g. air ejector discharqe, shall have provisions, e.g., heaters, to ensure that the adsorber is not degraded while providing a representative sample. License applicants will submit final design details in accordance vith the proposed review schedule, but in no case less than four months Prior to the issuance of an operating license. n 18.1. 30 1.3 Containment High-Range Radiation Monitor In containment radiation-level monitors vith a maximum range of l0~ rad/hr shall be installed. A minimum of tvo such monitors that are physically separated shall be provided. Monitors developed and qualified to function in an accident shall'e environment. The specification of 10~ rad/hr in the above position vas based on a calculation of postaccident containment radiation levels that include both particulate (beta) and photon (qamma) radiation. A radiation detector that responds 'to both beta and gamma radiation cannot be qualified to post-LOCA floss-.,of-coolant accident) containment environments but qamma-sensitive', instruments can be so qualified. In order to follov the course of an accident. a containment monitor that measures only gamma radiation is adequate. The requirement vas revised in the October 30, 1979 letter to provide for a photon-only measurement vith an upper ranqe of l0~ R/hr. The monitors shall be located in containment(s) in a manner as to provide a reasonable assessment of area radiation conditions inside containment. The monitors shall be widely separated so as to provide independent measurements and shall <<view<< a large Rev. 27, 10/81 1 8. 1-85
fraction of the containment volume. Monitors should not be placed in areas which are protected by massive shielding and should be reasonably accessible for replacement, maintenance, or calibration. Placement hiqh in a reactor building dome is not recommended because of potential maintenance difficulties. The monitors are required to respond to gamma photons with enerqies as low as 60 keV and to provide an essentially flat response for gamma enerqies between 100 keV and 3 NeV, as specified in Table II.F.1-3 of NUREG 0737. Monitors that use thick shieldinq to increase the upper range will under-estimate postaccident radiation levels in containment by several orders of magnitude because of their insensitivity to low energy gammas and are not acceptable. License applicants will submit the required documentation in accordance with the appropriate review schedule, but in no case less than four months prior to the issuance of the staff evaluation report for an operatinq license. 18.1.30.l.l Containment Pressure Monitor continuous indication of containment pressure shall be provided in the control room of each operating reactor. Measurement and indication capability shall include three times the design pressure of the containment for concrete, four times the design pressure for steel, and -5 psiq for all containments. Operatinq license applicants with an operating license dated before January 1, 1982 must have design changes completed by January 1, 1982; those applicants with license dated after January 1, 1982 must have all design modifications completed before they can receive their operating license. Documentation is due 6 months for the expected date of operation.
- 18. l. 30. 1. 5 Cogtagnment Wat'ry Level Monitor A continuous indication of containment water level shall be provided in the control room for all plants. A wide range instrument shall be provided to cover the range from the bottom to 5 feet above the normal water level in the suppression pool.
The containment vide-range water level indication channels shall meet appropriate design and qualification criteria. The narrow-ranqe channel shall meet the requirements of Regulatory Guide
- l. 89.
For BWR pressure-suppression containments, the emergency core coolinq system suction line inlets may be used as a starting Rev. 27, 10/81 18 1-86
SS ES-FS AB reference point for the narrow-range and wide-range water level monitors, instead of the bottom of the suppression pool. The accuracy requirements of the water level monitors shall be provided and justified to be adeguate for their intended function. Operating license applicants with an operating license date before July 1, 1981 must have desiqn changes completed by July 1, 1981, whereas those applicants with license dates past July 1, 1981 must have all design modifications completed before they can receive their operaitnq license. Submittals from operatinq reactors, licensees and applicants for operating licenses fwith an operating license date before January 1, 1982) shall be provided by January 1, 1982. Applicants with operatinq license dates beyond January 1, 1982 shall provide the required desiqn information at least 6 months before the expected date of operation. 18,$ . 3 0. 1. 6 Containment Hydrogen Monitor A continuous indication of hydrogen concentration in the containment atmosphere shall be provi'ded in the control room. Measurement capability shall be provided over the range of 0 to 10% hydrogen concentration under both positive and negative ambient pressure. Operating license applicants with an operating license date before January 1, 1982 must have design changes completed by January 1, 1982 must have all desiqn modifications completed before they can receive their operating license. Operatinq reactors and applicants for operatinq license receiving an operatinq license before January 1, 1982 will submit documentation before January 1, 1982. Applicants with operating license issued after January 1, 1982 shall provide the required design information at least 6 months prior to the expected date of operation. 18.1.30.2 Zntegggetation None required. 18 1-87 Rev. 27, 10/81
SS ES-FS AR 18.1. 30. 3 Statement of Response The response for each equipment requirement is given below. All equipment will be installed by the reguired dates. A human factors evaluation vill be performed for changes that involve control room instrumentation. Drawings shovinq the location of equipment vere submitted in a letter from N. W'. Curtis to A. Schve neer on June 15 f P1.A-842) . For modifications to plant systems and components such as addition of nev post-accident, monitoring capability, procedures are developed or revised as necessary and appropriate training is provided vhen the final design documents are approved and the equipment is available -for use. 18 1,30.3. 1 Noble - Gas F.f flu erat Nonitor Each of the five plant vents vill be monitored by an Eberline Model FAAM (Fixed Airborne Activity Monitor) . The FAAM's analyze representitive samples which are provided by isokinetic probes vhich are in compliance with ANSI 13.1-3.969. Each FAAM has three noble gas detectors which provide overlapping ranges of 1 x 10-~ Ci/cc to 1 x 10~ pCi/cc for Xe-133 qas. The sample stream is filtered by a HEPA filter and a charcoal filter, vhich are contained in a SA-13 assembly before passing the noble gas detectors. The charcoal filter can be replaced vith a silver zeolite filter when required. The plant effluent noble qas data is continuously monitored and stored in solid state memory. The flov through the sample line is also measured and stored in solid state memory. The FAAM then calculates and stores active.ty per unit of volume. This information can be displayed upon request and is periodically printed out for record keeping purposes. This information is displayed and recorded on backrow panel 1C669. High activity alarms for the reactor and turbine buildings vill be annunciated on control room front rov panel lC651. High activity alarms for the Standby Gas Treatment System will be annunciated on control room front rov panel 1C601. The lov-range noble gas channel is calibrated using Kr 85 and Xe 133 qas standards traceable to the National Bureau of Standards. The mid-range noble 'qas channel is calibrated using a Cs 137 stick source. The hiqh-ranqe noble gas channel is calibrated using a Kr 85 qas standard traceable to the National Bureau of Standards. Rev. 27, l0/81 1 8.1-88
SS ES-PS AR The system is powexed from non-class IE instrument AC power. An independent battery backup is- provided which is capable of power for 8 hours. 'rovidinq This equipment is installed and will be operational by fuel load. l8.1,30.~ - ~S~mli~n and Ana~lis of Plant~ffluents Each of the five plant,. vents has a continuous isokinetic sample drawn from it in accordance with ANSI-N13.1. Each sample's then taken through short runs of heat traced tubing to a Eberline Model PAAM (Fixed Airborne Activity Monitor). In the PAAM the sample stream then passes through a HEPA filter which removes particulates. Upon leaving the HEPA filter the sample stream passes through a charcoal filter which -removes iodines. When required this filter can be replaced with a silver zeolite filter. Capabilities for purging the sample line with compressed air are provided under manual control. The sample stream is next measured for noble qas activity and then returned to the plant vent. During normal operation the HEPA and charcoal filters are monitored by radiation detectoxs and this information is presented to 'the operator .in the'ontrol room;.. Under accident conditions these detectors will saturate and the filters must be removed, placed in a shielded container, and analyzed in a laboratory. The PAAM also has provisions for obtaining a grab sa mples. The isokinetic sample is in compliance with ANSI-N13.1-1969. To accomplish this, each vent has an air profile (final gas , treatment) station to eliminate turbulent and rotating gas flow. The average stack velocity and volume are then measured by means of a multipoint, self-averaging Pitot transverse station. An air flow controller then simultaneously withdraws a multipoint sample under isokinetic flow conditions by means of an isokinetic sample rack., This isokinetic sample is .then directed to the Final Airborne Activity Monitor. The system is designed such that plant personnel can remove samples, xeplace sample media and transport the samples in shielded containers to an analysis facility. Radiation exposures for this process are not in excess of 3 rem whole-body exposure and 18.5 rem to the extxemities during the-duration of the accident. Procedures for analyzing samples both normal and accident conditions are described in Subsection 12.5.3.5.5. The equipment used to analyze these samples is described in Subsection 1.2.5.2.7.1. Additional instrumentation and procedures for samplinq and analyzing implant iodine are described in Subsection
- 18. 1 70.
Rev. 27, 10/81 18 1-89
SS ES- FS AR The installation plant vent samplinq and monitoring system is complete. 18.$ . 30.3.3 Cogfagggegg Hj'g~gygge Radiation'onjtoredundant Class 1E in-containment radiation monitors will be I provided. The monitors will be General Atomic high rang'e radiation monitors. These monitors are capable of measuring radiation levels of 1R/hr to 1 x 108 R/hr (Gamma) f or photon = energies of between 80 KeV to 3 MeV. An accuracy of + 20% is obtained on lower decades. The detectors vill be unshielded and physically separated on opposite sides of the reactor pressure vessel. Loqarithmic indicating recorders will be provided for Channels A and 8 on front row panel 1C601. A common red high radiation annunciator for both channels will be provided on control room front row panel 1C601. A common white system trouble liqht will also be provided for both channels on control room front row panel 1C601. The containment radiation monitorinq system is designed to be safety qrade. This equipment will be qualified to IEEE-344-1975, IEPE-323-1974 and NUREG-1588 in accordance with the Commission order on May 23rd, 1980 (CLI-20-81) . The installation of the containment radiation monitoring system w ill be comple te by f uel load. 18.1. 30. 3.4 Containment Pressure Monitor Two Class 1F. redundant drywell chamber pressure measurements will be provided as follows: SERVICE /ANGE LOCA Range 0 to 65 psia HI Range 0 to 250 psiq The LOCA and HI ranges are divided into two divisions. Continuous, individual indication of all four Division I and II pressure measurements will be provided by inBicating recorders for the operation on front row panels 1C601. Normal operatinq pressures in the drywell, and wetwell are monitored by a -1 to +3 psiq instrument installed in each Rev. 31, 7/82 18 1- 90
SSES-FS AR chamber. An indicator on control panel 1C601 vill display these pressures. A selector switch is provided to allow the operator to monitor either dryvell or vetvell pressure. These instruments are non-safety qrade with the exception of the transmitters, which.are designed to meet containment pressure boundary service. The accuracy of these instruments is + 2'5 of full scale. The cantainment accident range pressure monitors are designed to be safety qrade. This equipment will be qualified to IEEE-344-1975, IEEE-323-1974 and NUREG 0588 in accordance vith the Commission order on Nay 23rd, 1980 (CLI-20-81). The containment pressure instrumentation will be installed by fuel laad. l 18.1. 30. 3. 5 Containment Qater Level Nonitar Redundant wide and narrov range safety grade instruments will be installed to continuausly monitor suppression pool vater level. The channel A measurements, will be displayed on control room front rov panel 1C601. The channel B measurements vill be recorded on front row panel 1C601. The narrow range instruments measure between 18 and 26 feet. The vide range instruments measure between 4.5 and 49 feet. This covers the required range of from the lowest ECCS suction to 5 feet above normal water level. Normal vater level is approximately 23 feet. The accuracy of these instruments is +2% of full scale. Installation of the suppression pool water level instrumentation will be complete by January 1982. 18 1~~0. ~6 Cogtaj,~ent Hydg~oen -~onitor Continuous and redundant indication and recording of hydrogen vill be provided on control roam front rov panel 1C601. instruments'vill have a range of 0 to 30%. These The containment hydrogen monitoring system is designed to be safety qrade. The equipment vill be qualified to IEEE-344-1975/ IEEE-323-1974 and NUREG-0588 in accordance with the Commission order on May 23rd, 1980 (CLX-20-81) . The accuracy of these instruments is +2% of full scale. Rev. 30, 5/82 18. 1-91
SS ES-PS AR Installation of the hydrogen monitoring instrumentation will be I complete by fuel load. 18 1 31 XNSTBUNEHTATXON FOR DETECTION OP INADEQUATE CORE COOLING (II P 2l
- 18. 1. 31. 1 Statement of geguigement.
Licensees shall provide a description of any additional instrumentation or controls (primary or backup) proposed for the plant to supplement existing instrumentation {including primary coolant saturation monitors) in order to provide an unambiguous, easy-to-interpret indication of inadequate core coolinq {ICC) . A description of the functional design zequirements for the system sha11 also be included. A description of the procedures to be used with the proposed equipment, the analysis used in developing these procedures, and a schedule for installing the equipment sh all be pro v ided. 18 1.31 2 Interpretation None required. 18 l. 31. 3 Statement D ~ of Response 9 The Susquehanna SES reactor vessel water level instruments utilize redundant cold reference legs. The reference legs are connected to redundant and diverse level instru ments by parallel instrument lines. The level instruments provide a range of measurement from below the active fuel to above the main steam lines. The fuel zone instruments are calibrated to LOCA conditions. This configuration provides optimum performance for all operatinq conditions and credible transients. The reactor vessel water level instruments are standard for .BMR/5's and later BWR/4's and were evaluated by the BMR Owners'roup and found to be adequate to detect inadequate core cooling (ICC) . This instrumentation is described and documented in NFD0-24708,
~'Additional Information Reguired for NBC Staff Generic Report on Boiling Mater Reactors<. Since the present design uses the optimum reference leg confiquration, no additional instrumentation or modifications to instrumentation are needed for detection of ICC.
Symptom based procedures are being developed {in response to requirement I. C. 1) f or if proper ident ication of:KCC. These Rev. 30, 5/82 18.1-92
SS ES-FS AR procedures will assist the operator in detecting the approach to ICC. Refer to Subsection 18.1.8 for the response to requirement I ~ C 1 PPSL has developed a Display Control Sub-system (DCS) format to promote operator detection of i.nadeguate core cooling. The format consists of three distinct functional areas: a graphic representation of reactor water level, a twenty minute reactor water level trend, and water level supporting data. The graphic display will provide a qualitative representation of reactor water level from -150 to + 170 inches relative to instrument level zero. Several vessel components are statically depicted as points of reference. The water level indication is normally displayed in yellow, however, of level decreases to or below -38 inches it will turn from yellow to red. The reactor water level trend portion of the display will provide a twenty-minute history, in one minute increments, of the water trend. Slowly increasing or decreasing levels should be apparent from this trend. The trend display will turn from yellow to red if the level decreases to or below -38 inches. Other supportive data, which may be useful in monitoring reactor water level, has also been pro vided. The format is sub ject to possible revisions or refinements, however, the f undamental concept of graphically indicating reactor water level will always be provided by the display. A typical format sample is provided in Figure 18.1-16. 18 1- 32 EMERGENCY POWER FOB PRESSURIZER EQUIPMENT~II.G.l} This requirement is not applicable to Susquehanna SES. 18,1,33 'EvIEN EsF vALvEs XII K 1 5} No requirement stated in NUREG 0737. Refer to Subsection 18. 2.25 which contains the response to the requirement in NUREG 0694.
- 18. 1 34 OPERABILITY STATUS I
/II. K 1.10}
No requirement stated in NUREG 0737. Refer to Subsection 18. 2.26 which contains the response to the requirement in NUREG 0694. Rev. 27, 10/81 18 1-93
SS ES-FS AR 18 l. 35 TRIP PRESSURIZER LOM-LEVEL COINCIDENT SIGNAL BISTABLES
~
~II K. 1 17)
This requirement is not applicable to Susquehanna SES. 18 1 36 OPERATOR TRAIHIHG FOR PROMPT MANUAL REACTOR TRIP (II K.l 20) This requirement is not applicable to Susquehanna SES. 18 1 37 AUTOMATIC SAFETY GRADE ANTICIPATORY REACTOR TRIP (II. K..1 211 This requirement is not applicable to Susquehanna SES. 18 $ . 38 AUXILIARY HEAT~EMOVAL SYSTEM PROCEDURES /II l.K 22'o requirement stated in NUREG 0737. Refer to Subsection 18.2.30 vhich contains the response to the requirement in NUREG 0694. 18 1 39 REACTOR VESSEL LEVEL PROCEDURES III.K 1.23'l
~ ~
No requirement stated in NUREG 0737. Refer to Subsection 18.2.31 which contains the response to the requirement in HUREG 0694. 18 1 40 COMMISSION ORDERS ON BABCOCK AND WILCOX PLANTS /II. K 2Q These requirements are not applicable to Susquehanna SES. 18 1 41 AUTOMATIC POMER-OPERATED RELIEF VALVE ISOLATION SYSTEM /II. K~ 3 This requirement is not applicable to Susquehanna SES. Rev. 27, 10/81 18 1-94
SS ES-FS AR 18.1 42 REPORT ON POWER-OPERATED RELIEF VALVE FAILURES (II K.3.2)- This requirement is not applicable to Susquehanna SES. 18.1 43 REPORTING SAFETY/RELIEF VALVE FAILURES AND CHALLENGES /II~ K,3 3) No requirement stated in NUREG 0737. Refer to Subsection 18.2.33 which contains the response to the requirement in NUREG 0694. 18 1 44 AUTOMATIC TRIP OF REACTOR COOLANT PUMPS DURING A LOCA '/II. K 3. 5} This requirement is not applicable to Susquehanna SES. 18.1 45 EVALUATION OF POWER-OPERATED RELIEF VALVE OPENING PRQQABILZTY /II. K. 3 7g This requirement is not applicable to Susquehanna SES. 18.1.46 PROPORTIONAL 'INTEGRAL DERIVATIVE CONTROLLER MODIFICATION /II K Q. 9g This requirement is not applicable to Susquehanna SES. 18 l. 47 PROPOSED ANTICIPATORY TRIP MODIFICATION ~IX K 3 10) This requirement is not applicable to Susquehanna SES. 18 1 48 POWER OPERATED RELIEF VALVE FAILURE RAT~EII K 3 llew This requirement is not applica'ble to Susquehanna SES. 18.1.49 ANTICIPATORY REACTOR TRIP ON TURB1NE TRIP XII-K 3.1&2 This requirement is not applicab'le to Susquehanna SES. Rev. 27, 10/81 18.1-95
SS ES-FS AR 18 1. 50 SEPARATION OF HIGH PRESSURE COOLANT INJECTION AND REACTOR CORE ISOLATION COOLING SYSTEM INITIATION LEVELS
/IX ~ K 3~13}
18.1. 50.1 Statement of Requgpement Currently, the reactor core isolation cooling (RCIC) system and the high-pressure coolant injection (HPCZ) system both initiate on the same low-water-level signal and both isolate on the same high-water-level signal. The HPCI system will restart on low water level but the RCIC system will not. The RCIC system is a low-flow system when compared to the HPCI system. The initiation levels of the HPCI and RCIC system should be separated so that the RCZC system initiates at a higher water level than the HPCI system. Further the initiation loqic of the RCXC system should
~
be modified so that the RCIC system will restart on low water level. These changes have the potential to reduce the number of challenges to the HPCI system and could result in less stress on the vessel from cold water injection. Analyses should be performed to evaluate these changes. The analyses should be submitted to the NRC staff and changes should be implemented justified by the analyses. if All applicants for operating license should submit the results of an evaluation and proposed modifications four months prior to the expected issuance of the staff safety evaluation report for an operatinq license or four months prior to the listed implementation date (July 1, 1981), whichever is later. 18 l. 50. 2 I n te rprety tip n None required. 18.1. 50. 3 Statement o f Response PPSL concurs with the BMR Owners'roup position on the separation of the HPCI and RCXC setpoints which was transmitted to the NRC by letter from R. H. Buchholz (GE) to D. G. Eisenhut (NRC), October, 1, 1980 (NFN-169-80) . This letter forwarded a GE study which showed that HPCI and RCIC initiations at the current low water level setpoints is within the desiqn basis thermal fatigue analysis of the reactor .vessel and its internals. Separatinq HPCI and RCIC setpoints as a means of reducing thermal cycles has been shown to be of negligible benefit. In addition, raisinq the RCIC setpoint or lowering the Rev. 27, 10/81 18 1-96
SSES-FS AR H'PCI setpoint have undesirable consequences which outweigh the benefit of the limited reduction in thermal cycles. Therefore, when evaluated on this basis, PPGL concludes that no change in RCIC or HPCI setpoints is required. PPGL also concurs with the BMR Group position that RCIC restart automatically f olloving a trip of the system at Owners'hould hiqh reactor vessel water level. This position was transmitted to the NRC by letter from D. B. Maters (BM ROG) to D. G. Eisen hut (NRC), December 29, 1980. PPGT. vill implement detail in the the recommended option 2 vhich is described study forvarded with the BMR Owners'roup in GE position. Implementation is discussed in a letter from N. W. Curtis to B. J. Younqblood on May 20 ~ 1981 (PLA-792) . 18 1 51 MODIFY BREAK-DETECTION LOGIC TO PREVENT SPURIOUS ISOLATION OF HIGH PRESSURE COOLANT INJECTION AND REACTOR CORE ISOLATION COOLING /II-K.3. 15) 3.8.1.51.1 Statement of geguirement The hiqh-pressure coolant injection (HPCI) and reactor core isolation cooling (RCIC) systems use differential Pressure sensors on elbov taps in the steam lines to their turbine drives to detect and isolate pipe breaks in the systems. The pipe-break-detection circuitry has resulted. in spurious isolation of the HPCI and RCIC systems due to the pressure spike which accompanies startup of the systems. The pipe-break-detection circuitry should be modified se that pressure spikes resulting from HPCI and RCIC system initiation will not cause inadvertent system isolation. All apnlicants for operating license should submit documentation four months prior to the expected issuance of the staff safety evaluation report for an operating license or four months prior to the listed implementation date (July 1, 1981), whichever is later. 18.1.51.2 Interpretation None required. Rev. 27, 10/Sl 18 1-97
SSES-FS AR 18.1. 51. 3 Statement of Response The BWR Owners'roup has performed an evaluation and recommends the follovinq modification to the steamline break detection loqic. In order to minimize inadvertent HPCI/RCIC isolation due to pressure transients durinq system initiation, a time delay relay, set at approximately three (3} seconds, is to replace the existinq relay in the steamline high differential pressure circuitry. The time delay feature assures that the steamline break isolation signal is, in fact, due to continuous high steam flow. See Subsections 7.3.1.1a.1.3.4, 7.6.la.4.3.3.4.2 and Fig. 18.1-13. The time delay relay shall be class lE, vith an adjustable time delay settinq of 0-5 seconds. This classification is compatible with the system's existing circuitry. Tvo time delay relays are required for the trip system logic for both the HPCI and RICI systems. A desiqn assessment study shall confirm the appropriate time-delay settinq. Implementation is discussed in a letter from N. W. Curtis to B. J. Younqblood on Hay 20. 1981 {PJ.A-792) .
