ML18019A586

Vol 6 of Part 7 of Plant Operating Manual,Consisting of Rev 1 to Inservice Insp Program ISI-203, ASME Section XI Pump & Valve Program Plan.

ML18019A586
Person / Time
Site:	Harris
Issue date:	11/04/1985
From:	CAROLINA POWER & LIGHT CO.
To:
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ML18019A583	List: ML18019A582 ML18019A586
References
ISI-203, NUDOCS 8602200211
Download: ML18019A586 (570)

Text

Osl 860220021 AnOCK f 860l27 00000400 PDR PDR 's CAROL(NA POWER & LIGHT COMPANY SHEARON HARRIS NUCLEAR POWER PLANT P~T OPERATING MANUAL n

rP + VOLUME 6 PART 7 PROCEDURE TYPE: In rvice nspection Program (ISI)

NUMBER: .ISI-203 TITLE: ASME Section XI mp and Val.ve Program Plan REVISION I APPROVED: l ) 85 Signa re Date TITLE: )V) C~IZ - ~pep SuPPO)~~

NOV P7)O8 C CJI I

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Page l of '48

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Osl Table of Contents Section ~Pa e 1 ' PURPOSE 4

2.0 REFERENCES

4 3.0 RESPONSIBILITIES 4 4.0 ABBREVIATIONS 4 5.0 PROCEDURE 5 5.1 Explanation of Codes and Symbols Used in the SHNPP Inservice Test Program 5 5.2 Inservice Pump Test Program 15 5.3 Inservice Valve Test Program 20 6 ' DIAGRAMS/ATTACHMENTS 148 ISI-203 Rev. 0 Page 2 of 148

i OS I.

List of Effective Pages

~Pa e Revision 1

2 3

4 - 90 91 92 93 94 - 95 96 97 - 104 105 106 148 ISI-203 Rev, 1 Page 3 of 148

OS1 1.0 PURPOSE This procedure describes the scope and testing requirements of the ASME Boiler and Pressure Vessel Code,Section XI pump and valve program at SHNPP. Compliance with this code is required by 10CFR50, Domestic Licensing of Production and Utilization Facilities.

2.0 REFERENCES

2.1 ASME Boiler and Pressure Vessel Code,Section XI, 1980 Edition through Winter 1981 addenda'.2 Code of Federal Regulations, Title 10, Part 50.55a(g).

2.3 SHNPP Technical Specifications, Section 4.0.5.

2.4 PLP-604, Inservice Inspection.

3.0 RESPONSIBILITIES 3.1 Technical Su ort Unit The Technical Support Unit is responsible for overall administration of the program including'.

3.1.1 Determination of the program scope.

3. 1.2 Revision of the program as necessary based on plant design changes.

3.1.3 Preparation of reports as necessary.

3.1.4 Requesting relief from required testing for components that cannot be tested during plant operation.

3.1.5 Trending and review of test results.

3.2 0 erations Unit Preparation and performance of surveillance test procedures that implement the program requirements.

3.2.2 Evaluation of test results based on acceptance criteria determined by the Technical Support Unit.

3.3 Administrative Section 3.3.1 Maintaining test records consistent with the requirements of reference 2.1.

4.0 ABBREVIATIONS 4.1 ASME " American Society of Mechanical Engineers.

ISI-203 Rev. 0 Page 4 of 148

OS1 4.2 CFR Code of Federal Regulations.

5.0 PROCEDURE The following is a detailed description of the ASME Section XI pump and valve program as implemented at SHNPP. The format is consistent with NRC recommendations.

5.1 Ex lanation of Codes and S mbols Used In The SHNPP Inservice Test Pro ram This Section identifies the meaning of all codes and symbols used in the pump and valve test programs presented in Sections 5.2 and 5.3. The tables in this section can be removed from the procedure to assist in reviewing and understanding the information provided in the program.

ISI-203 Rev. 0 Page 5 of 148

OS1 TABLE 5.1.1 SYSTEMS TESTED S stem Flow Dia ram Main Steam Supply 2165-S-542 Feedwater 2165"S-544 Auxiliary Feedwater 2165-S-544 Condensate 2165-S-545 Service Water 2165-S-547 Containment Spray 2165-S-550 Steam Generator Blowdown 2165-S"551 Process Sampling 2165-S-552 Diesel Fuel Oil Transfer and Storage

~

2165-S-563 Containment Atmosphere Radiation Monitoring

~

2165-S-605 Diesel Generator -.