- 18. l. 52 REDUCTION OP CHALLENGES AND FAILURES OP RELIEF VALVES
/II. K- 3 1~6 18.1. 52. 1 Statement= of Requirement
- The record of relief-valve failures to close for all boiling-vater reactors {BWRs) in the past 3 years of plant operation is approximately 30 in 73 reactor-years (0.41 failures per reactor-year) . This has demonstrated that the failure of a relief valve to close vould be the most likely cause of a small-break loss-of-coolant accident (LOCA) . The high failure rate is the result of a high relief-valve challenge rate and a relatively high failure rate per cha1lenge (0.16 failures per challenge) . Typically, five valves are challenged in each event. This results in an equivalent failure rate per challenqe of 0.03. The challenge and failure rates can be reduced in the following ways:
{1) Additional anticipatory scram on loss of feedvater, (2) Revised relief-valve actuation setpoints, (3) Increased emerqency core cooling (ECC) flov, (4) Lover operatinq pressures, (5) Earlier initiation of ECC systems
'- 18 98 Rev. 32, 12/82
SS ES-FS AR {6) Heat removal throuqh emergency condensers, (7) Offset valve setpoints to open fewer valves per challenge, (8), Installation of additional relief valves with a block- or, isolation-valve feature to eliminate opening of the safety/relief valves (SRVs), consistent with the ASME Code, (9) Xncreasinq the high steam line flow setpoint for main isolation valve (MSIV) closure, steam'ine (10) Lowering the pressure setpoint for MSXV closure, (ll) Reducing the testing frequency of the NSXVs, (12) Nore-strinqent valve leakaqe criteria, and (13) Early removal of leakinq valves An investigation of the feasibility and contraindications of reducinq challenges to the relief valves by use of the aforementioned methods should be conducted. Other methods should also be included in the feasibility study. Those changes which are shown to'reduce relief-valve challenges without compromising the performance of the relief valves or other systems should be implemented. Challenges to the relief valves should be reduced substantially (by an order of magnitude) . Results of the evaluation shall be submitted April 1, 1981 for staff review. The actual modification shall by be accomplished during the next scheduled refuelinq outage following staff approval or no later than 1 year following staff approval. Modification to be implemented should "be documented at the time of implementation. 18 1 52.2 Interpretation None required.
- 18. l. 52. 3 Sta tement o f Response The BWR Owners~ Group (BWROG) has performed an eva1uation and developed recommendations to comply with this requirement. These recommendations were transmitted by a letter from B. D. Waters to D. G. Eisenhut on March 31, 1981. This evaluation shows that Crosby SRVs (as will be installed in Susquehanna) have a probability of sticking open which is approximately a factor of ten less than the three staqe Target Rock valves. Xt is our Rev. 27, 10/81 1 8.1-99
SSES-FS AR understanding that the goal of this requirement is to reduce the probability of a stuck open SRV by a factor of 10 relative to a reference valve, which is the Target Rock valve. Therefore we meet the intent of this requirement without modifications. Implementation of the modification proposed by the BQROG will,not significantly reduce this failure probability. Therefore no modifications are necessary in response to this requirement., 18.1.53 REPORT ON OUTAGES OF EMERGENCY CORE COOLING SYSTEMS (II~ K 3 171 1 18.1.53.1 Statement of Requirement Several components of the emergency core-cooling (ECC) systems are permitted by technical specifications to have substantial outage times (e.q., 72 hours for one diesel-generator; 14 days for the HPCI system) . In addition, there are no cumulative outage time limitations for ECC systems. Licensees should submit a report detailinq outaqe dates and lengths of outages for all ECC systems for the last 5 years of operation. The report should also include the causes of the outaqes (i.e., controller failure, spurious isolation) . 18.1. 53. 2 Interpretation Hone required. 1 8. 1. 53. 3 Stat emen~og Re~sonse PPSL vill submit a report which summarizes emergency core cooling system outages accumulated during the first five years of ti opera o n. 18 1- 54 MODIFICATION OF AUTOMATIC DEPRESSURIZ ATION SYSTEM LO GIC g II. K. 3. 1 8} 18.1. 54. 1 Statement of Requirement The automatic depressurization system (ADS) actuation logic should be modified to eliminate the need for manual actuation to assure adequate core coolinq. A feasibility and risk assessment study is required to determine the optimum approach. One Rev. 27, 10/81 18.1-100
SS ES-FS AR possible scheme that should be considered is ADS actuation on lov reactor-vessel water level provided no high-pressure coolant injection or high-pressure coolant system flov exists and a low-pressure emergency core coolinq system is running. This logic would complement, not'replace, the existing ADS actuation logic. Applicants- for operating license shall provide results of l feasibility study year prior to issuance of operatinq license. A description of the proposed modification for staff approval is required four months prior to issuance of an operatinq license. 18.1. 54. 2 Interpretation The ADS actuation logic may not be automatically actuated for steam line breaks (SLB) outside containment. The operator must manually actuate the ADS after diagnosing. that an SLB has occurred. The ADS actuation loqic should. be modified to provide automatic actuation for all Design Basis Accidents. Pennsylvania Power 6 Light Company adopts th'e BWR Owners Group position (date February 5, 1982) on delaying ADS modifications until the completion of a study by General Electric Company. The study is scheduled for completion by 9/30/82. As stated in a letter from N Q. Curtis to A. Schwencer.on June 17, 1981 (PLA-851), the required system modifications installed prior to the startup following the first refueling vill be outage for Unit 1 and prior to fuel load for Unit 2 contingent on the results of the GE study and contingent upon delivery of qualified equipment. 18.1.55 RESTART OF CORE SPRAY AND LOW PRESSURE COOLANT INJECTION The core-spray and low-pressure, coolant-injection {LPCI) system flow may be stopped by the operator. These systems will not restart automatically on loss of water level if an initiation signal is still present. The core spray and LPCl system logic should be modified so that these systems vill restart," required, to assure adequate core cooling. Because this design if modification affects several core-cooling modes under accident Rev. 30, 5/82 18 1- 10 1
SS BS- PS AR conditions, a preliminary design should be submitted for staff review and approval prior to making the actual modification. All applicants for operating license should submit documentation four months prior to the expected issuance of an operating license or four months prior to the listed implementation date, whichever is later. 18.1. 55. 2 Interpretation None required. 18.1.55. 3 Statement of Ee~sonse PPSL concurs with the BMR Owners~ Group position which was forwarded to the NRC by letter from D. B. Maters (BMROG) to D. G. Eisen hut f NRC), December 29, 1980. The BMROG report states that the current ECCS design represents the optimum approach to BRR safety. No modifications to existing LPCI and core spray systems are necessary in response to this requirement. 18 1 56 A UTOHATIC SQITCHOVER OP REACTOR CORE ISOLATION COOLING SYSTEN SUCTION /II K 3 22) 18.1.56 1 Statement of Eeguig~ment The reactor core isolati'on cooling (RCXC) system takes suction from the condensate storage tank with manual switchover to the suppression pool when the condensate storage tank level is low. This switchover should be made automatically. Until the automatic switchover is implemented, licensees should verify that clear and cogent procedures exist for the manual switchover of the RCIC system suction from the condensate storage tank to the suppression pool. Documentation must be submitted four months prior to issuance of the staff safety evaluation report or four months prior to the implementation date, whichever is later. Hodifications shall be completed by January 1, 1982.
- 18. 1-102 Rev. 27, 10/81
SS ES- FS AR None required. Manual switchover of the RCIC suction from the condensate storage tank (CST) to the suppression poo3. on lov CST level is covered in the Emergency Operating Procedures. Specifically, this item is addressed in the folloving Emergency Operatinq Procedures: EO-00-022 (Cooldovn) Section 2.C. EO-00-023 (Containment Control) Section 2. D. This procedural guidance is an interim measure and vill be revised to discuss automatic switchover of the RCIC suction vhen the desiqn chanqe is implemented. The desiqn chanqes for automatic svitchover are being developed. All modifications vill be completed by January 1982. 18.1.57 CONFIRM ADEQUACY OF SPACE COOLING FOR HIGH PRESSURE COOLANT'INJECTION AND REACTOR COB/ X~SAT~IN CQQLI NG SY ST EMS g IX. K 3. 24) 18.1. 57. 1 Statement ~o-geguigement-Lonq-term operation =of the reactor core isolation cooling {RCIC) and high-pressure coolant infection {HPCI) systems may require space coolinq to maintain the pump-room temperatures within allowable limits. Licensees should verify the acceptability of the consequences of a complete loss of alternating-current {AC) power. The RCIC and HPCI systems should be designed to vithstand a complete loss of offsite AC pover to their support systems, including coolers, for at least 2 hours. All applicants for operatinq license should submit documentation four months prior to the expected issuance of the staff safety evaluation report for an operating license or four months prior to the listed implementation date, vhichever is .later. Rev. 30, 5/82 18 1-103
SSES-FSAR
- 18. l. 57. 2 In te @greta t ion Confirm that HPCI and RCIC room cooling can be maintained to enable continuous operation d.uring a loss of offsite AC power for 2 hours.
18.1. 57. 3 Statement. of Response The HPCI and RCIC room unit coolers and their support systems are designed to vithstand the consequences of a complete loss of offsite AC power since these are povered from onsite diesel generators Each HPCI and RCIC room is provided with a 100% capacity redundant unit cooler. Refer to. Subsection 9.4.2. 2. 18-1.58 EFFECT OP LOSS OF ALTERNATING-CURRENT POWER ON R FCI RCULATION P~UP S ZALS AXE K~ 3 25) -
~ ~ - ~
18.1.58.1 Statement of geguiresenf The licensees should determine, on a plant-specific basis, by analysis or experiment, the conseguences of a loss of cooling vater to the reactor recirculation pump= seal coolers. The pump seals should be designed to withstand a complete loss of alternating-current (AC) pover for at least 2 hours. Adequacy of the seal design should be demonstrated.- Applicants for operatinq licenses shall submit the evaluation and proposed modifications no later than 6 months prior to expected issuance of the staff safety evaluation report in support of license issuance, vhichever is later. modifications must by January 1, 1982. bc'ompleted 18.1. 58. 2 Interpretation Evaluate the effect of a loss of offsite AC power for 2 hours on th'e recirculation pump seals. 18.1. 58. 3 Statement of Response The system(s) providing cooling water to the recirculation pump seals vill be modified to automatically receive emergency power followinq a loss of offsite power. These modifications will be completed prior to the first refueling outage. Rev. 27, 10/81 1 8.1-104
SS ES-FS AR 18 1 59 PROVIDE A COMMON REFERENCE LEVEL
/II FOR VESSEL LEVEL +ISTRUMENT~AION - K ~327} .
18.1 59 1 Statemeng og Rggujge~mnt-Different reference points of the various reactor vessel water level i,nstruments may cause operator confusion. Therefore, all level instruments should be referenced to the same point. Either the bottom of the vessel or the top of the active fuel are reasonable reference points. All applicants for operating license should submit documentation four months prior to the expected issuance of -the staff safety evaluation report for an operatinq license or four months prior to the listed implementation late, whichever is later. 18 1. 59. 2 I n te rage ta t jon None required. 18.1. 59 3 Statement of Response. Susquehanna SES will be modified so that all reactor water level indications use the same reference point, the bottom of the steam dryer skirt. This commitment was previously stated, in letters from N. W. Curtis to A. Schwencer on July 21 and August 4, 1981 (PLA- 888 ~ -987) 18 1. 60 VERIFY QUALIFICATION OF ACCUMULATORS ON AUTOMATIC DEPBESSURIZATION SYSTEM VALVES (II K 3 281
- 18. 1. 60. 1- Statement of Reguirement-Safety analysis reports claim that air or nitrogen accumulators for the automatic depressurization system {ADS) valves are provided with sufficient capacity to cycle the valves o~n five times at design pressures. GE has also stated that the emergency core cooling (ECC) systems are desiqned to withstand a hostile environment and followinq an accident still perform their function for 100 days Licensee should verify that the accumulators on the ADS valves meet these requirements, even consider ing normal leakage. If this cannot be demonstrated, the 18 1-105 Hev. 27, 10/81
SS ES- PS AR licensee must show that the accumulator design is still acceptable. The ADS valves, accumulators, and associated equipment and instrumentation must be capable of performing their functions durinq and followinq exposure to hostile environments and taking no credit for nonsafety-related equipment or instrumentation. Additionally air (or nitrogen) leakage through valves must be accounted for in order to assure that enough inventory of compressed air is available to cycle the ADS valves. All applicants for operating license shall submit documentation four months before the expected'ssuance of the staff safety evaluation report for an operating license or four months before the listed implementation date, whichever is later. 18.1. 60. 2 Xnteroretation None required. The desiqn basis'and justification for the ADS accumulators are given below. This design basis is different than stated in NUREG 0737, Requirement Xl. K. 3. 28. The criteria for short-term and lonq-term ADS operations, as specified in the PSAR, are as follows: (a) Short-Term ADS Operation Accumulator capacity is sufficient for each ADS valve to provide two actuations against 31.5 psig (70% of 45 psig) drywell pressure (see PSAR Subsection 5.2. 2. 4.1 and response to guestion 211. 67) . (b) Long-Term ADS Operability of 100 Days The safety related nitrogen storage system contains adequate Oas in storase (a -bottles conld be replaced periodically to provide capacity or at least 100 days operation of the ADS. Justification for meeting .these criteria is given below. Short-term is defined for this discussion as the time required to depressurize the reactor to the residual heat Rev. 30, 5/82 l8. 1-106
SS ES-PS AR removal (BHR) shutdovn cooling pressure permissive setpoint, stabilize the reactor water level and place the reactor in the shutdown cooling mode. Each ADS accumulator is presently sized to provide tvo ADS f sa ety/relief valve (S/RV) actuation s a t 70% o f dryvell desiqn pressure. This is eguivalent to six actuations of the ADS S/RVs at atmospheric pressure in the drywell. The ADS valves are desiqned to operate at 70% of drywell design pressure because that is the maximum pressure for which rapid reactor depressurization through the ADS valves is required (qreater dryvell pressures are associated only vith the short duration primary system blovdown in the drywell immediately folloving a large pipe break)'. Por large breaks which result in higher drywell pressure, sufficient reactor depressurization occurs due to the break to preclude the need for ADS. One ADS actuation at 70% of dryvell design pressure is sufficient to depressurize the reactor and allow inventory makeup by the lov pressure ECC systems. Hovever, for conservatism, the ADS accumulators are sized to allow two ADS actuations at 70$ of dryvell design pressure. This design provides sufficient nitrogen to the ADS valves to permit depressurization until the RHR shutdown cooling mode can be initiated. Preoperational testing of the ADS valves at 70% of design drywell pressure is not practical because it ~ould require pressurizing the drywell during the ADS valve testinq. Thus, an equivalent number of valve actuations at atmospheric pressure is normally included in the ADS system test specification. The basis for the long-term ADS requirement is derived from the long-term coolinq acceptance criterion (Criterion 5) of 10CPR50. 06. Criterion 5 states:
'~Long-/edam Cooling. After any calculated successful initial operation of the ECCS, the cal-culated core temperature shall be maintained at an acceptably low value and decay heat shall be removed f'r the extended period of time required by the long-lived radioactivity remaining in the core This criterion requires that either ADS be operable in conjunction vith the low pressure ECCS pumps or that RHR shutdovn cooling and vater makeup capability be operable, to ensure long-term core 'coolinq.
30, 5/82 18. l- 107
S SES-F S AR The primary purpose of long-term ADS- is to keep the reactor pressure low enough so that low pressure .ECCS systems can be used to keep the core cooled. The ADS is not required after the decay heat is low enough so the vessel will not be pressurized above the shutoff head of the low pressure ECCS pum ps+ The duration for which the ADS must be available is dependent on factors such as the power of the reactor at the time of the LOCA, break size and location, available injection systems, and availability of RHR shutdown cooling. The long-term ADS design reguirement is 100 days. This is based on a judqment of the time required to make any necessary repairs to the RHR shutdown coolinq system or ADS, thus ensuring the 'core would be kept cool. Based on the 10CFR50 reguirement, a lonq-term depressurization capability is provided by supplying nitrogen to the ADS accumulators using a safety grade system. The safety related nitrogen storage (N2bottles) system contains adequate gas in storage for 30 days after a postulated DBA. However, these nitrogen bottles could be replaced periodically by brinq'ing portable N2 -bottles to provide long-term operation of the ADS. (At Susquehanna, these bottles are located in an area that is accessible followinq a loss-of-coolant accident.) From the above discussion, PPSL concludes that the Susquehanna design of ADS pneumatic supply system meets the intent of NUREG-0737, Item II.K.3.28. 18 1 61 REVISED SHALL-BREAK LOSS OF COOLANT ACCIDENT HETHODS (II.K.3. 30) 18,1.61.1 Statement of gecCuirement The analysis methods us'ed by nuclear steam supply system vendors and/or .fuel suppliers for small-break loss-of-coolant accident (LOCA) analysis for compliance with Appendix K to 10 CFR Part 50 should be revised, documented and submitted for NRC approval. The revisions should account for comparisons with experimental data, includinq data from the LOFT test and -Semiscale Test facilities. The Bulletins and Orders Task Force identified a number of concerns reqardinq the adequacy of certain features of small-break LOCA models, particularly the need to confirm specific model features (e.g., condensation heat transfer rates) against applicable experimental data. These concerns, as they applied to R ev. 30, 5/82 18 1-108
SSZS-PS AR each light-water reactor {LQR) vendor~s models, were documented in the task force also concluded that, in light of the TNI-2 accident, additional systems verification of the small-break LOCA model as required by II;4 of Appendix K to 10 CPR 50 was needed. This included providinq=experimental verification of the various modes of single-phase and two-phase natural circulation predicted to occur in each vendor's reactor during small-break LDCAs. Based on the cumulative staff requirements for additional small-break LOCA model verification, including both integral system and separate effects verification, the staff considered model revision as the appropriate method for reflecting any potential upgradinq of the analysis methods. The purpose of the verification was to provide the necessary assurance that the small-break LOCA models were acceptable to calculate the behavior and consequences of small primary system breaks. The staff believes that this assurance can alternatively be provided, as appropriate, by additional justification of the acceptability of present small-break LOCA models with regard to specific staff concerns and recent test data. Such justification could supplement or supersede the need for model revision. The specific staff concerns regarding small-break LOCA models are provided in the analysis sections of the BSO Task Force reports for each LWR vendor, (NURZG-0635, -0565, -0626 ~ -0611, and 0623) . These concerns should be reviewed'in total by each holder of an approved emergency core coolinq system model and addressed in the evaluation as appropriate. The recent tests include the entire Semisca1e small-break test series and LOFT Tests (L3-1) and L3-2). The staff believes that the present small-break LOCA models can be both qualitatively and quantitatively assessed aqainst these tests. Other separate effects tests (e.g., ORNL core uncovery tests) and future tests, as appropriate, should also be factored into this assessment. Based on the precedinq information a detailed outline of the proposed proqram to address this issue should be submitted. In particular, this submittal should identify {1} which areas of the models, if any, the licensee intends to upgrade, {2) which areas the licensee intends to address by further justification of acceptability (3) test data to be used as part of the overall verification/upgrade effort, and (4) the estimated schedule for performing the necessary work and submitting this information for staff r'eview and approval. Licensees shall submit an outline of a program for model justification/revision by November 15, 1980. Licensees shall submit additional information for model justification and/or revised analysis model for staff approval by January 1, 1982. Licensees shall submit their plant-specific analyses using the Rev. 30, 5/82 18 1-109
SSES-PS AR revised models by January 1, 1983 or one year after any model revisions are approved. Applicants shall submit appropriate information in accordance with the licensing review schedule. 18.1. 61. 2 Interpretation ~ None required.
- 18. 1,61~Statemegt~ORe~sonse PPSL considers that the reactor vendor, General Electric, is the most appropriate party to work with the staff in resolving staff concerns with small break LOCA models for BWRs. Accordingly, the staff should direct their guestions regardinq the scope and schedule for this requirement to General Electric (attn. R. H.
Buchholz, Manager, BQR Systems Licensing) . Copies of correspondence on this item should be sent to PPGL so that we may remain cognizant of the proqress of the program to resolve the staff~s concerns on this requirement. 18 1 62 PLANT-SPECIFIC CALCOLATIONS TO SHOW COMPLIANCE WITH 10CFR
~PRT 50 46 ~II $ Q 3$ l 18 l. 62. 1 Statement of Reouirement f
Plant-specif ic calculations using NRC-approved models or small-break loss-of-coolant accidents (LOCAs) as described in item II K.3.30 to show compliance with 10 CFR 50.46should be submitted for NRC approval by all licensees. 18 1.62.2 Interpretation None required. $ 8.l.~62. ~S gfgmgpf of Regpogge Plant specific calculations will be performed, if required, followinq NRC approval of LOCA model revisions required by item II.K.3.30 (see Subsection 18.1.61). Rev. 30, 5/82 18 1-110
SSES-PS AB 18 1 63 EVALUATION OP, ANTICIPATED TRANSIENTS WITH SINGLE
- ~ PAILUBg gO'V/I+ NO~EL -CLADDING FAILURE /II. K~3 44) 18.1.63.1 Stateme~n of Requirement For anticipated transients combined with the worst single failure an assuminq proper operator actions, licensees should demonstrate that the core remains covered or provide analysis to show that no significant, fuel damage results from core uncovery. Transients which result in a stuck-open relief valve should be included in this category.
All applicants for operatinq license should submit documentation four months prior to the expected issuance of the staff safety evalaution report for an operating license or four months prior to the listed implementation date, whichever is later. 18.1.63 2 Interpretation None required. 18.1. 63 3 Statement~P "of Response The BWB Owners'roup has prepared a generic response to this requirement. The report was transmitted to D. G. Eisenhut by a letter from D B. Waters on Decembe'r.29, 1980. This response contains an evaluation of analyses performed to demonstrate the core remains covered or no significant fuel damage occurs from an anticipated transient with a sinqle failure. PPSL has reviewed this response and finds it is applicable to Susquehanna SES. The report concludes that the core remains covered for all evaluated combinations of anticipated transients and single failures. 18 1.64 EVALUATION OP DEPRESSURXZATION WITH OTHER'HAN THE 18,$ . 64. 1 Statement of Requirement Analyses to support depressurization modes other than .full aetna tion of the automatic depressurization system {ADS) (e.g. ~ early blowdown with one or two safety relief valves) should be provided. Slower depressurization would reduce the possibility of exceeding vessel integrity limits'y rapid cooldown. Rev. 3 0, 5/82 18 1-111
SSES-PS AR All applicants for operating license should submit documentation four months prior to the expected issuance of the staff safety evaluation report for an operating license or four months prior to the listed implementation date, whichever is later. 1 8. l. 64. 2 I nte r greta tion None required. The BWR Owners'roup submitted a generic response to this requirement. This response was transmitted by letter to D. G. Eisenhut from D. B. Waters on December 29, 1980.. PPSL has reviewed this response and find it applicable to Susquehanna SES. The report. concludes that no improvement can be gained by a slower depressurization and actually could be detrimental to core cooling. Therefore no additional action is necessary in response to this requirement. 18-1.6'5 MICHELSON CQNCE~NS~~XX K 3 46}- 18 1 65.j, S~ttement of Reguigement A number of concerns related to decay heat removal following a very small break LOCA and other related items were questioned by Mr. C Michelson of the Tennessee Valley Authority. These concerns were identified for PWRs. GE was requested to evaluate these concerns as they apply to BWRs and to assess the importance of natural circulation during a small-break I.OCA in BWRs. 18 1.65.2 Intersretation None required. 18.1.65 3 Statement of Response The General Electric Company has responded to the questions posed by Mr. Michelson. This response was sent by letter from R. H. Buchholz to D. F. Ross on February 21, 1980. These responses are Rev. 30, 5/82 18. 1- 112
SS ES-PS AR applicable to Susquehanna SES and no further response is necessary. 18 1.66 ENERGENCY PREPAREDNESS SHORT- TERN (XII A 1 1) No requirement stated in NUREG 0737. Refer to Subsection 18.2.38 which contains the response to the requirement in NUREG 0694. 18 1. 67 " UPGQADg gNggGEN~CSUggOQT PACILITIES ~III A 1 2} l8~l,67. 1 Statement of Reguggemegt. A detailed statement of the requirement can be found in NUREG-0696. The implementation schedule was announced in Generic Letter 81-10 on Eebruary 18, 1981. This schedule is as follows: Desiqn information for emergency response facilities should be provided in connection with the operating license review process. These facilities shall be operational by October 1, 1982 or prior to fuel load, whichever is later. Interim facilities, as described in NUREG-0694 shall be provided by fuel load.
- 18. 1.67.$ Xnfe~gefation None required.
The proposed method of responding to this requirement was submitted by a letter to B. J. Younqblood from N. W. Curtis on April 2, 1981 (PLA-704) . Details on the emergency response facilities are presented in Appendix I of the Emergency Plan. Each nuclear facility shall upgrade its emergency .plans to provide reasonable assurance that adequate protective measures can and vill be taken in the event of a radiological emergency. Specif ic criteria to meet this requirement is delinea ted in Rev. 30, 5/82 18. 1-113
SSES-FSAR NUREG-0654 {PENA-BEP-l), >>Criteria for Preparation and Evaluation of Radioloqical Emerqency Response Plans and Preparation in Support of Nuclear Power Plants.> NUREG-0654, Revision 1; NUREG-0696, >>Punctional Criteria for Emerqency Response Pacilities;>> and the amendments to 10 CPB Part 50 and Appendix E to 10 CPB Part 50 regarding emergency preparedness, provide more detailed criteria for emergency plans, desiqn, and functional criteria for emergency response facilities and establishes firm dates for submission of upgraded emergency plans for installation of prompt. notification systems. These revised criteria and rules supersede previous Commission guidance for the upgradinq of emergency preparedness at nuclear power fac ilities. Requirements of the new emergency-preparedness rules under paragraphs 50.47 and 50.54 and the revised Appendix E to Part 50 taken toqether with NUREG-0654 Revision 1 and NUREG-0696, when approved for issuance, qo beyond the previous requirements for meteorological programs. To provide a realistic time frame for implementation, a staged schedule has been established with compensatinq actions provided for interim measures. Specific milestones have been developed and are presented below. Milestones are numbered and tagged with the following code; a-gape, b<<activity g-mini@urn acceptance criteria. They are as follows: {17 a. Fuel load.
- b. Submittal of radiological emergency response plans.
C>> A description of the plan to include elements of NUREG-0654, Revision 1, Appendix 2. (2) a. Fuel load.
- b. Submittal of i'mplementing procedures.
c Nethods, systems, and equipment to assess and monitor actual or potential offsite consequences of a radiological emergency condition shall be pro vid ed. (3) a. Puel load. C
.Implementation of radiological emergency response plans.
R ev. 30, 5/82 18. 1- 114
SS ES-PS AR
- c. Pour elements of Appendix 2 to NUHEG-0654 with the exception of the Class B model o f element 3, or Alternative to item (3) requir ing compensating actions:
A meteorological measurements program which is consistent with the existinq technical specifications as the the baseline or an element "1 program and/or element 2 system of Appendix 2 to NUREG-0654, or two independent element 2 systems shall provide the basic meteoroloqical parameters (wind direction and speed and an indicator or atmospheric stability) on display in the control room. An operable dose calculational methodology (DCN) shall be in use in the control room and at appropriate emerqency response facilities. The followinq compensating actions shall be taken by the licensee for this alternative: {i) If only element 1 og-element 2 is in use: The licensee {the person who wi11 be responsible for making offsite dose projections) shall check communications with the cognizant National Heather Service (NWS} first order station and NQS forecasting station on a monthly basis to ensure that routine'eteorological observations and forecasts can be accessed. 0 The licensee shall calibrate the meteorological measurements program at a frequency no less than guarterly and identify a readily available source of meteorological data {characteristic of site conditions) to which they can gain access during calibration periods. 0 During conditions of. measurements system unavailability, an alternate source of meteorological data which is characteristic of site conditions shall be identified to which the licensee can gain access. 0 The licensee shall maintain a site inspection schedule for evaluation of the meteorological measurements program at a frequency no less than weekly. 0 It shall be a reportable occurence if the meteorological data unavailability exceeds Rev. 30, 5/82 18. 1-115
SS ES- FS AR the goals -outline in Proposed Revision 1 to Regulatory Guide 1.23 on a guarterly basis. The portion of the DCM relating to the transport and diffusion of gaseous effluents shall be consistent with the characteristics of the Class A model outlined in element 3 of Appendix 2 to NUBEG-0654 (iii) Direct telephone access to the individual responsible for making offsite dose projections (Appendix E to 10 CFR Part 50(XV) (A) (4)) shall be available to the NRC in the event of a radiological emergency. Procedures for establishing contact and identification of contact individuals shall be provided as part of the implementing procedures. I This alternative shall not be exercised after July 1, 1982. Further, by July 1, 1981, a functional description of the upgraded programs (four elements) and schedule for installation and full operational capability shall be provided (see milestones 4 and 5). March 1, 1982.
- b. Xnstallatian of Emergency Response Facility hardware and software.
co Four elements of Appendix 2 to NUREG-0654, with exception of the Class B model of element 3. (5) a. July 1, 1982. b Full operational capability of milestone 4. C~ The Class A model (designed to be used out to the plume exposure EPZ) may be used in lieu of Class B model out to the ingestion EPZ. Compensating actions to be taken for extending the application of the Class A model out to the ingestion EPZ include access to supplemental information (meso anP synoptic scale) to apply judgment regarding intermediate and long-range transport estimates; The distribution of meteorological information by the licensee should be as described in Table 18.1-13 by July 1, 1982. July 1, 1982 or at the time of the completion of milestone 5 ~ whichever is sooner.
- b. Mandatory review of the DCM by the licensee.
Be v 30, 5/82 18 1-116
SS ES-FS AR C<< Any DCH in use should be reviewed to ensure consistency with the operational Class A model. Thus, actions recommended durinq the initial phases of a radiological emergency would be consistent with those after the TSC and,EOF are activated. t7) a. September 1, 1982.
- b. Description of the Class B model provided to the NRC
- c. Documentation of the technical bases and justification for selection of the type Class B model hy the licensee with a'iscussion of the site-speci fic attributes.
(8) a. June 1 1983.
- b. Full operational capability of the Class B model.
- c. Class B model of element 3 of Appendix 2 to NUREG-0654, Revision 1 Applicants for an operating license shall meet at least milestones 1, 2, and 3 prior to the issuance of an operating license. Subsequent milestones shall be met by the same dates indicated for operating reactors.= For the alternative to milestone 3, the meteorological measurements program shall be consistent with the NUREG-75/087, '<Standard Review Plan for the Review of Safety Analysis Reports for Nuclear Power Plants,~'ecton 2;3.3 program as the baseline or element 1 and/or element 2 systems.
- 18. 1. 68. 2 Interpretation None required.
- 18. 1. 68 3 =Statement of Resoonse Hilestones 1, 2 and 3 are beinq addressed as a part of the short term emergency preparedness requirement III.A.l.l. Refer to Subsection 18.2.38 for response. Responses to these and other milestones vill be incorporated into Appendix I of the Emergency Plan..
Rev. 30, 5/82 18 1-117
SS ES-PS AR 18 1 69 INTEGRITY OP SYSTEMS'UTSIDE CONTAINMENT LIKELY TO CONTAIN
~RA IOACTIVB.Jf AT~XAK, ~II~D 18 1.69.1 Stateme~n of geguirement Applicants shall implement a program to reduce leakage from systems outside containment that mould or could contain highly radioactive fluids during a serious transient or accident to as-lov-as-practical levels. This program shall include the follovinq:
(1) Immediate leak reduction. (a) Implement all practical leak reduction measures for all systems that could carry radioactive fluid of containment., 'utside (b) Measure actual leakage rates with system in operation and report them to the NRC. (2) Continuinq Leak Reduction Establish and implement a proqram- of preventive maintenance to reduce leakage to as-low-as-practical levels. 'his proqram shall include periodic inteqrated leak tests at intervals not to exceed each refuelinq cycle. This requirement shall be implemented prior to issuance of a f ull-power license. Applicants shall provide a summary description, together with initial leak-test results, of their program to reduce leakage from systems outside containment that would or could contain primary coolant or other hiqhly radioactive fluids or gases durinq or follovinq a serious transient or accident. Applicants shall submit this information at least four months prior to fuel load. 18 1 69.2 Interpretation None required. $ 8~ 69,~Stgtgeegt of Re~aonae
- 1. Proqram summary description:
Rev. 30, 5/82 18 1-118
SS ES-FS AR 1.1 The follovinq systems will be leak tested (the freguency is indicated in ( ) after each each item): A Residual Heat Removal (18 months) B Reactor Core Isolation Cooling Ci Core Spray D High Pressure Core Injection E Scram Discharge F. Reactor Water Clean-up+ G Standby Gas Treatment H Containment Air Honitors I Post Accident Sampling Initial leak-test results vill be available when the first measurements are made, prior to completion of the startup test program.
~ NOTE: The R$ fCU system will not have significant post-accident radioactivity because the suction is isolated by containment isolation signals (refer to Table 18.1-10) . However, this system may conceivably be used in some post-accident scenarios, and vill therefore be leak tested.
1.2 The following systems contain radioactive material but are excluded from our program (justification for exclusion follovs each item): Hain Steam identified by NEDO-20782 as not to be regarded as containing highly radioactive fluid following'an accident. B Feed vater same justification as A. C Hain Steam Line Drain this system is isolated following a LOCA. Di Reactor Mater Sample this system will not be used following an'ccident, a separate post- accident sampling st. at ion is being developed in response to item XI. B.3. Recirculation Pump Seal Mater (from CRD pumps) - lines.are protected by check valves and an excess flov check valves. Floor 8 Equipment Drains this sytem isolated following a LOCA and will not be used following an accident. Rev. 30, 5/82 18 1- 119
SS ES-PS AR
'G. Suppression Pool Clean-up 6 Drain same justification as P.
1.3 Method for obtaininq actual leak rates Mater leakage vill be collected in a graduated measuring device and timed to determine GPM leak rate. Implementing procedures will establish criteria for initiation of leak rate quantification., Steam an estimate of the size of the leak will be made (i.e. equivalent pipe diameter steam flow). Flovrate will be determined using standard Handbook data. This vill be converted to a GPM flowrate using the specific volume of the steam at the given conditions. The two gaseous systems are tested as follows: A Standby Gas Treatment System This system is subject to filter efficiency testing in accordance vith the Technical Specifications vhich includes "DOP" and refrigerant injection. B. Containment Air Monitors - These are tested vhile the system is under normal runninq conditions by checkinq each mechanical joint with liquid soap. Consideration vas given to the Standby Gas system regarding the incident at North Anna Unit 1 in 1979. The standby gas piping and duct work from the containment to the filters are gas tight and do not include any pressure relief devices vhich would allov gases to escape to the Reactor Building. The piping is rated at 150 psiq and the duct work is HVM-GS-G (High Velocity Medium Pressure Galvanized Steel Gas tiqht3 . In light of the above, the actions stated in 1.1.G and
- 2. A have resulted.
4 Technical Specifications vill incorporate an acceptance criteria of 5 GPM total leakage rate for the systems listed in 1.1 with the exception of: Standby Gas Treatment which is limited to the acceptance criteria stated in Technical Specifications Subsection 4.6.5.3 and Rev. 30, 5/82 18. 1- 120
SS ES- PS AR B The containment air monitors - which has an acceptance criteria of zero leakage as determined . by a liquid soap test. The program is implemented. 18.1 70 1 'Statement of Reauirement Each licensee shall provide equipment and associated training and procedures for accurately determining the airborne iodine concentration in areas within the facility where plant personnel may be present during an accident. Effective monitorinq of increasinq iodine leveLs in the buildings under accident conditions must include the use of portable instruments usinq sample media that will collect iodine selectively over xenon (e. g., silver zeolite) for the following reasons: 'L (1) The physical size of the auxiliary and/or fuel handling building precludes locating stationary monitoring instrumentation at all areas where airborne iodine concentration data miqht be required. (2) Unanticipated isolated >>hot spots<< may occur in locations where no stationary monitoring instrumentation is located. (3) Unexpectedly high background radiation levels near stationary monitorinq instrumentation after an accident may interfere with filter radiation readings. The time required to retrieve samples after an accident (4) may result in high personnel exposures are located in high-dose-rate areas. if these filters A fter Ja nuary 1, 1981, each applicant and licensee shall have the capability to remove the sampling cartridge to a low-background, low-contamination area for further analysis. Normally, counting rooms in auxiliary buildings will not have sufficiently low backgrounds for such analyses following an accident. In the low background area, the sample should first be purged of any entrapped noble gases usinq nitroqen gas or clean air free of noble gases. The licensee shall have the capability to measure accurately the iodine concentrations present on these samples under accident conditions. There should be sufficient samplers to sample all vital areas. Rev. 32, l2/82 18 1- 121
SSES-FSAH
].8.1.70.2 Interpretation PPSL is in basic aqreement with the technical discussion as outlined in this requirement. It should be noted that Susquehanna SES is a BMR and does not possess an auxiliary building. Consequently, it is premature to suqgest that our counting facilities within the control structure will be inarlequa+e to effectively count air amples. Add itionally, purqinq of the air sample cartridqes may not be necessary if an effective collection media- is used for radioiodine air sampling.
- 18. l. 70. 3 Sta tement of Resnonse PPGI. will meet the requirements defined in this item. To summarizo the proqram, three (3) particulate and gaseous continuous air monitorinq systems are provided for air sampling plant areas where personnel may be present during accident conditions. The systems are cart mounted for ease of relocation.
crap sa mples are obtained usinq the equipment s pecif ied in Subsection 12.5.2.6.3. During accident conditions silver zeolite cartridges will be used for radioiodine analysis in conjunction with two (2) Eberline stabilized assay m ters (SAN-2) or o.qui valent. Air samples are evaluated as specified in Subsection 12.5.3.5.5. In addition to initial training provided for Health Physics personnel, periodic drills are conducted in accordance with the Susquehanna Emerqency Plan Section 8.1. 2 (See Amendment 25 of Operatinq I,icense Application) . Analysis of iodine cartridqes will be performed in a low backqround, low contamination area. During accident conditions, preliminary analysis will be perf ormed by onsite radiation monitoring teams in the countinq room, if accessible using a SAN-
- 2. Final analysis will be performed in the emergency off-site facility where appropriate sensitivity can station be achieved. Prior to air or analysis, cartridqes will be purqed using service
)hot~led nitroqen, if necessary to reduce noble gas interference.
All equipment and procedures will be available for use by fuel load Rev. 32, 12/82 18. 1-122
SSBS-FS AR
- 18. 1-71 COQTJQ~RO~~H JB~XTA IIIXX-R~EUIREMENTS ~III.D. 3~4 18.1.71. 1 Statement- of Reauirement-Licensees shall assure that control room operators will be adequately protected against the effects of accidental release of toxic and radioactive qases and that the nuclear power plant can be safely operated or shut down under design basis accident conditions tCriterion 19, "Control Boom," of Appendix A, "General Design Criteria for Nuclear Power Plants," to 10 CPR Part '50) .
All licensees must make a submittal to the NRC regardless of whether or not they met the criteria of the Standard Review Plans (SRP) sections listed below. The new clarification specifies that licensees that meet the criteria of the SRPs should provide the basis by referencinq past submittals to the NBC and/or providinq new or additional information to supplement past submittals. 18.1. 71. 1.1 - Requirement@ fog Licensees. that Meet Criteria All licensees with control rooms that meet the criteria of the followinq sections of the Standard Review Plan: 221-222 Identification of Potential Hazards in Site Vicinity 2 2.3 Evaluation of Potential Accidents; 6.4 Habitability Systems shall report their findings regarding the specific SRP sections as explained below. The followinq documents should be used for guida nce: (a) Regulatory Guide 1.78, "Assumptions for Evaluating the Habitability of Regulatory Power Plant Control Boom During a Postulated Hazardous Chemical Release>>; (b) Regulatory Guide 1.95 ~ "Protection of 'Nuclear Power Plant Control Room Operators Against an Accident Chlorine Release"; and, (c) K. G. Murphy and K. M. Campe, >>Nuclear Power Plant Control Room Ventilation System Design for Meeting General Design Criterion 19 ' 13th AEC Air Cleaning Conference, August 1974 Licensees shall submit the results of their findings as well as the basis for those findings by January 1, 1981. In providing the basis for the habitability finding, licensees may reference their past submittals. Licensees should, however, ensure that Rev. 30 '/82 18 1-123
SSES-PS AR these submittals reflect the current facility design and that the information requested in Attachment 1 of NUREG 0737 is provided. 18.1.71.1.2 Requirements for Licensees that Do Not Jeeps ifegjy All licensees with control rooms that do not meet the criteria of the above-listed references, Standard Review Plans, Regulatory Guides, and other references shall perform the evaluations and identify'ppropriate modifications, as discussed below. Each licensee submittal shall include the results of the analyses of control room concentrations from postulated accidental release of toxic gases and control room operator radiation exposures from airborne radioactive material and direct radiation resulting from design-basis accidents. The toxic qas accident analysis should he performed for all potentia1 hazardous chemical releases occurrinq either on the site or within 5 miles of the plant-site boundary. Requlatory Guide l. 78 lists the chemicals most commonly encountered in the evaluation of control room habitability but is net all inclusive. The desiqn-basis-accident (DBA) radiation source term should be for the loss-of-coolant accident LOCA containment leakage and engineered safety feature (ESP) leakage contribution outside containment as described in Appendix A and B of Standard Review Plan Chapter 15.6.5. Xn addition, boiling-water reactor (BQR) facility evaluations should add valve-stem any leakage from the main steam isoaltion valves (MSIV) (i. e., leakage, valve seat
- leakaqe, main steam isolation valve leakage control system release) to the containment leakage and ESP leakage followinq a LOCA. This should not be construed as altering the staff recommendations in Section D of Regulatory Guide 1.96 (Rev. 2) regardinq NSIV leakaqe-control systems. Other DBAs should be reviewed to determine whether they might constitute a more-severe control-room hazard than the LOCA.