2165-S-633, 633S01 Miscellaneous Drains 2165"S"685 Demineralized Water 2165-S-799 Service Air 2165-S-800 Instrument Air 2165-S-801 Fuel Pool Cooling 2165-S"805 Emergency Screen Wash 2165-S-808 Fire Protection 2165-S-888 ESW Bearing Lubrication 2165-S"936 Essential Services Chilled Water 2165-S-998, 998S02, 998S03, 998S04,999, 999S02,999S03, 999S04 ISI-203 Rev. 0 Page 6 of 148

OS1 TABLE 5.1.1 SYSTEMS TESTED (CONT'D)

S stem Flow Dia ram Reactor Coolant 2165-S-1301 Chemical & Volume Control 2165-S-1303, 1303S01, 1303S02 1304, 1305, 1306,1307 Safety Injection 2165-S-1308, 1309, 1310 Containment - Waste Processing 2165-S-1313 Component Cooling Water 2165-S-1319, 1320, 1321, 1322, 1322S01 Residual Heat Removal 2165-5-1324 Containment HVAC 2168-G-517 Auxiliary Building HVAC 2168-G-517 S03 Control Room HVAC 2168"G-517 S04 Switchgear and Protection Room HVAC 2168-G-517 S05 Fuel Handling Building HVAC 2168-G-533 ISI-203 Rev. 0 Page 7 of 148

OS1 TABLE 5.1.2 SYMBOLS USED TO DESIGNATE VALVE TYPE

~Smbo 1 Valve T e BA Ball BF Butterfly CK Check-DA Diaphragm GA Gate GL Globe ND Needle PG Plug RG Regulating RL Relief SK Spring Check Three Way ISI-203 Rev. 0 Page 8 of 148

OS1 TABLE 5.1.3 SYMBOLS USED TO DESIGNATE VALVE ACTUATOR TYPE

~Smbol Actuator T es AO Air Operator Manual Operator MO Motor Operator Self Actuated SO Solenoid Operator EH Electro-Hydraulic Operator PO Piston Operator EH/N Electro - Hydraulic and Nitrogen Operator ISI-203 Rev. 0 Page 9 of 148

OS1 TABLE 5.1.4 SYMBOLS USED TO DESIGNATE NORMAL VALVE POSITION

~Smbol Valve Position Open Closed LO Locked Open LC Locked Closed TH Throttled LT Locked Throttled Valve position determined by other system parameters as in the case of any check valve or regulating valve.

ISI-203 Rev. 0 Page 10 o f 148

OS1 TABLE 5.1.5 CODES USED IN THE TEST FRE UENCY COLUMN The codes used in this column indicate the plant operational status that must be achieved before a particular valve can be safely tested. For simplicity, the following codes are used:

Test Fre uenc Plant 0 erational Status Normal Operation. Valves in this category will be ~uarterl tested dosing normal operation without any adverse effects on operations or safety.

Cold Shutdown. Testing of valves in this category cannot be performed quarterly during normal operation and must be deferred until cold shutdown in order to avoid possible adverse operational or safety situations.

Refueling. Testing valves in this category cannot be performed quarterly during normal operation nor performed during cold shutdown and must be deferred until the plant is in a

~refuelin mode in order to avoid possible adverse operational or safety situations.

ISI-203 Rev. 0 Page 11 of 148

OS1 TABLE 5.105 CODES USED IN THE TEST FRE UENCY COLUMN (CONT'D)

Valves in this category are relief valves which will be tested in accordance with IWV-3510. At each refueling, a portion of the total number of relief valves will be tested as prescribed by IWV-3510.

At least once every two years.

ISI-203 Rev. 0 Page 12 of 148

OS1 TABLE 5.1.6 CODES FOR VALVE TESTING FS Full stroke valve for operability in accordance with Section XI, Article IWV-3411.

FL Exercise valve with fail-safe actuators to observe proper operation of failure. mechanisms in accordance with Section XI, Article IWV-3415.

TS During the full stroke test, measure the full stroke time of a power"operated valve. The valve stroke time will conform to the requirements specified in Technical Specifications.