In addition to the accident-analysis results,,which should either identify the possible need for control-room modifications or provide assurance that the habitability systems will operate under all postulated conditions to permit the control-room operators to remain in the control room to take appropriate actions required by General Design Criterion 19, the licensee should submit sufficient information needed for an independent evaluation of the adequacy of the habitability systems. Attachment 1 of NUBEG 0737, item III.D.3.4 lists the information that should be provided alonq with the licensee's evaluation. Rev. 30, 5/82 18. 1-124
SS ES-PS AR
- 18. 1. 71. l. 3 Documentation and Implementa tion Applicants for operatinq licenses shall submit their responses prior to i.ssuance of a full-powez license. Notifications needed for compliance vith the control-room habitability requirements specified in this letter should be identified, and a schedule for completion of the modifications should be provided.
Implementation of such modifications should be started vithout await inq the results of the staf f rev iew. Additional needed modifications, if any, identified by the staff during its review will be specified to licensees.
- 18. l. 71. 2 Interpretation None required.
18.1.71.3 Statement of response The control room HVAC system layout and functional design includes protection of the control zoom from radioactive and toxic gases. Subsection 6.4 provides a complete description of this system and compliance to habitability requirements. Refer to Subsection 6.4 for the response to this requirement. The revision to Subsection 6.4 vill incorporate the f olloving commi tme nts:
- 1. Supplies of food and potable vate'r adequate to support 10 people for 5 days will be maintained onsite.
- 2. Supplies of potassium iodide adequate to protect 30 people vill be maintained onsite.
- 3. Self contained breathinq apparatus and bottled air supply adequate to support 5 operations personnel for 6 hours vill be maintained onsite. Por those situations requiring use of SCBA s within the control zoom HVAC envelope, the Technical Support Center activities will be rel.ocated to the Emergency operations Facility.
REFERENCES Rev. 31, 7/82 18. 1-125
SS ES-FS AR Letter, D. G. Eisenhut (NRC) to S. T. Rogers (BMR Owners'roup), regarding Emergericy Procedure Guidelines, October 21, 1980 U. S. Nuclear Requlatory Commission, <<TMI-2 Lessons Learned Task Force Status Report and Short-Term Recommendations" USNRC Report NUREG-0578, July 1979, Recommenda tion 2. 1. 6 b. U.S. Nuclear Requlatory Commission, <<NRC Action Plan Developed as a Result of the TMI-2 Accident," USNRC-0660, Vols. 1 and 2, May 1980, Section II.B.2. Letter from D. G. Eisenhut (NRC) to All Licensees of Operatinq Plants and Applicants for 'Operatinq Licenses and Holders of Construction Permits,
Subject:
Preliminary Clarification of TMI Action Plan Requirements, dated September 5, 1980. U. S. Nuclear Requlatory Commission, "Clarification of TMI Action Plan Requirements," USNRC Report NUREG-0737, November, 1980, Item II.B.2. U. S. Nuclear Regulatory Commission, I E Bulletin No. 79-01B, "Environmental Qualification of Class IE Equipment", January 14, 1980 U.S. Nuclear Requlatory Commission, "Interim Staff Position on Environmental Qualification Report 'NUREG-0588 ~ December 1979. USNRC Standard Review Plan 6.4, "Habitability Systems", Re vision l. USNRC Requlatory Guide 1.3, <<Assumptions Used for Evaluating the Potential Radiological Consequences of a Loss of Coolan't Accident for Boiling Mater Reactors<<, Revision 2 ~ June 1974. USNEC Requlatory Guide 1.7, <<Control of Combustible Gas Concentrations in Containment Following a Loss-of-Coolant Accident,> Revision 2, November 1978. USNRC Regulatory Guide 1.89 ~ <<Qualification of Class IE Equipment for Nuclear Power Plants," November 1974. Code of Federal Regulations, 10CFR Part 50, Appendix A, GDC 19, Revised as o f January 1, 1980. C. Michael Lederer, et al., Table of Isotopes Lawrence Radiation Laboratory, University of California, March 1968 o ~: 7/82 18 1- 126
SS ES-PS AR 18 1-14 D. S. Duncan an,d A. B. Spear, GRACE I An IBM 704-709 Pgogram Design fog. Computin'g Gamma Ray Attenuation and Heating in reactor Shields~ Atomics Inter'national, (June 1959) . 18.1-15 D. S. Duncan and A. B-. Spear, GRACE .IX An IBN 709 Pgoggam fog Computing Gamma gay Attenuation and Heating in Cylindrical and Spherical'eometries, Atomics International, November 1959.
- 18. 1- 16 Nemorandum of Telephone Conversation, S. Ford of LIS to N. Anderson of NRC s Lessons Learned Task Force,
~
Subject:
TNI Requirements at SHNPP, April 9, 1980.
- 18. 1-17 USNRC Regional Heetinq Minutes, Region I, Sub ject: TNI Review Requirements at SHNPP, April 9, 1980.
- 18. 1-18 USNRC Regional Meeting Minutes, Region IY and V,
Subject:
TH I Reviev Requirements, 9/26/79. Rev. 31, 7/82 18 1- 127
0 SS ES-FSAR BgQ$ R$ S ~ Essential or non-essential classification basis codes are described in Table 18. 1-11. (2) Automatic actuation siqnal codes are described in Table
- 18. 1-12
{3) Where the control power source is left blank, the control power sourc'e is the same as the valve motor power source. (4) E32-1P001B automatic actuation signal is dependent upon action of QSIV's, time, RPV pressure. 'he valve is normally closed and interlocked when RPV pressure is greater than 35 psiq. The valve cannot be opened unless the inboard tiSIV is closed. Information presented is representative of that for main steam lines B, C and D. (5) Automatic signal code UA .for B21-1P028A, et al (Reactor Vessel pressure) prevents operation of condenser low vacuum bypass.
\ T (6) Reactor recirculation system sample line valves B31-1P019 and 1P020 receive hiqh radiation signals for isolation but since the line does not provide an open path from the containment to the environs, the radiation isolation signal may be considered a diverse signal in accordance with Standard Review Plan 6.2. 4. This judgement is based on our definition of an open path as a direct, untreated path to the outside environment.
Hand Switch Mos. are from'the PSID rather than referenced Sch ematic Diagra m. (8) Automati" actuation signals for E11-1P015A and B: codes UB and F. are isolation siqnals; codes G and T are initiation signals. Automatic actuation signals for E11-1P050A and B, and 1F122A, B: code 2 is an isolation signal; no initiation siqnals (10) Either valve opening (or closing) will energize a common open (close) status light. HS-11314 controls both valves. Typical for HV-11345 and HV-11346. Closes on "LOCA" signal but can be reopened after 60 minutes. Valves can be administratively reopened if the high drywell pressure is due to plant heat up or loss of drywell cooler. (12) Closes on <<LOCA<< signal but can be reopened after 10 minutes Rev. 3l, 7/82
FOR THE P&ID FOR PASS SEE FIGURE 9.3-9a Rev. 30 5 82 SUSQUEHANNA STEAM ELECTRIC STATION
'NITS 1 AND 2 FINAL SAFETY ANALYSIS REPORT PASS PAID FIGURE 18; l-ll
FOR LOCATION OF PASS SEE FIGURE 1.2-20 Rev. 30, 5/82 SUSQUEHANNA STEAM ELECTRIC STATION UNITS1 ANO2 FINAI SAFETY ANALYSIS REPORT LOCATION OF PASS EL. 719'-1" FIGURE 18. 1-12
FOR THE LOCATION OF PASS SEE FIGURE 1.2-4 Rev. 30, 5/82 SUSQUEHANNA STEAM ELECTRIC STATION UNITS 1 AND 2 FINAL SAFETY ANALYSIS REPORT LOCATION OF PASS EL. 729 FIGURE 18. 1-13
200 100 80 Pormissiblo Region 60 40 20 10 8 I 6 Nitric Acid 4 a C 1
~ 8
.6 O
~ 2
.1
~ 08
~ 06
~ 04 Imposstbte Region
~ 02
~ 01 5 6 10 Rcv. 27, 10/81 SUSQUEHANNA STEAM ELECTRIC STATION UNITS 1 AND 2 FINAL SAFETY ANALYSIS REPORT SPECIFIC CONDUCTANCE AND pH of AQUEOUS SOLUTIONS AT 2 5oC FIGURE 1S. 1-14
OTHER CLOSE ON HIGH DIFF. PRESSURE ISOLATION SIGNALS
/ / / TIHE DELAY RELAY CONTACT
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DPIS DPIS REPLACE WITH TDK DELAY RELAY AUTO ISOLATION RELAY FUSE Ill K O gZ
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f INCHES RELATIVE TO 160 INCHES ABOVE VESSEL 0 INSTRUMENT 0 STEAN 140 DRYER NA I N STEAM LINES 658,5" 120 RXPRESSXXXXPSIG MATER LEVEL 100 SHUTDOMN RNG XXX IN 80 MATER LEVEL TREND UPSET RANGE XXX IN 60 NAR RANGE A XX N 40 NAR RAt'GE 8 XX IN 20 NAR RANGE C XX IN STEAN MIDE RANGE XXXX IN 0 SEPARATOR
-20 527,5"
-00 CORE SPRAY INLET
-60 484.5"
-80 FLOMS
-100 RHR LP A XXXXX GPN A
-120 RHR LP 8 XXXXX GPN C 0 z C -140 RCIC XXX GPYi F
P I t1 -160 z 15 10 5 377.5" I t'iTi ~of m Z O S" INUTES UPPER SHROUD-CH TOP OF ACTIVE FUEL 366,3" t CO z U z m H A <<m H~o U)
'0 C'
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SSES-FS AR 18 2 RESPONSE TO REQUXRENEQTS IN NUREG 0694 NUREG-0694 supersedes NUREG 0578. The clarificat.ions given in the Vassallo letter on November 9, 1979 were used in the development of applicable responses. I 18 2 1 SHIFT TECHNICAL ADVISOR ZI. A 1. lj Requirement superseded by NUBEG 0737. Refer to Subsection 18. l. 1 for response.
- 18. 2. 2 SHXFT SUPER VISOR ADMINISTRATIVE DUTIES ~I. A l. 2}
18.2. 2 1 Statement of Requirement Review the administrative duties of the shift supervisor and delegate functions that detract from or are subordinate to the manaqemont responsibility for assuring safe operation of the plan+ to other personnel not on duty in the control room. This requirement shall be met before fuel load;
- 18. 2. 2. 2 Interpretation None .required.
18.2.2.3 -Statement of Response PPGL has restructured the operations organization and redefined responsi bilitie of shift personnel to relieve the shift supervi. or of routine administrative duties. Administrative procedure AD-QA-300, "Conduct of Operations," i mplemen ts this policy. The Vice President Nuclear Operations will review and approve assignment of the Shift Supervisor's responsibilities to ensure proper delegation of duties that detract from or are subordinate to the safe operation of the plant.
- 18. 2-1 Rev. 27, 10/8l
SSES ZSAR 18 2 3 SHIFT MANNING ~I A 1 3) Requirement superseded by NUREG 0737. Refer to Subsection 18.1.3 for response. 18 2 4 IMMEDIATE UPGRADING OF OPERATOR AN D SENIOR OPERATOR TRAINING AND QUALIFICATION ~I. A. 2 lg Requirement superseded by NUREG 0737. Refer to Subsection 18.1.4 for response. 18 2. 5 REVISE SCOPE AND CR,ITERIA FOB LICENSING EXAMINATIONS JI A 3. 1$ Reguirement superseded by NUREG 0737. Refer to Subsection 18.1.6 for response. 18.2. 6 EVALUATION OF ORGANIZATION AND MANAGEMENT IMPROVEMENTS OF NEAR-TECUM OP ERATING LICENSE APPLICANTS gI. B. 1. 2~ 18 2.6.1 Statemept of Beguiremgnt The licensee orqanization shall comply vith the findings and requirements generated in an interoffice NBC review of licensee organization and management. The review will be based on an NRC document entitled Draft Criteria for Utility Management and Technical Competence. The first draft of this document was dated February 25, 1980, but the document is changing with use and experience in ongoing reviews. These draft criteria address the organization resources, training, and qualifications of plant staff, and manaqement (both onsite and offsite) for routine operations and the resources and activities (both onsite and offsite) for accident conditions. This requirement shall be met prior to fuel load. 18 2. 6. 2 In terpretat ion None required. Rev. 27, 10/Sl 18-2-2
SS ES- PS AR
- 18. 2. 6. 3 Statement of Resnonse.
A review of orqanization and management has been completed in accordance with draft NUREG 0731, "Guidelines for Utility Nanaqement Structure and Technical Competence.'~ An NRC audit of the organization was conducted March 2-6, 1981. 18 2.7 SHORT. TERN ACCIDENT ANALYSIS AND PROCEDURE REVISION (Z.- C 1l Requirement superseded by NUREG 0737. Refer to Subsection 18.1.8 for response. II 18 2.8 SHIFT RELIEF A$ D QURQOVER PROCEDURES ~I C.'2j 18 2. 8.1 Statement of Reauirement j Revise plant'rocedures for shift relief and turnover to require signed checklists and logs to assure that the operating staff fincluding auxiliary operators and maintenance personnel) possess adequate knowledge of critical plant parameter status, system status, availability and alignment. This requirement shall be met prior to fuel load. 18.2. 8. 2 Interpretation None reguired. 18,2.8.3 Statement of response Administrative procedure AD-QA-300, "Conduct of Operations," discusses operations personnel responsibilities at shift turnover. Administrative procedure AD-QA-303, "Shift Routine," specifically defines the shift turnover process. 18 2-3 Rev. 27, 10/81
SSES-FS AR 18.2. 9 SHIFT SUPERVISOR RESPONSIBILITIES'I C. 3} 18.2.9.1 Statement of Reguigement Issue a corporate manaqement directive that clear3.y establishes the command duties of the shift supervisor and emphasizes the primary manaqement responsibility for safe operation of 'the plant. Revise plant procedures to clearly def ine the duties, responsibilities and authority of the shift supervisor and the control room operators. This requirement shall be met prior to fuel load. 1 8. 2. 9. 2 In te r ore ta tion None required. l 8. 2. 9. 3 Sta ggyegt o f Re@yon se The Senior Vice President Nuclear shall issue prior to fuel load a statement of policy establishing the primary responsibility of the Shift Supervisor for safe operation of the plant under all conditions and establishing authority to direct actions leadinq to safe operation in the Shift. Supervisor. The Senior Vice President - Nuclear shall re-issue this statement of policy on an annual basis. Administrative Procedure AD-QA-300, <<Conduct of Operations," sets forth the plant policy on Shift Supervisor duties. Training for Shift Supervisors includes plant Administrative Procedures, and will encompass AD-QA-300. 18 2. 10 CONTROL ROON ACCESS lI C 4} 18.2.10.1 Statement of gegujgement Revise plant procedures to limit access to the control room to those individuals responsible for the direct operation of the plant, technical advisors, specified NRC personnel, and to establish a clear line of authority, responsibility, and succession in the control room. This requirement shall be met prior to fuel load. Rev. 31, 7/82 18. 2-4
SS ES-PS AR 18,2. 10. 2 Inte~g~eation. None required. ~18 2. 10. 3 Statement of*Response Administrative procedure AD-QA-300, "Conduct of Operations," provides the authority and instructions for control'oom access control. 18 2 11 PROCEDURES FOB PEEDBACK OP OPERATING EXPERIENCE TO PQAQT STAg~E g ~5 Requirement superseded by NUREG 0737. Refer to Subsection 18.1.12 for response. 18.2.12.1 Statement of Reauirement Obtain nuclear steam supply system vendor review of low-power testinq procedures to further verify their adequacy. This requirement shall be met prior to fuel load. Obtain NSSS vendor review of power-ascension test and emergency procedures to further verify their adeguacy. This requirement must be met before issuance of a full-power license. None required. The General Electric Company, through its site startup organization, will review all startup tests associated with NSSS systems and will review all Emergency operating procedures that were submitted to NHC in response to item E.C.8 (see Subsection 18.2. 13) The startup tests encompass the low power testing and Rev. 30, 5/82 18. 2-5
SS ES-PS AR the pover ascension testing phases. These reviews will be completed prior to fuel load. 18 2.13 PILOT HOHITOBXNG OP SELECTED EMERGENCY PROCEDURES FOB NEAR TERM-Op@RATING. LICENSE-APPLICANTS ~I C 8Q 18.2.13.1 Statement of Requirement Correct emerqency procedures, as necessary, based on the NRC audit of selected plant emergency operating procedures {e. g., small-break LOCA, loss of feedwater, restart of engineered safety features folloving a loss of AC power or, steam-line break). 18 2.13.2 Interpretation Hone required. 18.2. 13.3 Statement of Resnonse Emergency procedures based on those quidelines have been developed and are currently in trial use on the Susquehanna SEC Simulator. These procedures have been reviewed by the NRC. Pinal versions vhich incorporated NBC comments vere submitted in a letter from N. W. Curtis to B. J. Youngblood on May 15, 198 1. (PLA-791 ) . 18 2 ~4 CONTROL gOON DESIGN JZ~D ~1 Reguirement superseded by NUBEG 0737. Refer to Subsection f
- 18. 1. 16 or re sponse.
~8 g- 15 TRAINING DURING
~
LQW gOWER TESTING ~I G ~I 18.2 15.1 Statement of Reauirement Define and commit to a special low-power testing program approved by NRC to be conducted at power levels no greater than 5 percent for the purposes of providinq meaningful technical information beyond that obtained in the normal startup test program and to Rev. 30, 5/82 18 2-6
<<%V ~ '<< SSZS-TSAR
\
provide supplemental training. This reguirement shall be met before fuel load. Supplem'ent operator traininq by completinq the. special low-pover test proqram. Tests may he observed by other shifts or repeated on other shifts to provide training to the operators. This requirement shall be met before issuance of a full-power license. 18 2 15.2 Interpretation None required. 18.2.15.3 Statement og Re~s ogive The BQR Ovners'roup has prepared a generic response to this requirement. This vas transmitted to D. G. Ei;senhut by a letter from D. B. Waters on February 0, 1981. PPSL concurs with this response. This generic approach outlines an extensive testing proqram desiqned to contribute to and provide for extensive traininq opportunities during the start-up program. The objectives of this program are to,provide:
- l. A plant, that has been thoroughly tested.
- 2. An operating staff that has received the maximum experience and in-plant training to safely operate it.
- 3. Plant procedures that have been reviewed and revised to provide the staff vith proven directions and controls.
Susquehanna's Operator Training Program has been in progress since 1977 and is completinq the final phases of training at this time. This program utilizes the Susguehanna Simulator located at the plant site, and provides the operators with extensive training vrior to actual operations in the plant itself. The Simulator is also used for procedure development and check out. The Operator Traininq Proqram that is being developed for the Preoperational and Lov Power Testing Pxogram incorporates and builds on the extensive traininq already completed by the operations section. It vill include the recommendation presented in the BWR Owners'roup position but goes beyond those recommendation's by maximizinq the use of the Susquehanna Simulator in preparinq the operators for the start-up tests to be performed. The objective of the Operator Training Program is to provide each operator with the maximum learning experience during the start-up Rev. 30, 5/82 18 2-7
SS ES-PS AR phase. In order to achieve this objective, a comprehensive traininq proqram is being developed that utilizes the many traininq opportunities that are available during this period and ensures actual testinq. This program covers the period from Preoperational/Acceptance Testing through the Power Test Program on Unit I. To support this amount of training the operations section which is staffed for six sections has reorganized into four sections. This reorganization provided the benefit of allowinq more operators off shift to attend formal training as well as provide more operating experience for each shift team. Every effort is beinq made to keep the shifts intact and provide traininq that promotes the >Shift Team~~ concept. The training program being developed covers the areas of activities listed below but recognizes the overlap that exists between some of the areas. I Preoperational/Acceptance Testing II III. Cold Functional Testing Hot Punctional Testing XV Sta rt-up Tests V Additional Testing Each area of testinq has activities that lend itself to operator traininq. The major ones are outlined in Table 18.2-1. The .. traininq program provides a vehicle to identify activities that have a significant benefit for training, documents this training, and ensures that all shift crews ~eceive equal experience opportunities. The proqram also attempts to schedule repeats of certain evolutions that are considered critical and cannot be routinely performed at a later time. The training program wild. identify areas of testing/training that while not required by start-up program would have additional training benefit. This testing/traininq could then be scheduled into the testinq program as additional testing. Pinally this program will develop the basis for the In-Plant Drill Proqram. This comprehensive approach to testing/training more than adequately satisfies the requirements of NUREG 0737. 4 Susquehanna SES power condition vill for conduct a test which simulates a loss. of AC the reactor and containment systems. The purpose of this test will be to obtain data relative to the performance of these systems under the imposed condition of no AC power available for mitiqation of transient effects. Several key factors associated with performance of this test include: (a) No blockinq of low pressure ECCS functions will be provided. Transient conditions imposed by the test are not expected to initiate these systems on low water level. Adequate data will be obtained prior to injection of low pressure ECCS flow on a hiqh drywell pressure signal in conjunction with a Re v. 30, 5/82 18. 2- 8
confirmatory lov reactor pressure signal. If initiation points are reached earlier in the test, this would represent a criteria for test termination and the ECCS vould be
'allowed to function as designed.
{b) Xn most if not all cases, Limiting Conditions for Operation vi3.1 not be violated. It is possible that as test plans are developed certain LCO's vill be identified as inhibitinq test performance. Hovever, for LCO's that are being approached as a result of transient effects during the test, this will represent
'criteria for test termination to insure plant safety.
(c) Loss of power to plant instrumentation will not be simulated. To accomplish the major goal of this test, instrumentatin vill be maintained functional .for proper data collection. This constraint is also considered necessary to insure plant sfaety. Training of licensed operators in response to the loss of all station AC condition vill be provided at PPSL's plant specific simulator. This will provide the opportunity to experience the instrumentation blackout condition vithout placing the plant in jeopardy. (d) Plant AC busses will remain energized, the emergency diesel generators wi11 be available or operating, and breakers to safeguards equipment vill not be racked out. These precautions are considered necessary for plant safety. (e) Test termination criteria will be established .for parameters such as reactor vessel temperature limits, containment pressure and temperature, reactor vessel level, suppression pool temperature, HPCI and RCIC room temperatures, and CRD temperatures. The test will be conducted at a convenient point during the first fuel cycle, with the constraint that adequate decay heat exists to provide a valid test. Several options are being explored for test initiation {e.q.,'turbine trip from 5% power following load reduction, turbine trip from 85% pover, etc.) It is our position that the method finally selected will have'little bearing on the test, since plant performance during the initial state of such transients is adequately tested in startup tests. The commitments previously made in response to Item I.G.l for additional testinq and traininq vill be fulfilled, as that valuable input will be obtained for the loss of AC it is felt povertest. The test may cause certain conditions vhich are inconsistent with NBC req'uirements. Re therefore vill provide the NRC with the Rev. 30, 5/82 18 2-9
SS ES-PS AR test plan and pertinent documents for review and approval.. Performance of this test is continqent upon a favorable safety evaluation and obtaininq appropriate commission approvals. Since the NRC has indicated that they may not require a test at Susquehanna SES if results from a test at another plant resolve their concerns, PPSL's commitment is contingent on a continuing NRC requirement for this test.
- 18. 2~6 ~RACTOg ~0~ANT SYSTEM/ VENTS ~IX B,lj Requirement superseded by NUBEG 0737. Refer to Subsection 18.1. 19 for response.
18 2-~7 PLANT SHIEL2ING /XI B Qi Requirement superseded by NUREG 0737. Refer to Subsection
- 18. l. 20 for response.
Requirement superseded by NUREG 0737. Refer to Subsection 18.1. 21 for response. 18 g,l9. TRAINING $ 08 MITIGATING CORE DAMAGE /II B 4g Requirement superseded by NUREG 0737. Refer to Subsection f
- 18. 1. 22 or re sponse.
Requirement superseded by NUREG 0737. Refer to Subsection 18.1. 23 for response. 18 2,21 NELIgP AN/ SAFETY VALVE 'POSITION INDICATION~II D.SQ Requirement superseded by NUREG 0737. Refer to Subsection 18.1. 24 for response. Re v. 3 0, 5/82 18- 2-10
SSES-FSAR 18 2. 2g CONXA~X~N~N ISOLATXO~ND QNNDABILITY XIX.8~4~2'equirement superseded by NUREG 0737. Refer,to Subsection 18.1. 29 for response. I 18,2 23 ADDITIONAL ~ACIDENT MONITORING I NSTRUMENTATION ~II ~P. 1 Reguirement superseded by NUREG 0737. Refer to Subsection 18.1.30 for response. Reguirement superseded by NUREG 0737. Refer to Subsection 18.1. 31 for response. 18 2,25 A SSUg ANCE Og --/ROAR ESP FUNCTIONING ~
/II K 1 5g 18,$ .25 1 Statement gf Requirement Review all valve positions,'ositioning requirements, positive controls and related test and maintenance procedures to assure proper ESP functioning. This xeguirement shall be met by fuel load.
None required. 18.2.25~ Stag~em ~n og 'Response Operating and surveillance procedures are currently being developed. Writing the procedures to reflect ESP requirement is a key ob 5ective of procedure originators. Additionally, these procedures will receive a review {independent of the originator) to provide further assurance that the procedure is technically correct and provides for accomplishment of procedural objectives {including maintenance of proper safety function). Rev. 30, 5/82 18 2- 11
SS ES-FS AR 18,2,26 - SAggTY R~EL ~TD SIST H OPgiLABYLYTY STATB~SZY-K.~10$ 18 2,26. 1 Sta tement of Reauirement Review and modify, as required, procedures for removing safety-related systems from service (and restoring to servic'e) to assure operability status is known. This reguirement shall be met by fuel load. 18.2. 26. 2 YnterRRetation None required. l8,$ . 26,3 Statement of R~es onse Surveillance testinq vill be controlled by administrative procedure AD-gA-422. This procedure,.- which is currently being drafted, will require that surveillance implementing procedures contain a review of redundant component operability prior to removinq the system to be tested from service, (if such removal is required by the test), a review of proper system status prior to return of the tested system to'service, and provide for notification to Operations of the need for system status changes. Administrative Procedure AD-QA-306, YYSystem Status and Equipment Control," (see Subsection 18.1.13.3) establishes control of system status as an operations responsibility and will provide the same reviews described above during normal operations and maintenance activities. Haintenance procedures will only cover activities while systems and components are removed from service, the Operations section will actually accomplish changes in system status as controlled by the described Instruction. 18 2 27 TRIP PRESSURIZER LOtI-LEVEL COINCIDENT SIGNAL BXSTABLES XXX=K~k&7). This requirement is not applicable to Susguehanna SES. 18 2 28 OPERATOR TRAINING FOR PROHPT MANUAL REACTOR XRXR LXIaK~L=ZOM-This requirement is not applicable to Susquehanna SES. Re v. 30, 5/82 18. 2-12
SSZS-FS AR 18 2 29 - AUTONATIC SUETY GEA~DAN~TCIgATORg T~I~PII K ~12 This requirement is not applicable to Susquehanna SES. 18 2 30 AUXILIARY HEAT REMOVAL SYSTEMS OPERATING PROC'EDURES
/II K~$~2$
Describe the automatic and manual actions necessary for proper functioning of the auxiliary heat .removal systems that are used vhen the main feedvater system is not operable. This requirement shall be met by fuel load. 18~2. 30. 2 Integggetatian None required. A generic response to this reguirement vas provided by General Electric in NEDO-24708, vAdditional Information Required for NRC Staff Generic Report an Boiling Mater Reactors," (August, 1979) and supplement I. A plant specific description is provided below. If the main feedvater system is not operable, a reactor scram wil1 be automatically initiated when reactor water level falls to Level 3 (540.5 inches above vessel bottom or 178.2 inches ab'ove the top of the active fuel) . The operator can then remote manually initiate the reactor core isolation cooling system from the main control room, or the system vill be automatically initiated vhen reactor water level decreases to Level 2 (489. 5 inches above vessel bottam or 127.2 inches above the top of the active fuel) due to boil-off. At this point, the high pressure coolant infection system vill also automatically start supplying makeup vater to the vessel. These systems vill continue. automatic injection until the reactor vater level reaches Level 8 (581.5 inches above vessel bottom or 219.2 inches above top of the active fuel), at which time the high pressure coolant injection turbine and the reactor core isolation cooling turbine are automatically tripped. Rev 30 ~ 5/82 18 2- 13
SS ES-PS AR In the nonaccident case, the reactor core isolation cooling system is utilized to furnish subsequent makeup water tvo the reactor pressure vessel. The Reactor core isolation coolinq system and the high pressure coolant injection system vill restart automatically shen the level falls to Level 2 (The reactor core isolation coolinq system is being modified to automatically restart, see subsection 18.1.50). No manual actions are reguired for these systems to restart. Reactor vessel pressure is regulated by the automatic or remote manual operation of the main steam relief valves which hlov dovn to the suppression pool To Kemove decay heat, assuming that the main condenser is not available, the steam condensing mode of the residual heat removal system is initiated by the operator. This involves remote manual a liqn ment of the residual heat removal system valves. If the steam condensinq mode is unavailable for any reason, the main steam relief valves can be manually actuated from the control room. Remote manual alignment of the residual heat removal system into the suppression pool cooling mode is then required for suppression pool heat removal. Makeup vater to the vessel is still supplied by the reactor core isolation cooling system under manual control. For the accident case with the reactor pressure vessel at high pressure, the hiqh pressure coolant injection system is utilized to automatically provide the required makeup flov. No manual operations are required since the'high pressure coolant injection system vill cycle on and off automatically as water level reaches Level 2 and Level 8, respectively. If the high pressure coolant injection system fails under these conditions, the operator cap manually depressurize the reactor vessel using the automatic depressurization system to permit the low pressure emergency core coolinq systems to provide makeup coolant. Automatic ,depressurzation vill'ccur if all of the folloving signals are present: high dryvell pressure 1.69 psig, Level 3 water Level permissive, Level 1 water level (398.5 inches above vessel bottom or 36.2 inches above the top of the active fuel), pressure in at least one lov pressure injection system and the run out of a 120 second timer {set at 105 seco'nds) vhich starts with the coincidence of the other four signals. 18,2 31. 1 Statement of Reauirement For boilinq water reactors, describe all uses and types of reactor vessel level indication for both automatic and manual initiation of safety systems. Describe other instrumentation 3ev. 30, 5/82 18. 2-14
SS ZS-FS AB that might give the operator the same information on plant status. This requirement shall be met before fuel load. 18,2. 31. 2 Interpretation None required.
- 18. 2. 31. 3 S ta tem en t o f R es pon se The response to this requirement was provided by General Electric in NEDO-24708. Additional Information Required for NRC Staff Generic Report on Boilinq Mater Reactors," {August 1979) and Supplement I.
$ 8 2,32 COMMISSION ORDERS +0 QBCQCK AND MILCOX PLANTS /II K 2} These requirements are not applicable to Susquehanna SES. 18 2 33 REPORTING REQUIREMENTS FOR SAFETY/RELIEF VALVE PRILU HS OR CHRLLBNGRS
~ ~ R ~
II?I H 3.3'I
. 'I 18 2. 33. 1 Stytemegt og Hggu'igggegg Assure that any failure of a PCBV or safety valve to close vill reported to the NRC promptly. All challenges to the PORVs or
'e safety valves should be documented in the annual report. This requirement shall be met before issuance of a f ull-power license.
- 18. 2 33. 2 Interpretation Prompt reportinq to the NRC consists of notification within 24 hours by telephone with confirmation by telegraph, mailgram or facsimile transmission, followed hy a written report within 14 days.
The annual operating report has been supplanted by more detailed Monthly Operatinq Reports. Documentation required to be included in the annual report will be supplied in Monthly Operating Be por ts. Rev. 30, 5/82 18- 2-15
SSES-PS AR 18.2 33.g Stagemenf of Response Subsection 6.9.1.8 of the Technical Specifications will be chanqed to require prompt reporting with vritten follovup for failures of main steamline Safety/Relief Valves to reclose after actuation. Procedure {s) for reporting of Reportable Occurrences are beinq written addressinq Technical Specification requirements.. Subsection 6.9.1.6 of the Technical Specifications currently requires documentation of all challenges to main steamline ] Safety/Relief Valves to be included in the monthly Reactor Operatinq Report. Procedure{s) for preparation and submittal of these monthly .reports are beinq written incorporating this requirement. 'eportinq
$8 2 34 PROPQRTIQQAL XQTEGRPL DERIVATIVE CONTBOLLER
~
/II K-3~9 This requirement is not applicable to Susquehanna SES.
gS 2. 35- ~AN ICIPQTQB J REACTOR gRIQ~DIPICATION -
/II K 3 10)
This requirement is not applicable to Susquehanna SES.
$ 8.2. 36- POWDER OP~RATED- RELIJP VALVE FAILURE RATE /II K 3 lip This requirement is not applicable to Susquehanna SES.
18 2.37 ANTICIP~ARY BQACTOQ TRIP ON TURBINE TRIP
~
/II K 3 1~2 This requirement is not applicable to Susquehanna SES.