TM During the full stroke test, measure the full stroke time of a power-operated valve. The valve stroke time will be established after initial baseline testing and will be analyzed in accordance with Section XI, Article IWV-3410.

RL Test safety and relief valve set points in accordance with Section XI, Article IWV-3510.

PI Remote valve position indicators shall be observed to verify that valve operation is accurately indicated.

ISI-203 Rev. 0 Page 13 of 148

OS1 TABLE 5.1.6 CODES FOR VALVE TESTING (CONT'D)

LK Perform valve leak rate test in accordance with Section XI, Article IWV-3420.

FF Verification that a check valve will pass flow in the forward direction.

BS Verification that a check valve will properly back seat to block flow in the- reverse direction.

ISI-203 Rev. 0 Page 14 of 148

OS1 5.2 Inservice Pum Test Pro ram Summar of Information Provided Each pump test table provides the following information:

The system designation for the pump Individual pump by number The simplified Flow Diagram on which the pump is located and its coordinate Speed Inlet Pressure Differential Pressure Flow Rate Vibration Amplitude These parameters are each addressed with an entry consisting simply of a uYes" or a "No," indicating whether or not that parameter will be monitored quarterly during the 120-month duration of the program.

ISI-203 Rev. 0 Page 15 of 148

PUMP TEST PROGRAM TEST PARAMETER MEASURED SYSEM PUMP DRAWING INLET DIFFERENT I AL FLOW VIBRATION PUMP NO, NO, COORDINATES SPEED PRESSURE PRESSURE RATE AMPL I TUDE REMARKS 2165- N DP 0 V Auxiliary Feedwater IA-SA S-545 J-7 N/A YES YES YES YES I B-SB J-8 N/A YES YES YES YES IX-SAB J-9 YES YES YES YES YES Emergency Service Water IA-SA S-547 C-2 N/A N/A N/A YES YES See Note 1 IB-SB C-3 N/A N/A N/A YES YES See Note I SW Booster IA-SA S-547 H-5 N/A YES YES YES YES IB-SB II-I5 N/A YES YES YES YES Containment Spray IA-SA S-550 F-8 N/A YES YES YES YES IB-SB L-8 N/A YES YES YES YES D/G fuel Oil Transfer IA-SA S-563 F-2 N/A YES YES N/A YES See Note 2 IB-SB F-7 N/A YES YES N/A YES See Note 2 Emergency S.W. Intake IA-SA S-808 C-15 N/A YES YES YES YES Screen Wash IB-SB C-12 N/A YES YES YES YES Chilled Water IA-SA S-998S02 J-6 N/A YES YES YES YES Circulation (P4) IB-SB S-999S02 J-6 N/A YES YES YES YES Chiller Condenser IA-SA S-998S02 D-9 N/A YES YES YES YES Recirculation (P7) IB-SB S"999S02 D-9 N/A YES YES YES YES Charg i ng (Sa f ety Inject i on ) I A-SA S-1305 M-9 N/A YES YES YES YES IB-SB K-9 N/A YES YES YES YES IC-SAB J-9 N/A YES .YES YES YES See Note 3 ISI-203 Rev, 0 Page 16 of 148

PUMP TEST PROGRAM TEST PARAMETER MEASURED SYSEM PUMP DRAWING INLET DIFFERENTIAL FLOW V I BRAT ION PUMP NO, NO COORDINATES SPEED PRESSURE PRESSURE RATE AMPLITUDE REMARKS 2165- N DP Q V Boric Acid Transfer I A-SA S-1307 E-8 N/A YES YES YES YES IB-SB S-1307 G-8 N/A YES YES YES YES Component Cooling Water I A-SA S-1319 F-7 N/A YES YES YES YES I B-SB L-7 N/A YES YES YES YES I C-SAB 1-7 N/A YES YES YES YES See Note 3 Residual Meat Removal IA-SA S-1324 N/A YES YES YES YES IB-SB N/A YES YES YES YES Fuel Pool Cooling I 14A-SA S-805 G-10 N/A YES YES YES YES 144B-SB J-IO N/A YES YES YES YES ISI-203 Rev ~ 0 Page 17 of l18

" PUMP TEST PROGRAM NOTE NO, PUMP NOTE Emergency Service In lieu of inlet pressure, the water level will be measured, Discharge pressure will be recorded Water IA II, IB in lieu of DP.