$ 8,$ ,88 EHERGEHC1 g~RPQR~RBDH $ 8-HHORT TER/ /III. H 1 11 Comply vith Appendix E, >>Emergency Facilities,>> to 10 CPR Part 50, Regulatory Guide 1.101, >>Emergency Planning for. Nuclear Pover Plants," and for the offsite plans, meet essential elements of Rev. 30, 5/82 18 2-16
SS ES- FS AR TABLE 18.2-1 /Continued)
- 2. Conduct preselected start-up tests on the simulator prior to the actual test in the plant.
- 3. Feedback of data/response to the Nuclear Training Department to update the simulator 6 materials.
- 4. Provide each shift with training on testing that they did not perform.
V. Additional Testing A qroup of supplemental tests will be developed, to he performed durinq the Preoperational Test Program, which will provide meaninqful technical information in addition to established tests programs. The followinq procedures will be written or revised to incorporate the supplemental tests as developed by the BMR Owners'roup. The FSAR will be revised as appropriate.
- 1. TP 2.14 will be revised to incorporate the <<integrated Reactor Pressure. Vessel Level Instrument Test."
- 7. P59.2 will be revised to incorporate the <<Integrated Containment Pressure Instrumentation Test."
- 3. Hew Technical Procedures (TP's) will be written to incorporate three RCIC System Tests.
- a. Start-up of the RCIC system after a loss of alternating current (AC) power to the system.
- h. Operation of the RCIC system with a sustained loss of AC power to the system.
- c. Operation of the RCIC system to verify direct current power separation.
A new test procedure will be written to 'perform a station 4 blackout test durinq the first cycle as "described'n subsection
- 18. 2. 15.
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~ CACIS STCAH LINC TO OK INOIVIDVALSVAHNUCIATCD OVTDOARD SVSTKH SHOWN IN ( I SUSQUEHANNA STEAM ELECTRIC STATION UNITS 1 AND 2 FINAL SAFETY ANALYSIS REPORT MSIV LEAKAGE CONTROL SYSTEM FCD FIGURE 6.7-3 Sheet 1 I 4
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~CWITC<< VALVE Rev. 19, 1/81 SUSQUEHANNA STEAM ELECTRIC STATION UNITS 1 AND 2 CLOSE
'VH(S ()RAWING SU(IESE()ES FINAL SAFETY ANALYSIS REPORT DC RCYERSINS CON(ACTOR T2 ~
E)WG << ft'9ESP27 REV Q FCEE S()S(ar)EHANHA t Ea 2. ST IN SIMPLY Liat 15ollvloa YILYtNo r SCC NO)f5 2 ~ 0 l HPCI SYSTEM FCD FIGURE 7.3-7 Sheet 1 I I 4 10
SEE REI'l IOR INSTRIIIAENT SE't P(RNC TIRDPC ST(P Sl(MI APPLE WAVE IIllY MLVE MD ION Svpp plxL VlfA (CAPP Rll VENT tl(R(fNCT COMP R(YYI Ma/lit( IJ CDS(0 I(LIT (LOSE 0 IENT AIK LMXT AREa CO(LCR AR(A Mal TENP t (KRIET NNN NKkl TOAD LP a.? NKS 0.3 5 IOSITKN. SNIT(N CR REF FS RfF IS IfRMSS5C WICN Dn(NAA(t INN IOMTKN PRESS r RM5 CR D ~ I(K PI SSIE ITAAOINL AFT( II(LATION POSE ~ TRAE OELal DVTRN n (CPICNED CR REF IS KC I' 5 IIIOV%IYE IAKN IOT IN TEST OI5 CR OC CNWRM TEA MLVCNO OC ROTC t ~ 5
- t. IO5ITION SWITCN
-St(SET'TNNCI CCITACTS LCILOCKEO IN 1KNY\AL n(LATIN SONIC KPC STfAM NYAI TLNSPR LOMC'A'RISC SOPPLY LOW (DIAOST DAIN PRE SSME(
RIAS CR IP OR PISIR Mac Oafar N004 ER I NPCI Sl(AM SUPPLY LOW PR(SSIRE NYiN TVANN( (YAADST DMTN PA( SSRE N/O 15(CAPON Aol SMNAL(IOIE I) g PDRTON SMOCK a05(S b(N AM&TAWED CNTlKT N CPINKE SWPCN KY TY(IFNNITKN CNTNL 5WITCN IN TTDS( IOSITON CIN(t ASA't DRPA(SSON SMYRE 5IKN SRYIA(C TANK ST(MNC CAAIAOER NYAI CNAMECR NION LDw I(VEL LDW LEVEL LET(L LEVEL I PLNNSSVE MrlSS ALITD l5(LAZKA SENAL PRESENT PENWSSAIE WIKN fafaaffD NANSVEIMOI 5(L(IKO IS 5(L(NOO PLOT 5(LCIKO l5 ~POSITKN EN(AC(fD VALVE DE OCR(YE(D ~Wilful, CPIINL SWINN SEAL IN CCIFPOSITON lilLCSS NRIN5%% OM(55 aosto VALV( OVER KRNCD WINE LSI LNC PERIASSIVf IFKISS P0055IVE IPL($5
~ ENNSRVE MNE$5 FMLY CF(N OVERT(R(ato CORNS FAAS COSED ONCSS CF VR LP l4(E C IS IQATKN @DIAL Rev. 19, 1/81 t~
SUSQUEHANNA STEAM ELECTRIC STATION
~YAM DPPLY L 5(t IOT(
AT TA(TDA I ~ UNITS 1 AND 2 FD(PA St 50(N NOT CNAMSER EAT VAIN MO POAC FINAL SAFETY ANALYSIS REPORT HPCI SYSTEM FCD FIGURE 7. 3-7 Sheet 2 IO
I N K P I y ~t 0
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) YILYC 101 SULLY Otta LIHIT 01 5VITCN YILYKNof SULLY CL05KD LIHIT 01 5VITCH YLLYt IIOT f ULLY CLOSED LIHIT SVITCN VLLYK 101 SUlLY OPK N g
ON LI HIT ON SVITCN 101$ LSWITCN SmS SVITCN SIOO SVITCN YILYf 5VITCN YJLVC 5VI'TCN VALVE SVI1CN VALYK TVPICI Ilf10101 Pf AS No'I OPTIITTD YLLYtt VL V 5 JOSO XC 0 ICIT SILLY COLOR CLOSED (5KE TADIK 1) Slf 1JSLf 11 t P05ITION SVITCN UMIT SWITCH ON VALVE
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5 ~POSITION Svlf ffl Rf OUIRtD ON TLLYK 2 POSITION 5VITCH
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CONTROL SVITffl VJCUUN TINE CONTROL SVITCN CONTROL SVITCH COHDKNSITK I'UNC'IION 11 OP K 1' CONOKRSAT C I1 OPt1 IN DRAIN POT (SfC TAaff 05I 1 ION LCYKL HIS<< POSITION
'OPCN'O5I 1 101 HICH LfYlL TNACII (IS SEC TULE OCIAY) 5KC 11$ Ca AUX TASLt ff L5N RN5 Ca RN5 Ca Ij LOCJL OCYXK sxa TANIE 1 LUCTUJ1INC DCYICE 10 PERNI551YC Iowa f
Sf AH SUPPLY PER<<15511 VNta 5'ltIN SUPPLY f YILYt No SOOIIS YILYKNo SOOI I5 SULLY CLOSCD SULLY CL05KD TASLK n ( OKVXE T JLYC NIX DKYICC 01 1 JLYK LCTINTINI - ill Vlf TRIP fwrf la IURTIIR CDXIRIX YILYK Dfla CONTROI VENT CONTROL YK1T ITS, I AIR 1lllfIfI CATION Tlfl~ Ilf COITIOL YLLIK CLOIKD Of ACTIN'IIIC CNKRCITED t<<KRCIllD KN'KRCI110 DlfICK5
~ KRNI$5ITC 50LKNOIO PC RNIS 5 I YK PKRNI55IYC toit<<OID Pf RHI55IVC PKRNI55IYC 50LtlOID PKRNI55IYC VHC1 PILOT 1 VNKN FILO 1 V 1'l 1 V<<11 PILOT V<<t<<
SOLKROO lt YJLYK SOLEI ID IS SOLKNOID l5 YLLYK 50LKROID IS 50I.CXOID I5 1 JLYK 50LKROID 15 KNKRCIKKD Sol DK KataCIKKD KRKICIKKD 50L Of-KNtRCIlto f<<laffltD 5OL Ol KNKRfflfD PN.OT PILOT LDCLL ~ Ilof lOCAL 5TDP Yslll OFT N 51IP Vlllt Cllllt TJSLE 1 Tol IX SUPC RYI5ORY INDICITHIC lICNTS 1l1f III INC Dlllit fffl lf Rev. 19, 1/81 Lula SIHCTIa Dlfllt lIll1 NW Jul<<
<<PCI TINIIXT 51IP YN.YT YILYl II I FILD LIIIT SVIICH LOCAL CLOITS C@KIffl 0 KNlaffllD t 1l I C I2 C 0 TIRIIW. PI OIL IVISS los Fl ~ SUSQUEHANNA STEAM ELECTRIC STATION Ao Sots loCJL Jo Sotl LOCAL Ao F051 LOCJL HICI fLOI loI S5 IUL INDI LP CH UNITS 1 AND 2 VLLVt SAILS CL05tD YILYK JILS CloSKD f VJLVK SLIL5 CLOSCD VlfNl~ I SS I FINAL SAFETY ANALYSIS REPORT 01 Lots OS *Ia 01 lo5$ OF AIR ONL05$ Of AIR Hl PRESffWR ~ DI Hl I<<
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>VT I A ISPR5NT AVX CR DEVICE / CCR / C CR) ( PCRllISSIYM WHEN t(RIA$5IYC WNKN TVROINE VALVEOOS FN~g 5'fOI'ALYE $ 1$ f C(OSKO S IS PTX>> SIGNAL IS PRESENT AUX DE TICE PERMISSIYC ON 'A SCRAM AVX DEVICE CR PKRUISSIYE WNKN TVRSINK SIRST SfACE PRESS EXCEEDS SCT POINT OF PS NOO'SA (SI AUX PEAN]5$ IVE ON DEVICE t(RIRSSIYE WHCN '4 SCRAH SIEACTOR FOEKR IS >DO 5 RATED AVX DK VIC C PKRMI'SSIYE WNKN TVRSINK FIRST STACE tRE$ 5 CXCKEOS SK'f POINT OF PS NOOSE ID) AUX DKYICE FVLL CORC DlstLAY 4 / / t / / G CI ~G POIMISSIYE WNKN NANGAL ClOSC EXR SA SO/ MANUAL 4YPASS HANUAl CLOSC GXR 14 SOR FULL CORK D!5PLAY KIIPUT SWITOI IS IN CICITC PUHt A'NS I'lON CT4$ ( tVNP 'A'NS RCF. 4 CR CR aDSE j XKCIRC PUMP aRCUIT SREAXKX SA(EAT Ta RKCUIC tUMt CYLCUIT SXKAXEII $ $ (AEY Ta ) RECIRC PUMP TRIP LOGIC A TYPICAL FOR LOGIC 4, SVFFIXE'5 SHOWN IN ( ) Rev. 19, 1/81 SUSQUEHANNA STEAM ELECTRIC STATION f CISGS> CR CR UNITS 1 AND 2 A FINAL SAFETY ANALYSIS REPORT Rt'T 5'YS A (4) Rff 51$ A (Sf TRIP OUT Ot SVC REACTOR PROTECTION SYSTEM CR CHS IED FIGURE 7..2-1 Sheet 4 I I y t ~ 'I 4 t I h tj I'l tl t P y y tl klkt I 2 POSIT)01 'pxSVITCN C t Iitk J I0 1 0051 Jl KKTLOCK OPCN P05IIION fCN LOCJL IN(V $ (IYNYNH 1005)TIOH Sv)YCH SXSP( rcfakf.- avfo - tfot 5(AL Sl '5 15 RETURN VO SO)IT)VII SWIYOI 'CLO5('I'JUYPJ UKU'5KUND fROII Jill(O CONTACTS 'STOP'AIN'f NP IPO s(IYIAIHNQ I R(YUkH TD 'AUTO IN "START C.t RNS a CONY ROL SUIT CH CONTROL 5VITCH (ONTROL SVITCH l1 DP( ~ IN C(05t IN '5'flRY to'l l IIok totlf POSITION SKJL III ION I 1l Ill TION SLOV tKRNISSIYE VNKN RN5 CR RNS Ck 5)CHAI. I totlf(01 5VITCN tfakf JV)0 Sfot I CONYRDLLCR YUkli1t STOP JV1 5tklks Rtflikk 10 'JVIO XRSSII( vakH AVID'VllNVlL YJLYC IS 101 Dffit SRON 'OttN CLOSE 51 JTION FULL T CLOSED IJI IR(V OKN FIC LIIUI ON 1500 5 VIYCN YJLYK ~FOR VALVC tfkN155IYC VNEN P(llNttlvf VITN Cokf ROL SVIICN TVkslat Eall SEAL IN CONTROL SVITCH laf 5flL l1 VJLYK Soll IS )1 AUTO'OSITION IN Sf tot)1)01 FVLLV 'Ottk'1 VX (01 l)1 CON Tt ~ t 5 LINII '5VITCH YJLYE 12k RNS 0-)2 RNS Ck LOV SICNJL 5(LECTOR ttf 5 LOCJL Pk R LrJSS IVk PNRLJISSIVA~ CDHTRDI. 5VITCH I ~ 510(" OIXLL55VALVR POSITION OPCN CL05t YJIJJLC CLOSIIIC PIALV CIX)SCO tfRNI5$ IYE VNtN Cokf OIL CONTROL SVITCN RNS ~ k($ 5. It LOV w 'STOP DC RCvtktlkl CokflCTOR T2 ~ OLI LILIIY OLI PCS II)01 Jl'S TOCOVN Yl Y N 0 Soll TVXSIX 50ttl Stlok XNlUST OOL CLCCTRONIC IVkllXCCOYERNDR C01110LLtk AND Rlkt/SICNJL C01YCR(tk SW ifCH VALVC Sw(TCal UALVC Cj RN5 LOCJL ~ Rtf ~ IVRSIRE StCfD CokfloLLfk / La/ xtkr war l / 1 A L L DRVVELL DRTVCLL CLOSf 5 I ART $ 10t START 5 Iot INSN tkt1 SIIRC tlfNISH 5SVl f OC Rf Yfkslkl CONT ~ C TON It 1 OC STARIER Ttk OC 51AkIKR Ttk ~5 ~ 015 11 (l) si(I a 5)e nck ~ 0<ID <c) wc I $ -src 5 P05ITION SVITCN SftllltVPtLYYlY 'I YVXSI11 1 S OI START Yl(UUN PUNP Jvxklakv 01. pipit ao p kvs 1 START ANXILIARVOIL PUVIP Sfot JVYO 'STJRI \ vtlcaL soa cooalas valtk SUPSLv vaLvt No Sots) RKS ~ RTS 5 Rtf 5 Stlal REYVXN TO AUfo PULL 10 LOCK Tlill)RC AUTONATIC INIT(lf)01 CONTROL CONTROL SVITCH YJCVVN TANK C01fkoL SVIICH VACVO)a VALIK IN 'Sflkf C0101ESJYC ik SYOr C(PIPE))safe t05)1)01 LET(I. NICII t05ITION LEV I. LOW REACTOR ktlCTDk Ms'~ LOV tat 5SVRE L51 1 RNS LSL nDollCa)-(l ~ 5 TAI Ooio (C Lt ktr ~ Rf PO Rtf 5 5 SOSJYOI SXOa Ck ROUT( )0 SCPO R5 (1( /' r L 5()a IN START STOP OC 51ARICR (12) INI ~ RClCTOR Nlkolt (cakoirfvklc cauofa)SKR Yacvvkvlaxcok Ntlv FONS HICII VAICR LEYEL Rtttf PVSHSVITON LI5 ~ tl 102as TINSINC JIIXIL)lkTtoVltktNI Rff I Lt RCACYOR NISH VJTER 5KAL-HI LCYEL 5 N- V l tl g ~~ ) I I.I5 ~ Lt Not(D KVI REf I I%XVI))ilf ISKDS YIAII OP(1 FUROILIC HICN TURSIKC KXNJVSY Hill( TVklklf LOV PUNP lVCTI01 tltstVKC 5VIIOIDKPRC55 I ~ V51$ U I 01 NOT PERNI55IV E VNEN LOV OUK RSPCKO EXNJVSY tkt55VRC tk($$ VRC (NtCI PVHP) TO Iklt LEYEL sita JL IS tkttCkT I C-2 Lt v AIIX Jt OCNC t LOCAL t 10lla ~5 NO)I'5 P5 NNO RNS CR AUX Ot YiCE KOV)UKNR(SS RYISIN( Vk(55 Ittivf llk(55 ISXAIOI OVIR fever skaf ao)o Y( (a(xf(RUED tR(5(HT NNLE aosto Ilk fktkslft SOL TO 5aiika lo'ff 5 TRIP TURSINE JUX ofvicf > LOCaL ktf 5 AVTONJT)C T1IP 5 RCNDYC TRIP TVR ~ lkt flitCONTROl Rev. 19, 1/81 SUSQUEHANNA STEAM ELECTRIC STATION CC A(KJSRs COHYJKS)k It ~ UNITS 1 AND 2 flklR( (XJJNJST Ya(VUJ FINAL SAFETY ANALYSIS REPORT (a(aa(a v(K po lo) ~ OUI (IT)KM, Fok Fl)1 sl)JVO) HPCI SYSTEM FCD FIGURE 7.3-7 Sheet 5 0 YO I 4 4 A JDQ *""'9 ~,D 4 4$ 4 ~ I"2 < N I lD ll, ':-, I, II *D 4~ D C'4
- D t
4 Ni 4 ~ I lDQO 'A (NOTE al 2 POQTION SwlTCH CLOSE AUTO'(51 RKACIOA MAAIIA:a(0 CONTACT HATK2 L (V(L ADOV( LKVKL2 Taw ~ ll ~ $ IATPI NOT Us taM 55IVK WHftc ~ IPMI$5lvt IN 'ROSE NO25 4 Uala 5TKAM ONE IPI'55 a(AC(PI 'OQIION Pa(55 AT TURD Nf MOO( SWITCH IN SAON aaovf sf laoa I 'PUN'05tltON COMMON TO lll tNROAAD MAIN ~ NS CR R(F 5 lOCAL DIES slcaw IsRaltoe vaLVES sottatl,o.o LOQO'C'AON Pf A<<55IVt IHCN ~ law 5TKAM LPC 1(ST SNITCH AAO lOW OFF AC SOLKNOCI LOQC DC QX.KNOIO lOQC 'TfSI'ANTAWCO CONCIH RAU Dtt PfRMISSIVE Pf atesstvt NHKN A$$ $ 4 leCH COWCCNSE R COIIOEN sta CIDASS VAO IS La(AT(a TCH IS IN DVPA5$ LOCC THAN SET DONT Pf atesstvt wHEN PEA<<55IYE wlcEN 'C'A vs LO(a' aHs 1()1 SW LOQC'C'('9') AUX LOQC '0A') AUX P( 'I(ST P05ITION fkfaQ(to
- UAM ST(aM LAC NOSCA otect (ataQ(KD OEIACK Dfaaesslvt <<CN ICSH RAPAIION TRP FI(f,2I UAN 5T(AN LDC '4 AMS CA kUX AUX'EVICE FLOW NOAMAL OA FROM LOQC'C OCVICK D(LOA'els I
PEIbesstvf Iecta I NOOsa TUIIDIIE 5(OP VALVfS Aac LK55 ltc ate 90'4 PKRMtsstvt IHCN pf atesstvf wHEN PDS Sw CD PERMISSIVE wHKN CONTROL SWITCH Is LOQC A ('0') AUX LOQtC R')'0')AUX DKVICf tNEASIZE 0 CEVISE EN( RQZKO P(f 4 IN'TEST'OSITION P(lHtsSN( tec(N MAIN $ 1(AM Lo('0'(OV Itw$ aa N.s NOlHAL 02 4(LOV eats MOOTA L~ Dtlaesstvf WtCN a(ACTOI DDESSIIAE IS Ow <<QC PRfSSUIC 5OAAM SET DONT CA A PS NOt04 pl ace sstv( NWC N Mate ST(AH LQ('C SLOV WOlell 04 FROal FROM LOQC'C', C;Zl WFIS Nooaa D(LOV LOQC'C'UX CA ANMINPATE WHEN CTPA55 SW STOP VAlvf AIIO IKACTOR PS ALL r / I AT Ptale55IVK STATE w Ca CR (StAL M) (A(5KT) / c P(AID5QVt lecEN PKAUI'sstvt NHKN F((HIS(M( WH(N AUX DEVICt 'A'N(RQZEO pv)A(5(1 vcaOaao Mate Sl(AH Lw( D Tl SLOW NOIHAI Oa SH I ~ (I OV N 5 KNfRQZt SOLKMOIO ENEIOIZC 50LKMOO DEVI D I TKST SRKNOD PAD( VAI.VK AC ~ ILOI VALVE 4 NOD(A I FILO vALvf RCF. IS ROS($ vaLUE aT IASH C PCIaa55tvt wtce CD(ED WHEN DOTH PERMISSIVE WICfa CL05($ VALVC AT SLOw ~ AOI MILVK 5OLt NODS LDQO'D'US pf AIA55tvE MINN Iatl STtAM LDC <<Ql fiear SOtt A.D.C,D alx Ofvlft'R'ANO'0 SPK(D INCN 1(51 Aal R IN(eccl(a MAIN 5'lfAll ~ MANUAL SW 'CLO(KD Il DM 0 ENEAQ(co ~ I(01 VALVE SOLENOID TUNNtL T(MD CIS4I fOa IDQC 'A'1 IS ENERCUKD (NOTE I) afLOW 5t'(PONT Ctsat fOA lDQC' AUX SOR IOQO 0 II DEVICE C 1$ 'ISls NLOOA ! Foe 'C'oil I 1 L. I VALVE LNRT SWIIPI 10 AKACTOA PAOTECIIOI STSTCM (atf, ~ ) ~ fale5SIvt WICN AIDULIART DtVICK ~ IAIN 51(kw LDC KNEAQZK0 IUMCL PFffa(NTIlL FROM LOQC 'C TEND 9(IDW S(TPON'I AUX UAIN STCAM l5OLATION VALVE AO f0224 FOtak C ls LP OEVICt A (TTPICAL FDR AO SOtt ~,C,D) FO(2 ~,C.D N40$ 4 /Ca INDOAAD Male STEAM LINK ISO(ADO N VALVE STSTtw W (NO'IC I,S(9) TTDICAL FOR OUTDOARD (OITDOAAD DEVICKS DI DAACXETS()) ~ WMN $ 1jhMLNC LCAA CCTECIICWI C Isa(c SCS( LOS IO ~ EAUISSNE wtCN 0'A NOT DI MANUAL I SOKA DON RUS C4 A StOW LOCIC C' ((HNSIV( Wtl(N IIAIIISlllH lta( ax(a l(IIP a(IOV Sll IONI ka ((vista( a(os) llf tl ill Olvt(C 5 la Uaw Slf AU lINf ISOLATION A TTPIOAL SOR LOQC 0 I KXC(PT Rev. 19, 1/81 FOR LETTER SUFFIXES w<<CH MaLl, Dt 0:X'(T) RCSDCCIIVCLT (sff NOTC 5) SUSQUEHANNA STEAM ELECTRIC STATION UNITS 1 AND 2 FINAL SAFETY ANALYSIS REPORT NUCLEAR BOILER SYSTEM FCD FIGURE 7. 3-8 Sheet 2 IO 0 LOCIC A LOCIC C 5TATIDR all(EAT 3 STATION CAT'ifRv 3 5(f Pff YADLC)lroft ~ Of f ADDIIIOVAL UVCTIOVS SVNCN(S NI CH THESE HICH SEAL N OavvfLL , Davv(LI. SEAL Ia ~ RESSURK PRKSSURC Ad CII- AUT ca HOI OA <<5II)c LP OCVICK z P05ITIDA Sv RORHAL a(5Cl SPRIVC Rf fURN ~ CRNI5$ IVC Ual(5$ Pf RKI5$ IYK UVLE 55 10 ROIIHAL ASC Oavvlll Pa(55 A~C OVVVllLPa(5 ~TO 1 a( 5( I SMTCH la RES( I 5V ITCH IN ADS I(ARMS W CACH Ot 2 SYSTEMS Todf AHHUHUATCO RK5cr Posl(IDR RK5CT'0511IOL' SKPARATELY.TYPICAL SYS1cll 5 OENCES ARLSHDWHW DRACKE'1 f ). aas ca D.z ALARM fUHC TIOM INITIATION~ DENCI I' I MOH OHCWlll PAESS 5IGMAL, SLALCD M DRYWEU. PRESS SVATCM AVH DEVICES I Pf RHISSI VK V V(V atACIOR VASKA / A CR C pfawsslvE afAC'loa VA'ICR VHKA Ltvflttlov Taalt 1 lfvCL tfLov L fv f L I I ala SCIL UI LOW REACTOR WAT(A LtvfL CONFIRM(D LEVEL SYATCH AVV DEVI(fS LIS HOAZAIKHOAZ53 LfTEL I IRIP NO~II lftov L) SCRAM I L IS RKI'ITA(k(IFOR L IS LP AUV I No)1 A L SCC Aoolvcovlt FUVCTIOVS 10) I C acllv OF Tutst Svntvts AOS TRIER INTIATCP TINING CICVICC tDS AIKD) P(RHISSI YK VH(N Mu(UL lvttlTCN SAISKH ARV(o (R LOG( fDYPAss A( CIC5(0) PUSH OUT(DMS I SCM W (f1(A Ilo SECCNVS Rtac'loa VATER LtvEL t(Lov tea/ SCAL ~ IH VVVAIALPIITIATCW SCALED IN Aticvc)ARA to( aio) Olt Aua PCVCC5 l(Vtl. 3 IRIP C K-z L IS l / AUX D(YI('l A55 Coal SPRAY IRKR PUMP RUHNNO FV(SSAK SVITCIE5 OSRW 5TR(AM PUMPS AETNA(( AV( CEYC(S Of ROA2A 5(AL Itl 1 LA ~ TAOll I AUV OCVICCS IOR OYSTKH OUT Otv"CC OUC IP Tt5TIHG. RCPAIR IALAltw OI'(RVICC 1 P05ITIOR 5V
- UNCTION OR (005 OF CUCIPT P(MCR Pf RHI 5 SITE VVLf55 IYAHISVIKUvt($$ t(AVINtic uwllsl IOLIL All A(lft VORHAL at5CT ~
5talac RCTVRR ocic Asc RK5(1 5 LOGC ACC A(5(T IV Rfslv SNITCH IH a(SCT DIVITCH IS IH 'acscl 10 RORHAL POSII IDR POSITION OEVCE LP FICUCF POSIT KIN VALVE LVAHIHO 5(C Ruc RHS Ds 5tC TAO(X I SCX TAOLC g AIIVPCUT(A (lvf wlgt() OWIICH HV Rtot 1'ODITCPC OAIITY RELIEF VAlvc AHY 5IA VALVE DWIIIH RMS t) 3 OWIICH M OFF POOITIOH ~ H Ofr PCXNTHHY H A lc u AL tv AHUAL INITIATION ICHTIATIDH UNDATDR tlvf Wwvl IRITIATK 'TIN( PUSPDVTTON't ~ USHIWTION C DELAYS Iso 5EC CONC SPRAY COAC SPRAY '3 Pd Clt OA RHA HPCP OA Nca $ 55 ca CR RUNNING PIPU'IPYFAHG ~ CRCVSSIVE llp 5to APTKR CA ~ 5 Auv TABLE 2 URIIA1ION OF ID5 TASLE)l H.C } 5 IlPCTVM OHOVH M CR SVDTtH ORICHETS () IOS K.l ctl ps tcootA)OI 1ACLK 1 MITIATIHG OCVCC N) 3 +EH PS'HOIOA P(AHISSIV( 'VINN PTICHIDSIVC WICII I APS LOGC 'A'fd) M ~ T PHINllC IPC H AOS SlS) T(51 OTATISS (Oat SPltAY NUMD NA PUMP tuv\ piper A PCAHISSAFK ItHR PIPCP WH(II CC PCRI45NVC WICEN PERNI55IVf VV(A C ll RIPWINC IIVHHW6 0's IS Ruutcw6 A COR( SFRAVIRHlt PUM ~ RIR NAG CONC SPRAY AHN PIPIP A AUHHIHC RIMHIHO AIPPP ted LP DCYCVIVC OVDTCH d APO LOGC~A') PS Cti-IIOORA LP R(f I AIN (ccoccw uc DAAEHET f) VA LP LP Rff IC RKF 6 ADS A'fd) MAIAUL HAHLUI atl Or OcRVCc OUT OF DCRVICC 1 FKTUSIVE VAEN PCTUASSIYE WHEN NDT N lIST AUV ALLAY NOT N TK51 AURIUARY a(LAY ( AOSWLVT~AD) ROVER HOHIIT)RMO OCVCC Ji ( N(aoiz to KFC foll (0 ~ (IC JO( CR AU( RE(AT CR AUX 3 FOSITCFI SWITOl NLAT CR VSF( N'AUTO'Of f COMRR(R IHVUIS f(R AOS YALV(5 MANTAIN(D CONTKT lOCC A.C COICHON TO ALL HGH R(ACTOR fa($ 5WITCH C IN ol(N (Stt R(f I TACLC X FCA COMFUTN IHVUS NO) AUTO 0(PR(5$ URICAIION SO)ITEN Saf I 1 V/C(LI(I VAlVCS STATION dlvvtltY A STATION f)ATTE RY (S P(AMISVYE Via(4 IVITUTINO Cf Y(K ~ OTH LOOK ASC SWITCH A AIPI IICIAY5DA SWITCH 5 ZOOS PHICH- scf(TT a(LRS Yllv( ICTIAI(o Sv fa(SSIR( THAI(ION SWITCH IROH LOAIL D,D catctctW IN OP(N Ot(a AUlo Occ H Auto IN OP(H SWiTCH OR PAR ffASPE Po SI TV0H HU HTMH(p HAWIMNCP CONTR c'1 POIITIOH l(tvc( Nfl TDAIL WIO DEFMSSVVIIA~ THH lcc(vc a(u(F IMYIS CIWTALT I f(AMIS)IV( 'VHM AUTIUARY a(LAY SNITCH T.'Al Nlitf (,Rus ICIL ) RHS CR N(CIC) Nt AOS IALVt ACIUAT(O SY lOOC OR PWR FALURE XC I' Aufllllav a(CAT Ca(RCI(fo ica/ ica/ AUIILIARV Rtl Av Eat RCI zf 0 i FR I XCR/ a(l cc AV i,CR/ 0 AVI O(vl(t A C 0 / x AUI Dtvlct Ca / A 0 / AVV DCYICC / A C VIH(CCACV(il PA(55 CH lt(KIIVI LOW WAIfA IXVTL tcls Vl lttl fRON ACCUN FRDH ACCVN Pool AOOC (THRUST JIA CA C TACLK ) VALVE A VALVE a fstc oc TAIL'*') (stt VALVE'C'Sf I OCVAFL A ) K OCIAIL A ) ttcpl Cwvv(tl I SH.C PII(5$ OA ACKTCH LOW Walt A LTVTL 5HS IN ltlv Rev. 19, 1/81 CR SUSQUEHANNA STEAM ELECTRIC STATION A UNITS 1 AND 2 SOLKVDID tatacllCD VALVC Otfas FOI) LOCAL ( Hda R(A(IDR Pa(55(A( IAIY( C Vi 5(ats WITH AOS WLVtS Sf AVOW VKNT a(aciOR THROUt)I SCIV(V) fc(N)IN N AOS MDVK) FAIAVVTtST vfccc ouac FINAL SAFETY ANALYSIS REPORT SAIITY/RELIEF YALvf. AUTO o(PP(SIUAIKAvcu Atr I Tcall'I (TYPICAL FOA LOCK 0 5 'D'EVCCPT OIPVIV 5(COCC(S 5 5 0 ACSP(CTIVCLY LDLC AID 5MIC A$ LOLA A IC Atsvtcvlctl Y, CVC(PV COA l(TTTR SUCIXCS OR AS HOTCD u JIA.JCA 0(CONC Jld,J(tt NUCLEAR BOILER SYSTEM FCD SAFETY/RCUCF VALVES FIGURE 7-3-8 Sheet 3 7 I ) ( 0 'IO If I If f~ . ~ LOOP Loot ~ I PUNP 'I't tiJNP 'ET TOTAL SLOP TOTAL SLOV REF 5 ICOEl Ck Kfot~ Ck I ~RCFR I RCCIRC LOOP'A PUMP RC)IRV PUMP TS R CC I RC LOOP DISCNAROC RCCIRC I tfRNI55lvf VNEN tERIIISSIYE VVEN VALVC I'OSIA 'A'RIPPCD I AUX DEVICE A AUX OEYIEE 4 RI PCD O'I5CNAROC 15 CLOSCD I I f Nfl LIE ED ENERCITt0 YALYC FD DID IS CLOSCD UMI1 AUI I AU li SNICN ocwcc I AUX D-3 AUX 0 vlcc LP INI I LP I DKYICE Dtvltf 15 5NITEN I I I I C 1 I PCRMI55ivc 1 I PCRMISNIVC WVCN RlgCIRC IAOC 1 I PUMP 5 I5 RUNN IN 0 I I ~ tkNISSlvt VNEN AUI Dtvltt 4 f1fklI? Eo ~ KRNI55lvt VNfk AUI DEYIEE ENERCIEED 'I WNCN RCCIRC PUMP A'S I SOC RUNNINO AUX I AUX ocwcc I AUX DfvlCK W5 AUI DEYICf DCVICC LP I I 1 PCRMIQQIVC I PCRMISOIVC I CN RCCI RC YLV IDSIPISOPCN I Lppt I'LOV Sill<At ! OOF 'Tc DINCH VLV FDOIA l5 DPCN I 1 OR NATIIRAL I CIRCIILA1101 Ok Vvt1 AlL Jtf tiliit5 lkt LOOP '4' LOU 5ISNAL l 'l'ET loot Jt I tUNPS fLOV SIENlL '4'ET PUIIPS SLOV SICIIAL I ~ RDWIVVC DRIVE fLOV TOTAL Jt'1 fok NATURAL DRCULAII01 Ok VVEN ALl JET PUNt5 PROYIDiiil Dkivt 'VVtk Loot ~ ROVIDtVC JTT PUVP PUNPS ONLY Dklvf SI.OV,DR LOOP'4 JCT PUIAPD FLOW 5XJIAL 101AL JET LOOP VIIEN Loot ~ ROYIDINS l JET tUNtS Jtl tUNt ONLY DRIVK SLOVqpk tilvt floV ARE SLOV WUEN LOOP 4 JCT tUMPA ONLY PUIIP flov lOOP'1 JtvtUMPL IIOWSANll, VARN LOOP'0't I PUMPS ON I Y L. L $ UNNER PADYIPINDJtT PUMP PANE FLOW SUNNER PIIDYIDINGJET PUMP ORIYL FLOW AUX DCVICC A XXDS Ck XEDT CNCROiZCD ( RCCIRC AUX DCV LOOP'5'CT PUMP ONLY PROVIDING CR AUX DCVICC CNCROIXCD WX DCV CR 5 DRIVC FLOW ttkill55IYE VIIEN AUX otvlft 'I RCCIRC LOOP'A'CT Dt fktkCIEKD PUIAPSOIILY PROVIDING AUI DR iYC FLOW otvift l ,t J ttki155IVE VVEN PKRNISSIYE ViitN ttkNISSlvt Vlifk AUX Df VICE 4't AUI DEVICE AUX DEVICE ENER LIE ED 1'lltktiff0 'A'NKRCIEED AUX P,IS AUI 0 IS DEVICE DEVICE Dt'V"itt Rftokotk Diff PRESSURE/ RCI5 SLOV ktfokotk TOTAL JKT tilNP SLOV IIEA5URKNE11 51$ 'TEN SCIE Rev. 19, 1/81 SUSQUEHANNA STEAM ELECTRIC STATION UNITS 1 AND 2 FINAL SAFETY ANALYSIS REPORT NUCLEAR BOILER SYSTEM .FCD FIGURE 7. 3-8 - Sheet 4 I t i 5 10 CLOSC PS OCPRCSSLO SEAL'IM SCAI IN RNS RNS ~ 42/0 M Co ~ Nt/C MCC C= PERMISSIVE PER/N55lvt vNCN Yl(VfPOSI (ION 15 Pt RNI55IVE VN 'IOROVE SV IRI~ PtRNISSIVC Wv(v VALVt POSIIION P(RN15$ IVE VVLESS IOROVC 5V 'I RIP P(RHISLIVE V@LESS VALVt IS POLLY APPVES TO CIOSE PS VN LESS STOP PORO OHIV VNLCSS STOP OEPRC SAD PS DEPRESSED AXAYEIOSCD ON NECN OVtr(olo IS IVLLYOPEN ON Nt(ROVER(DAO O 05(O PS D(PAC5'SEO L IN I I ON IOROVE ON L IN I I ON Tolouf ON ~ Ulflv ON SVI ICN YALYE 5 VI I CN VALVE 5VIICN VALVE 5VIICN VALVE SHIV<4 VLLVt AMS CR A MS CR RMS 8 2 RMS rfRH ISSIVC IPAESS VALVE IS flAAYOPCN PVVVSSIVE PEAHISNVL WVTN VALVC P(6 VNlf.ss IOROVE I'5 RXLV CLOSED SW TAIP ON HCCH D M ISSIVC M I SIV LI HIT ON OVE RIOAO WHEN VAI VC VNLCSS TOROV SWIICH VALVC LANT ON OM POS IS fVLLY SW TRIP ON Swlfov VALVE VAI.VC YPPCN'IMI MECH OVERLOAD '5WITCH YALVC 0 OV SWITCH VALVC P(AMSSAC v CR/ v,(R/ VNLLSS VLLVC 15 I(RAYOPC N LIMIT / 'l4 / A SWIICN OPCN CLOSE AC RtvERSINC CONIACTOR lt ~ NERO YEN( VALVE No 1001 ~CR/ (IvP fol Ntlo vtrv vl(vtS NO foot 5 NO r0051 A (IVP fol Nllr Slflv Llvt Ovllv VLLVC Vo fotl) / g(TTP fol 51tlN LPC EOV/Ll?ER IDIO)p OPEN CLOSE AC REVERSINC CON(ACTOR (t ~ PCCDWATCR IMLCT MOTOR ODCRlTCO CHECK VALVC MO FOSSA (TYD I OR MO POSODI SEAL IN 5(lL IN ~ t/0 ~ NCC lt/0 ~ NCC SV AC, QSV AC oprM ps I'N5 OCRC55CD PCRN155IYC VNLC55 PCRNISSIYE VNLESS CLOSE PS DLPRCSSCD NT RNS RNS N RNS HT RNS ~ CRNI55IVC VNEN PERNI55IVE VNEN PtRNI'15lvt VNEN tRNISSIVf VNCN YRLVf f051(ION 15 IOROVE fs DELOW VALVE POSI'(ION 15 IOROVE 11 SCLOW E 9051 OPC N SWIICH 5f I POINT >IOV 'OPCN' SWITCH Stv POINT LI NIT ON IOR. 5V ON 'LINIT ON ION. 5V ON NORNl(LY trtRCIIto 5VIICN VALVE 01'EN VALYC SVIICN VALVt CLOSf YALYE rov SvAE CN(cr vo st ~ OVI Of fLOV 512(lN AIR SVPPLV SCC DCTAIL I A'CC CXHAVST AIR SVPPLV DCTAII SNCCT ~ 'A'HCCT CXHAVST Rev. 19, 1/81 SUSQUEHANNA STEAM ELECTRIC STATION UNITS 1 AND 2 X CR/ ~ CA/ FINAL SAFETY ANALYSIS REPORT /0 R i /C A CL05( P0511145 SVIICN SOLENOIO EvtRCltto YRLYC Ortr OPEN AC RCY(25INC CON(l(TOR lt ~ NUCLEAR BOILER SYSTEM lo TOTAA LOCAL I CCDWLTEA INLCT VALVE MO POIIA FCD (TYP POR MO Toll(if fttovlv(RACIVAIOR CvfCR vlLYf DISC (IYp IOR Ao roTAD) FIGURE 7. 3-8 Street 5 10 ff I L Il * $ (is IIIIIISI(CLCAECXI loooi ~ I START I. 1K CINTtcl 5151(H ls IalvN THOrl 5r5T(a I. Dr(AITINC 5(DKV(t AST(k lcv vli(k LCT(L (1 HNH (NHRLL rt(ssa( sickle ls n r(A(oc 1 I COOITIOI l /'I LCR/ OH I 0 W 0'AVWCLI I I/I SIST(H I 51lA'15 ~ 105(C 0((kv / ptCSSURR I Cool C 0011/0 5T51(II I I 5TAATS ~ Ni 5(C 0(ilv ~ $ 'CH HO I IA I I f(lf(b I $ 005l 51ST(H I Cr(VS l<<CA RCAC LCH rktn. $ (IH. I f0054 $ 151(H II ~ Or(as utta t(lc. Lo/ racss $ (ol. f Dl1k 5151(H I C(05(s It Or(1 No 0(ul t(ACTOR CR tfACTOR Pk(SS PCRNISSIVE I I S015l $ 051l SVSita SIST(H I 11 ~ C(05(5 <<Crta ~ NO 0(LJV Clo<<5 Jfi(a flcv t51JRIOCD I afs'. 5 ~ c rot YE$ $ tL I, / V VHCN LOV I stf f(014 5T5'ita I I ~ RIH(silr'l(k Slo/ (sikf(ISH(~ 1 0 LOv LfvCL ilk 101/A RCS I I I I JODITIOIIAL SUNCTIONS sft 0$ 5vliclvcs Cool l/C Ccol I/D au 10 10 5(c 5tC, I Lkkcs SIN 5((RXN(t JS CDNI IiIOI 4 iCA/ iCR/ I I a(ACTOR VK55(L V V NICH OkvvfLL I t. 515TOV II CIACWT ID(NTI(JL 10 CltCDIT $ 15< Lov LCvfL I ~ Pkf55URC I Ivs(u II LIS 411 PS CN t SVSTCN Us(5 0 ~ D 5VITCHCS T(sikR( Oc(k YlLVC lvrk55 SIST(H IOiil f 0111 Nol/0 LP NOHC LP I ANSI C 001A.C COOI 1,D I NHI Silu IISJ55 VI(V($ r 011A $ 0111 I Iasolko 15LN Vliv($ $ 005A $ 0051 kfJCTOR PRESS I 1(sikR( oc(a vliv($ Sooik ~ C014 Ptklu55lvf I rvv 5U(ilol vk(lfc $ 001 ~ Soo is VN(1 LOV T(SI 4Trl55 VN'K So l sl $ 0154 Ou(4(ako VlLvt f Doll S Doll LP roo Ho(as IMLL tc raoiccno vITH Dvtk(ao raonciiov. onaiolo Not(0 ttil15 10 SC lrrll(D 50 li 10 Mlavll1 rota OI INTDR ls lOC JS $ 055IRT V<<Hot(1 IHCOIAI( DAM(c 10 ITITa5 ca Hkul '10 CH(ACCN(v RCS I rota 515. Ov(k(IWI fairs '10 lt Iirl55(D Uat55 Vlivt NINA i(51 Vkiv( Novas SM(L I( IROVID(0 vl Yi TH(IML Dvtk(IID TAI $ 5 JND ANNH(lk(la Ia 400<<IOI. Vliv( HOT/R Cll(UII5 lk( 10 4( rtovilto VIIH IA(Alta SHa( CILCVIT Cak(IT rtoi(CIIV( Ill/5, ~, Ho(lv( Pock Sa 5Tsiu I SOVS IMLL DICIIITC fkol J Dlfrtt(11 Hlvulc crckc(acv lc aus THNI rock sa 5TST(/I I, Hfvs, RC5C'I ~ Oak Sca YN'Ks I ~ IlCH 51ST(H SHNL okiCIaln flol TIE 5NC 405 svrr(TIac Hrv rota. ((HiloL Soak soa puus 4 wlv(s Dr sv5rta I OClc Cc SROI 4 tiff(IXAT50tACC Ivla Ca(a(L POCR fiR ST51OI 1, PO 5 SVITOC(lk 0(vie( SUN((I(a IASN(ks NCI 5$ tC, C'Ii.t. I
- 4. kil 100<<H(1'I NO IISTRORITS Jai rk(SIKD IT 5TiitN 10 (tii) OkC55 LICNT ON Vata SCALED 11
/ 1, 5tt ltf(NVC( PCID'5 ra JIDITIONL IaraMTIOI Ol ALAIHS, YAlYK INIICAI INC LIONS JND rao( 55 IasfauaaIAII(H, NJNI/AL SEAL IN IkiTIATION 0 Irk CaC srtkv 5151CII 5MLL CC 0(51(N(0 Ia ACCDRDNCC VITH kCf 10, 5(f AOTK 10 10. Tkk(SSDOCANI5C NDT(D. JLL a/0 5MLL Sc 5 $ 05IIIOI 5VIIOK5 Clos( AUX DtYICC RNKD P CONTROL 5V PCRNISSIVE VNCN CONTROL SV MVTIPJ'DPtlP SPA<<1 k(TIRX '10 AUTO flol ((05( Ol OP(a IN Oat 1 VkiVK CtI IS SULLT, $ 004A IN CLOst ll Ho roolk/I, fotÃJ/l,.SOIIJ/4 VAK5 Alf/ID(0 VITH k(V(k51liil'ii Scl(af, $ 0$ 1110N CL05to' $ 0511101 RHS NUT 01 RN5 P-b SYITCH VLLYC LlollvDN WH1N OH ~ JAH OIL DVKRRIO0 LCR/ W RClC101 PRCSL kfLCTOR Pktss PCRN/SSIVE VNKN / PKRN/5$ ivt UNI.K$ $ Ref tttNcc Ouclkkvvi PCRINSSIVC ~ CRNISSWC AUI SICNJL VALVE IS ~ N Sfkki Tk/P ORYVCLL VNK1 LDV VNCN Lov IS PRESCN'I fULLT CLOSKD I, STI 1010 NY(L(kt Soiitk STITOI SCID ~ LloltfON Wvtu ON flktt 0/K5KLS COO(.11C KOUIP A AUX ORAL Nl L I HIT 01
- 1. 111 H/Io 0, Cl1 1010
~ u(L(kk Doll(t Sisiol SCD k(5 IDull Iali toavkl ST51(/I fCD H LP Not/0 LP SVI(CH ~, (Oa Srkkv 5TTI(1 rli0 ~ JAHUAL or\Rsuoa A 0C Ov Jf NOXIA DEVICE VALVE 5 11 1010 11&010 cac srkkv s iu 0(s. sr(c. OT JK 4. ~ I ll<<0 PCRNISSIVt VNCIV LCR kff I RCS I DCVICC 1, Sl '1010 HPCI 5T51(H fID RC IC STII(H CD I puup'A (c I ak/0 W ~, All~ 10'10 10CIC 51NCLS LVNLAAL Y. (11 ~ 1010 AR 5(51(H PC ID AUX
- 10. ACIN050 tilC, toulr. 5tr fok Slf(cukko 515.