D/G Fuel Oil The D/G Fuel Oil Transfer Pump flow will be demonstrated by the pump's ability to refill the Fuel Oil Day Tank on demands This will be observed as part of normal testing.

Charging IC-SAB Any one of the three component cooling or three charging pumps is an installed spare. One pump is Component normally running, the second pump is aligned as an automatic backup to the operating pump, and the Cooling IC-SAB third pump is electrically disconnected. In the event of failure of the operating pump, the second pump automatically starts and the installed spare is electrically connected and valved in as the reserve pump. The normally operating and reserve pump will be tested. The installed spare is required to be tested before it is declared operational'SI-203 Rev, 0 Page 18 of 140

OS1 Relief Request:

R-1 Pumps: All Class'2, 3 Test Requirement: Bearing Temperature Measurement per Subsection IWP Basis For Relief: Section XI of the ASME Boiler and Pressure Vessel Code presently requires that bearing temperature be recorded annually 'as part of the operational readiness assessment data.

However, bearing temperature rise prior to a failure occurs only minutes before the failure. Therefore, any bearing failure predicted by recording yearly temperatures would be the result of a random event. the data retrieved from ~earl tests eoold oot warrant any increase in confidence of component reliability and should not be required, since in many cases, this requirement will cause the plant to install additional instrumentation.

CPSL considers the yearly temperature requirement unreasonable because it does not increase the confidence in the reliability of the component.

Alternative Test: Vibration is a singularly reliable indication of pump mechanical condition. Vibration measurements will be taken quarterly in accordance with Subsection IWP.

ISI-203-Rev. 0 Page 19 of 148

OS1 5.3 Inservice Valve Test Pro ram ISI-203-Rev. 0 Page 20 of 148

SHNPP VALVE TEST PROGRAM SYSTEM: Main Steam (MS) D~g No (Rev.) 2165-S-0542(1) Page I of 4 VALVE SECTION X I DRAWING VALVE SIZE VALVE ACTUATOR NORMAL TEST REQUIRED RELIEF NOTE NO, CLASS COORDINATES CATEGORY PASSIVE (inches) TYPE TYPE POSITION FREQUENCY TEST REQUEST NO.

IMS- A B C 43 C"3 RL RL 44 G-3 RL RL 45 J-3 RL RL 46 C-4 RL RL 47 G-4 RL RL 48 J-4 RL RL C-5 RL RL 50 G-5 RL RL 51 J-5 RL RL 52 C-6 RL RL 53 G-6 RL RL 54 J-6 RL 55 C-7 RL RL 56 G-7 RL RL 57 J-7 RL RL 25 D-2 GA AO FS FL TS Pl ISI-203 Rev. 0 Page 21 of 148

SHNPP VALVE TEST PROGRAM SYSTEM: Main Steam (MS) Dwg, No. (Rev.) 2165-S-0542(1) Page 2 of 4 VALVE SECTION XI DRAWING VALVE S I ZE VALVE ACTUATOR NORMAL TEST REQUIRED REL IEF NOTE NO CLASS COORDINATES CATEGORY PASSIVE (inches) TYPE TYPE POSITION FREQUENCY TEST REQUEST NO.

IMS- A B C 27 G-2 GA AO FS FL TS Pl 29 K-2 GA AO FS FL TS PI 80 D-8 34 GL PO FS FL R-2 TS Pl 82 G-8 34 GL PO FS FL R-2 TS Pl 84 K"8 34 GL FS FL R-2 TS PI 81 D-8 GA AO FS FL TS Pl 83 G-8 GA AO FS FL TS Pl 85 K-8 GA AO FS FL TS Pl 231 E-8 GL AO FS FL TS PI ISI-203 Rev. 0 Page 22 ot 148

SHNPP VALVE TEST PROGRAM SYSTEH: Main Steam (HS) Dwg. No. (Rev.) 2165-S-0542(l ) Page 3 of 4 VALVE SECTION XI DRAWING VALVE S I ZE VALVE ACTUATOR NORMAL TEST REQUIRED RELIEF NOTE NO, CLASS COORDINATES CATEGORY PASS I VE ( I nches ) TYPE TYPE POS I T ION FREQUENCY TEST REQUEST NO.

IMS- A B C 266 H-8 GL AO FS FL TS Pl 301 L-8 GL AO FS FL TS PI 70 H-7 GA FS TM PI 72 K-7 GA FS TH Pl 73 K-7 FF BS R-30 7I H-7 FF BS R-30 354 N-5 GL AO FS FL TH PI 336 GL AO FS FL TH Pl ISI-203 Rev. 0 Page 23 of I48

SHNPP VALVE TEST PROGRAH SYSTEH: Hain Steam (HS) Dwg No (Rev, ) 2)65-S-0542 (I ) Page 4 of 4 VALVE SECTION XI DRAWING VALVE S I ZE VALVE ACTUATOR NORMAL TEST REQUIRED RELIEF NOTE NO 'LASS COORDINATES CATEGORY PASSIVE (inches) TYPE TYPE POSITION FREQUENCY TEST REQUEST NO.

IHS- A 8 C 58 G-8 GA EH/N C FS R-25 FL TH Pl 60 F-8 GA EH/N C FS R-25 FL TH PI 62 J-8 GA EH/N C FS R-25 FL TM Pl ISI-205 Rev. 0 Page 24,of I48

SHNPP VALVE TEST PROGRAM SYSTEM: Feedwater (FW) Dwg. No (Rev. ) 2165-S-0544 (I ) Page I of 3 VALVE SECTION XI DRAWING VALVE SIZE VALVE ACTUATOR NORMAL TEST REQUIRED RELIEF NOTE NO. CLASS COORDINATES CATEGORY PASSIVE (inches) TYPE TYPE POSITION FREQUENCY TEST REQUEST NO.

IF W- A B C 159 B-7 16 EH/N 0 FS FL R-3 TS PI 277 E-4 16 GA EH/N 0 FS FL R-3 TS Pl 217 D-4 16 GA EH/N 0 2 FS 2 FL R-3 2 TS 5 Pl 307 C-6 GA AO C FS R-11 FL TS Pl 319 F-3 GA AO FS R-ll FL TS PI 313 0-4 GA AO FS R-11 FL TS Pl 165 B-5 GA AO FS FL TS Pl ISI-203 Rev, 0 Page 25 of I.III

SHNPP VALVE TEST PROGRAM SYSTEM: Feedwater (FW) Dwg. No. (Rev.) 2165-S-0544(1) Page 2 of 3 VALVE SECTION XI DRAWING VALVE S I ZE VALVE ACTUATOR NORMAL TEST REQUIRED REL IEF NOTE NO, CLASS COORDINATES CATEGORY PASSIVE (inches) TYPE TYPE POSITION FREQUENCY TEST REQUEST NO.

IF W- A 8 C 163 8-6 GA AO FS FL TS Pl 279 E-3 GA AO FS FL TS Pl 281 E-3 GA AO FS FL TS Pl 223 C-3 GA AO FS FL TS PI 221 C-4 GA AO FS FL TS Pl 133 8-10 16 GA AO FS R-28 FL TM PI 191 C-IO 16 GA AO FS R-28 FL TM Pl ISI-203 Rev. 0 Page 26 ot 146

SHNPP VALVE TEST PROGRAM SYSTEM: Feedwater (FW) Dug. No. (Rev.) 2165-S-0544(l) Page 3 of 3 VALVE SECTION XI DRAWING VALVE SIZE VALVE ACTUATOR NORMAL TEST REQUIRED RELIEF NOTE NO. CLASS COORDINATES CATEGORY PASSIVE (inches) TYPE TYPE POSITION FREQUENCY TEST REQUEST NO.

IFW- A B C 249 E-10 16 GA AO FS R-28 FL TM Pl 140 B-IO GA AO FS R"28 FL TM Pl 198 D-10 GA AO FS R-28 FL TM PI 256 E-10 GA AO FS R-28 FL TM PI 158 B-7 16 BS R-31 216 16 CK BS R-31 276 E-4 16 CK BS R-31 ISI-203 Rev. 0 Page 27 of 148

- SHNPP VALVE TEST PROGRAM SYSTEM: Auxiliary Feedwater (AF ) Dwg, No, (Rev.) 2165-S-0544(l) Page I of 5 VALVE SECTION XI DRAWING VALVE SIZE VALVE ACTUATOR NORMAL TEST REQUIRED RELIEF NOTE NO, CLASS COORDINATES CATEGORY PASSIVE (Inches) TYPE TYPE POSITION FREQUENCY TEST REQUEST NO, I AF- A B C 4 3 N-7 FF 23 3 FF 110 FF 16 L-6 FF BS 31 L-8 FF BS 117 L-10 FF BS 49 J-6 GL EH FS FL TM Pl 50 J-7 GL EH FS FL TM PI 51 J-8 GL EH FS FL TM PI 129 J-9 GL EH FS FL TM Pl ISI-203 Rev, 0 Page 28 of 148