OCVICK AfACTOR PRCSS AELCTOR Pttss, PKRNVLSTVR APVCR CLOSC PCRNI55IVC Pftalsslvc Svavtu 'Ol CHAL IN VNK1 LOV Vaf1 Lov I'0 PRCSCNT PS Otl LP Ps Otl LP AUX Avl CR NOXIC Not/0 otVICC OOVICC ~ Rtf I RCS I 'TINK OCLAY ~ talkN\IVR IN<<ON Pfkalsslvf kl/fu Ol CHAI VHKN PERH/SSIVC I/NLC$5 VAI.VC IS Pt ANISSIVC IOSCC APTtA STOP ~ a patSANT OVKAIOROU(D JSICR 1111 SICNAL OI CHAL IS 0 VN/Lf CL0511C PRZSONT /C AUX Tokol/C 01 AUX AI/I C PLRlHSSIVO Dfv ICE 5VIICN VJLYC OCV/CC DCYICE UNLASS closC Sr CHAL 15 PIIK5taf AUX PKRHI55IYK VNta CONTROL SV ot VICE Ck JUYO CI CHAI IN STOP IS PRLSLHV POSITION X P0511101 SVITCN JUI RHS STOt AUTO Silt( Spaac acfuaa vo.kuvo. Of VICE SRON $ (OP 5TAR( COIITROL SV ptauvsovt Ikcxls PCRNISSIVC Ulv(,CSS REV. 31$ 7/82 IN Stkti STOP YkOHJL VJI.VC IS POSITION IS PRC5taf SULLY OPCN CR LCR A kHS CR kut OfvICC L 5VI'tCN YALYC /R L / SUSQUEHANNA STEAM ELECTRIC STATION UNITS 1 AND 2 STAR1 STOP OPC N CLOSE FINAL SAFETY ANALYSIS REPORT Jlk CIRCI/Il OktLXCR St ~ tcvcaslac CONTJCTOR 4t ~ Cok SPRAY PUHP Coolk CORK 5PRLV INSOARD Vkivt NO f005k YTLt(0 TftQ ITPICAL SOA Pi/HP Coo/C (10TC$ C ~ 5) t AoltS 1 5 CORE SPRAY SYSTEM TYPICAL SOR ST51(H C TYPICAL FOR ST$ 1EN t FCD FIGURE 7. 3-9 Sheet 1 D I I ( 0 t r t 1 4 I /' / Vklrt ttkAY NE ADER To tUNP Norok CORK 'SPRAY SVSTYAI I rot Of Cokf CORE 5PRAY IAANVAI INaIATICNI VALYt NOT VALVE NOT CORE SPRAY ltAKACt NICN tkfst ~ tlkrf NICN DIFF PRE55. OVERLOAD COOIA SY5TfN I ACTUATED SWITCII IN ACU AO PataKNI FULLY CLOSED fVLLYOtfk PIAN'OOIA TIUPPEO ~5 NOOTA Lt Dtls NOOAA LOCAL DY AK NCC AVX DEVICE L IN I I SVIICN ON YALYf LINI 5VIICN I ON VALYC DY At llco TYt N0014 TYP NOOK 4 TYP COOIC TYP FOR SYSTEN 2 IYP FOR 5YSTEN 2 TYPICAC. COAXIAL StC NOIC 4 ~SYSICN TYP Fok 2~ C Stt NOTC lo CONIROL SV Cokf ttkAY CONrkol SV Cokt SPRAY IN Ott N' FLOV LKSS SEAL IN IN 'CLOSE floV CAEATKR SEAL IN LOV POSITION IVAN LOV FLOV POINT tot l ICON CNAN fLOV toINT FIS RNS FIS 04 Avx Ac 4 RNS CA NOOCA NOOCA CoNT tfElrkfk RNI$ 5IYK VNKN PVNP tfRNISSIYE UNLCSS VALVE IS COOIA Ok COOIC OYEAIOROVED l5 RVNNNIC VNILE CL05INC TOROVE ON OT Ac SVCR SVI'ION VALVE tfkNISSIYC UNLESS ttANI$5IYt UNLESS VALVE IS YALVC IS fVLLYOtf N fULLY CL05fo CON avlk Yakavr LI NIT ON uNIT ON SVITCN VAI.YE A SVI'ICN VALYC Ottk CLOSE AKYERSINC CONTACIOR 42 ~ NINNNIN floV Ortkts VALVfNO foIIA Nort$ 2 O 5 TTPICAL FOR 515IEN 2 SEC NOTE lo CONTROL SV CONTROL 5V IN Otf N IN CLOtt'OSIIION POSI CION RN5 Ck RNS IIT A I N tfRNISSIYK Vkltst AUCD ELDSC SICNAL IS PRESENT AVX DEVICE ~ VSNOVTTON DKPRESSED 2 totITION SVI'ICN ~ aosc. - .Optk-CR tfkNIStlrt VNEN tfANISSIYE Uklfts VALVE 1$ ~ tkNIstlYE UNLtss ~ tkNISSIYE UNLK55 VALVE IS N ANT CANIED CONTACTt KCYLOCK IN 'Ottk POSITION VALVE IS VALVE IS fVLLICLOSCD OYKRIOAOUKO FVLLT ClotfD OrtkrokOVto VNILE OP K NINC VNILC CL05INC CONrkol SV CONTROL 5V I.I NIT TDRDUE ON L I NIT ON TOAOUt ON IN IN CLOSE SVnCN SVIICN VALVE tv lrcb YALYt SVIICI~ YALYt OPEN'OSITION P05I CION CXNAVST CXNAUSI RNS KIC RNS Ck AIR Alk SUPPLY SVttLT PERNISSIYE SOLCNOID tEANISSIYC tfRNISSNC $ 0ltNOID PILOT ttkNISSIYK ~ VkfN SOLENOID IS PILOT VALVE VNC N SOLENOID IS VNKN SOLENOID IS VALVE VNKN SOLE Nolo IS ttkNI5$IYf UNLC5$ VAI.YK l$ PEANISSIYE UNLESS VALVE IS PfkNISSIYt lf PKRNISSIYE VNLK$$ VAI.VC IS tNfkCIIfo SOL iocii Df ENKRCIIf D fNfktlff0 SOL Dc ENKACILED FULLY OPEN FULLY OPEN VAI.YC IS fVLLY OtfN OYKATOAOVED PILOT ALLOT LINIT tVIICN ON VALVE S / A / u NIT SVITCN ok VALVE Cl LI NIT SVITCN ON VALVE VNILt CLOSINC IOAOUE SVIICN ON VALVE A Rev. 19, 1/81 Q Ck I Ck/ R A ~CA/ aosc aosc OPEN CLosf. SUSQUEHANNA STEAM ELECTRIC STATION VALVR ACTUATOR YALYK OPENS DID ACVCAIION AND 1$ / R / A REVtRSINC CONTACIOR 42 ~ RCYfkSNIC CONTACTOR 42 ~ UNITS 1 AND 2 FAKE 10 CLOSE VNEN AIR OPERATED VALV Ao FOITA rfsr OYPAss vklvc No Folsk SUCTION VALVE NO PODIA FINAL SAFETY ANALYSIS REPORT IC51AOLE CNECK YALYt 4YFASS 'INAOIILUIC Crt CROCKS 2 4 sl NOCE$ 2 ~ sl OttN CLOSE Ao foOCA loCAL ICSTAOLC CNECK VA Vf Ao FOOCA CORE SPRAY SYSTEM VALVE ttkfokks CNECK fVNC'CION RKCARDLESS OF tV5NOVTTON toSICION FCD FIGURE 7-3-9 Sheet 2 i I b 10 4 k 2 POSITION SVITCN 2 tosITION 5VITCN 2 P05IT ION SVITEN NORNIL TEST Otf N 'CLOSE NORNIL 'Icsn XEYLOCXK0, XET RKNOYASLf IN XETLOCXKO, XCY RKNOYASLE IN tNORNIL t051'CION SVITCN NNOP XCVLOCXKO RKNOVISLK'IN XfY NORNAL tOSITION 'OtfN t051TION NAUITIINKOCONTACT 'NORNAL P05ITION A CORK 5PRAY LOSSOP POWCRPR CORK SPRAY svsnN I CORE SPRAY svsnN I CUR\ YPRAY SVSIS CC I 'SUCY NN VIIVC CCPNNDL CORK StRIY NOY TEST tact 'Isvl TEN PINIP 2 2140OA ~ VWP f 'tl COOIC cost spal~v cole stalv SYSTKN I OVT Of UVCRLIIOCP PITY CORA CPRAY IN TEST LOCI C tovca SPITOI H CIISC CCCVINN SVSTCN I OVT Of IN IICTCR SRCANAR NOT IN OPIRAYINP Posm IVI SNCIXCN lcfv H OCKIATINIIUUIXH ~ UNP Ctl COOIC ROTOR PUNP ftl-COOIC ROTOR Sf RYICC SYSTCIC I VALYS STATUS TAILURE Ol VCLVNlS PIILVCuylf0 5C RYICC EST'051'I ION CN'CWIR LOSS OR POWCIL LOSS AVYO Tait AUTO TRIP ANN. CR 5~ NCC UX OCY RNS CR AUX OfvlCC NICS CR RNS Ca ~Y lf NCC AINC OCV ICE ST AE IVX of vlcc ~ AC'IIVATE NOV TNCRNAL $$ NCC TYPICAL foa SYS'nN t 5EC NOTE 10 CONTROL 5V CONTROL SV SEAL IN IN 'OPEN IN CLOSE SEAL IN ~ 05ITION POSITION RNS CR RNS VC tfaN1$ 5IYE VNKN ~ KINI5$ lvf UNLESS tfRNI55IYE VICLK$5 VALVE 1$ VALVE Ctl f005I IS AUX SICNIL OVKRTOROVKO fVI.LT CL05KO IS PRESE NT VNILC CLOSINC LINIT ON AVX TOROUC ON SYITCN VALVE OfvlCC SVITCN VALVE tfRNI$YALYC 5IYC UNLE5$ IS tfRNI5$IVC UNLESS VII.VC IS fVLLYOtfN LI NIT ON CR / fVLLYCLOSEO LI NIT ON CR SVITCN VILVC / IC SVI TCN VALVE /* Rev. 19, 1/81 OPEN SUSQUEHANNA STEAM ELECTRIC STATION RKYERSINC CONTACTOR It ~ UNITS 1 AND 2 CORK SPRIY OVTROIRO YILVC NO fooll NOTES t I~ FINAL SAFETY ANALYSIS REPORT TTtlCAL foa STSTEN t CORE SPRAY SYSTEM PCD FIGURE 7; 3-9 Sheet 3 5 l I 0 TO II ff I'I j 4 4 I 1 fl I, 4 If 1 ll I 1 lf I Il ffk4 I It 4 'f CCC'3$ trtd AE, CJ Cf Elk K)') EFvf v VNITI rrAS PIVDR!TS Cdh PVMPS COO(A ANDI. 5 SYS CCATS SEOJPA!I( SH(MN 5<d CHYSSEDVPAJM I low L(t(LH I PIESSICK, IJVHT E trAS PRCRTY Sok PJVPS CDDCC A!0 0 IDENTKJIL ff(ftT Cokk(SPOIKSHD EDIAPND 5VSSLt(5 hk( I I IHE C<<awk 5151fM AS OAAAN SHOWS SYSTEM L THE OPLI4AYPJO AS CCLDWS Ok A5 NOT( D I 5(DIEM(LAST(k LDV lttl(R L(v(L SKhhi Ort HCH Dkvhftf ACCCWVMNKD SYSI A DY LDW tt(JCIDR tvt55VIIE IS AS FCKIOWS PVVP Cloth SMATS NO OllA> 'lola rt 4 SYSE 40 ttww MOTORS OV(klOAS I!CATS SHNL (( PASTE(I(0 W!TH (H(RLO!o PASECTKA TO If JPPL(0 50 AS To MANTAIN PDA(R Ott tvtvv Ct!0(4 STAITS AO NIAV MOTOR AS(<<VO A5 P(55(LE WITHOVT VMMgtAT( (AMIDE to ILJRDR . I- Rtvk(OOCC STARTS 5 SC D(ihv Sf'OCtv 'HARM 10 Ew(NANCY PDATR SYST(ththvf MOTORS(rrhti 44 E Low uv(ol NKSSVRE PVNPCDOE D SMJtTS 5 .1 ~ IHIOVID(D WIT!I CIKRLOAO Tk!PS hvo LOSS CC PDAER A;AILVSIN I I ~vv AD(HTKN.IPLVE MDIDR CVKVITS ARE TO df IDROVCKO WlTH Dh(AHEP / S<<14 (PENS htl(k klh'.T<<t IDW tv(SS!tf SIKRT ORCVIT Cttk(NT tACTfCTNT TRPS l Itktk33!I( I /AWLkNV /iv!rr(N W!TMTED f<<5A DIKHS r!STER IKRYISSYE AEKI<<t Low SHESDJAE 5 AVYLIARY R(LAYS AND D(VK(5 Art( ICST 5!rOAN ON THf Cvrv(TKNL CONTR<< (VA(RAM (K(tf WH(RE MEDEOTOCNRSVTH( SVACTIDNHE Rf Orhk(MENTS. C0NT (04VVD SOL ~ 5(Al' I FD(tv I MDTIVl PDV(R SDR SIST(M I RPAPS SHALL (PISH!rtt( Ck<<J A k(ACIDR I(SS(L CD(4k CLOSE.IVOPKN.IAOIVAIILYMNNIrLN(0 Diff(RfNT KMlkl(NCYAC IVS THAN IVE PVMPS CW 51ff(M POA(R I lOW L(V(L'I MAHIJl'NfTMTOV CD(t A CDSEDJ Sth OIIKR IALVES IN (KH SYS SHML okrDPMTK ROM 'fHE SLM( SO( IA (555!JPPLYINC P/rt POW(R LOCK CINTIKK POAER 5YSCMI Svhtt ICAI 1 !Kll VALVE Cold A CP(N) (( SIIDN A OFS(R(NT SOVRCC THLV SYSTEM!E ~dd v CR ItfI('I IMTATDII Sfkvrg WT(k PVMPS ~ CLOSE OS CD<<rh(LCI STOP IC RLIVNINCr 2 5ihTVS llOITSSHALLDE AS C41DWS SKNL T I VHLVK5 AMEER ON CDR CIOI(0 POSITI<<4 5TARI t/tt R(0 COA OP(N PCODI)N k(KIIR YfSSEL SINN(DORA JEANS NO C(IAY IDTH <<l Sok INTERNE<<htf POSIDON ILDP L(v(MI PLWP COE I I STJAI5 0 C(LA" 5'thltTS NO ICAv tttrtPS k(0 ON fok tvNP thtvrvNO PLAIPCOC( C AIAIER ON fOR P/AP St(P PVMIMCOC I 4.7 STARTS ND D(itv I ALL AVT TIMPK CVK(5 SNAIL 4( ATAISIASLK CROM o IIK SILL 5CAL( Aht SCALE Srrh(L IE Al LEAST I tv TrNE 5 CRfAT(k THAN Sr(CFKO Tw( Sf TTNSS, 1 HKH 0AYWfli $ (AL IN 4 A I H J H krASSN( WtCN 'l hll EOVIPMtNIQLNSIRJIJKNIS AS( Pk(Crt(0 dv (k VNL(S5 PP(SSVR( ND!I IN 1(ST OIH(RWM NDT(O,SE( R(C I rl 40 IHE 5(NStki ORCAI AR IA(hh 0(TECIKN ANS trt4VK 5fi(CTKN ~ kvh CVTJ04VV IS 10 EC Akkhtr((0 SO TMT CALLO( OC A SPCE D(VKE OR CIA(III SAOM DW 1 ID(K f0 SVIKTON CN f(MANI Whl NDT tkfv(AT CORA((I SEifCT!DN OC lOOP FOR INNCKN tllll ~ PVTMION Nrh SKJVIL C ll THE k(SKIP( trfhf P(MOIAL SYSIEAI SHALL df NSK!1(0 N 5&1 (M(00(NCV Wlftt PROPC(EO (!ITlRA SOIMKL(hk tOWDt FLINT PAOTEC43N 0($ rl F SIST(MS IE(f EN;.AS APPLKN To TIK CD!IT!tDL CIKVITRY Iv DTIERS td CR IE 1td RE(OVAL PEA I k(MOVHL SfSTEIA SHALE I( 0(SICNIO IN WITH k(S ro ~I~LEQEX5% I bl IDO ~ (SDVAL KAT ACOVAL SIS PHD dhtt 4030 L!OC SYIJDCS p(RM!slrvl vw(N Pf RVA55W( WHEN Pf PJNSS!Vf WHEN PlkwSS!vt wH( Sd(IKO Nt(XEAR DIRER SYST(M ttb O(S(L PDW(k Avhk NORMAl SYJ!vP C NDT IN CHA!A(i T LN CHANNEL ~ dfl M30 !Vvct(rh IttL(R svzxM (co IS<<t tvwt C POH(k hhkhtkf TlST T(51 $ (b 1030 Ck( SPL4Y SY5 C(ft $ 431-KTO RECFK Sltw CNINL sv5 CcD (dry LP CR RMS 7(IPI030 CISC SI5 C(0 RHI IMIIMKN CC 4(SPD30 ILCK SVS SCC DIV k IOOC NDSPKIO RDKTDR AECI4C SYS ttrt ~~@ ~" /FASOSSr/F rvDT PtklvtSSIIK IO AII 4030 (I(CIRCA( KOLIP SftfkATKtt fOR SASEDVARD $ Y5 WvKN STOP RAMSSV( ASI(k C(RVISSAI WH(N pc!rhp Sr(NJL IS PA(ma S CA't)ND 0(S(l SIM(k AlrAIL CASPNh'CK 3(br FOR PVMP S<<ttk Jtvhhht( 77rtCJP Df(JCY Ck SEC(Ed) N + 5W'IKHC(AR D(VKE CVNCKN Mhtl(k JJISI 5tfC. CITY I P(RIJIISVE Avt(k 5 SIC<<40 TPJE (CAY CR SCAI kt V( NOt ALLY WLVE NOT Akhv ~ N STOP CONOITKP4 PAL M VHLVJ HCE SILLY ~HOT RLLT VAL~NDI/ILLY CR IM! OP( N ,I lotrTKN PW, CDHOIT!ON SVRIFNJTD STDP SPNIS k(PJ!rN TO St/0 rl4 SADM PLRIRSSIVC vrtKN Hrl Vl lt 'Ar AI I ~ SAlt'OP'NTIKL NDT PERMSSrvf AIJX OCVVX SW P(RMSSYK wr(N 5'Akt FOTNKN wHEN 5t<<'(rrrt (NKRIVKED VLVE NDT Sth(YOPEN 45 sama NST P(IW15!VK pf RM!isrvl wHEN P(AIASSVE lwrlN CR WHf N 510P SKtrhK AVY CVKI VMVI NOT Sthtv W LIOHY ON RMS CR CR NWHC4 SVATIH IS tR(SLNI EIKAD!(ID S PDSttrtN gW 'SMR T-)VIO STOP. / W C<<CDKL ~ LN slop pvtr5 KNIR N 'STOP POSIT!<<h CSI STOP SKALDIC N SKJL(D vt Stop ptvrp c NOT Pf RIAStrvf SPRP!0 k(DAIN TO AVID CIKIA IPPY 1 Fk<<4 Sthkf'TCF WIKN STCP SKNAL N Rtw Phrw IS PR(5(NI Sttp Itprp 15 RtPPPHO N FROM! tphv 4 N I'AWIIDVTKN VAKN RHrt tlhrrt CR 1 RLNHNO kMS Ck 10 ttrwv t STDP IPCT 4 ~ Jv! I CR CV4I PIAIP A Cll Rev. 19, 1/81 / CR START / STARf Ck 5 SUSQUEHANNA STEAM ELECTRIC STATION / R Ark 'I A R A,k CIA(VII Dt(AH(0 Sf F / A UNITS 1 AND 2 krw pvrvp ~ .coo(A (3f{ Not(5 St ~ ) Rrrk Ih!MP II 44 FINAL SAFETY ANALYSIS REPORT RHR SYSTEM FCD FIGURE 7- 3-10 Sheet 1 7 I E 1 0 10 12 CI Rt&CTU4 PICSS. PUUA55llt NbtlA LP PS dtl NOtld PCRIRSSIVK WICN V&LVE IS NOT Al TIALY OCSKD POSITION REACTOR PRE55. RKACIDR PRESS. < LICNT ON PUORSSIV\ Pt$ 04SSIVE W WHEN WHEN IDW WICN IOW X SEALED-N PS dtl PS dtl-NOtlC NOtlO 0 Ptf&RSSIK WICN I P VALVE IS NOT N ITALY QDSED POSITION UNT ON VlLYC 5WITOI NO SOOd PC$ RRSSIVC MCN AUX SNNAL IS PIIESKNT )OPtN'AUTO POSITKN SW CLOS PtRI&55IVK WICN REACTOR VKSStl. 'T L PRES SIXIE ls IDW CONTROL PW CLOSC SW S N QOSt I I 5 N 'ltd CONTIIX. 5W t I P5 dsl NOISA ~ OSITKN ~ OSITKN RNS CR lt AUX OXIT ~ RHS CR M p SCIL N PUORSUYE WICN lUICCNT ~ tRIASSIYE WHEN TMK CQAY VALVE IS SIALY ClDStb 42t VALVE IS ARLY PtfbaSSIVK QDSCD FOR S MNUTES LRRT ON Y&UC UIRT QI IALYC SWITOI VO fOITA SWIIDI &KI $ 0ISA LP NOT PE$ tlOSIYE WICN AUX SIONIL IPCESS 00NTROI. $ 5 PRESENT SwWI IS N RMS CR AUX 42 ~ f I'2 VALVC L&RT VALVE TORQIE VALVE L&KT VALVE TCRCLC SW Ptf&RSSIVE SW PCIORSSIVE SY PERMISSIYC SW PQURSSIYE &IHLK QDSNO MCE QDStli WNIK QDSNO MCE QD504$ LRAT CN L&RT ON TORQC ON SWITCH V&LVC SWITOI VALVE SMT CH 'IALVE RCVtRSNC CONT&ETON 42 ~ RKVKRSNO CONTACTOR 4t 4 ~ RHR OUT VALVT MO f00& RIO Tt Kl -52$ $ SK CONITKE SW S4 St&L N ICAO SPRAT ISQATaN MO $ 022 MO Sots R RIIS CR NIIONT ~S ~ t~ LAAT SWITOI ON VALVE KKT $ 00$ KD N'CPO4'POSIIXN SEN. N i&RESS CONIROL Plfltttl IS N POSIIXXI MME POSIT KN NNC POSITON NJX Q&IT UIAT CN AUX CCNK RMS 4$ 45 fblS IQ, M-Q At& SMTOI VALVE RNS dt A Rev. 19, 1/81 VlLVKIART 5W P\$ &RSSAE WIRE OPKNNO PtRNI55IYC UAESS Q&IUKL SWITOI ls N VALVE LART 5$ $ PUbRSSIVE lACE QDSNS VALVE TO&I&IX SW PCI&RSSNE IACE CLDSNO TOIKXIC SMTCH ON VNVC SW MCE UNIT ~ YlLVC tACT SWITOI OPTIAHS CN VALVE WLVK LWKT SW PC$ bASSWE MCC, QOStQ VALVE TORCIIE SW PERMISSIVE WHLE Q05NO VALVE I&AT SW PKRIASS&C M4IE OPUINO LNRT SWITCH ON VNVE VALVE IART SW PKRMISSVE wHLE QDSNO VALVE TOIK&C SW PUUJIISNVE IACE QDSNO TCAQIC, SWITCH ON VALVE SUSQUEHANNA STEAM ELECTRIC STATION UNITS 1 AND 2 FINAL SAFETY ANALYSIS REPORT RCYCRSNO CONTACTOR 42 AC ~ RKVKRSNO CONTACTOR Ct 4 RHR SYSTEM Ns VALVE %4t PI&It 5UCTION 'IALVt f004A f004 $ 005& IQ4 VALVE I&ANNA Stt Tldl.t FCD FIGURE 7. 3-10 Sheet 2 l I 0 $ 0 4 ll I h l b W 4 h I'aost tosITION 5V otta NAINTAINED CONTACTS )a~~ --oPi.- 5 POSITION SV HAINTAHICD CON(t(1$ VALVE 101st CONTROL SV K(T(OCK IN'OPE N'POSITN)N Clost 'NORHAL'tta CONTROL Sv IN IN Oaf N SPRINC RCTVaN 10 NORHAL. 'OtCN tosl1ION tosl1ION CONTROL SW coa1aol ski '((OSC CON)aa Sv CDNTROL 5V IN OP(N N .a 05(. PX POsl (ION POSITION IN OPKN RNS CR RH5 Ca t05l TION tosl(ION RHS CR RHS AC A.v RHs ca RH5 YALYE fo)54 N01 ttaNI55IYC coanoL sv IN VNtN AUTO SICNAL IasotkO ISOL VALVE OPtN toSI (ION 15 tkfSKNT CL05VRC 5IC fo)5 ONLT YA(vc UNIT VALVE LIKI1 I YALYK Tcacat AUX DtVI(t Ca iktf 4,~ 5WP(XHr5SIVC WHILE Dt(xHNG 5v t(RNISSIYC Vailt ClDSWO 5V t(RHI5$ IYC V'NLt C(.05INC VALVE 'LHII1}}