Sl SHNPP VALVE TEST PROGRAM SYSTEM: Auxiliary Feedwater (AF ) Dug. No. (Rev,) 2165-S-0544(1) Page 2 of 5 V~L~~ SECTION XI DRAWING VALVE SIZE VALVE ACTUATOR NORMAL TEST REQUIRED RELIEF NOTE CLASS COORDINATES CATEGORY PASSIVE (inches) TYPE TYPE POSITION FREQUENCY TEST REQUEST NO ~

IAF- A B C 131 GL EH FS FL TM PI 130 J-10 GL EH FS FL TM PI 54 F-6 FF BS H-7 FF BS 92 1-8 FF BS 136 F-6 FF BS 148 H-7 FF BS 142 H-8 FF BS 55 F-6 GA FS TM Pl 74 G-7 GA FS TM Pl ISI-203 Rev, 0 Page 29 of 148

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SHNPP VALVE TEST PROGRAM SYSTEM: Auxiliary Feedwater (AF ) Dwg. No. (Rev.) 2165-S-0544(l) Page 3 of 5 VALVE SECTION XI DRAWING VALVE SIZE VALVE ACTUATOR NORMAL TEST REQUIRED RELIEF NOTE NO, CLASS COORDINATES CATEGORY PASSIVE (inches) TYPE TYPE POSITION FREQUENCY TEST REQUEST NO, IAF- A B C H-8 GA MO 0 FS TH Pl 137 F-6 GA I FS I TH 5 Pl 149 G-7 GA FS TM Pl 143 H-8 GA FS TM PI 64 C-6 GA FS R-24 FL TS Pl 102 F-4 GA PO FS R-24 FL TS Pl 81 GA FS R-24 FL TS Pl 155 B-3 GA AO FS FL TS Pl ISI-203 Rev, 0 Page 30 of 148

SHNPP VALVE TEST PROGRAM SYSTEM: Auxiliary Feedwater (AF ) Dwg. No. (Rev.) 2165-S-0544(l) Page 4 of 5 VALVE SECTION XI DRAWING VALVE SIZE VALVE ACTUATOR NORMAL TEST REQUIRED RELIEF NOTE NO. CLASS COORDINATES CATEGORY PASSIVE (inches ) TYPE TYPE POSITION FREQUENCY TEST REQUEST NO.

IAF- A 8 C 153 8-4 GA AO FS FL TS Pl 159 G-3 GA AO FS FL TS PI 157 G-3 GA AO FS FL TS Pl 163 K-3 GA AO FS FL TS Pl 161 K-3 GA AO FS FL TS PI 68 C-2 FF 106 G-2 87 K-2 FF 19 K-6 GL EH FS FL TM PI IS)-203 Rev, 0 Page 31 of I4II

SHNPP VALVE TEST PROGRAH SYSTEH: Aux I I I ary Feedwater (AF ) D~g No, (Rev,) 2165-S-0544(1) Page 5 of 5 VALVE SECTION XI DRAWING VALVE S I ZE VALVE ACTUATOR NORMAL TEST REQUIRED RELIEF NOTE NO, CLASS COORD I NATES CATEGORY PASSIVE (inches) TYPE TYPE POSITION FREQUENCY TEST REQUEST NO, I AF- A B C 34 K-8 GL EH FS FL TH PI N-6 GL I FS I TM 5 PI 24 N-9 GL FS TH Pl 65 C-6 BS R-31 84 E-5 BS R-31 103 G-4 BS R-31 ISI-203 Rev. 0 Page 32 of I III

- SHNPP VALVE TEST PROGRAM SYSTEM: .Condensate (CE) Dog. No. (Rev.) 2165-S-0545 (I ) Page I of I VALVE SECTION XI DRAW I NG VALVE SIZE VALVE ACTUATOR NORMAL TEST REQUIRED RELIEF NOTE NO% -CLASS COORDINATES CATEGORY PASSIVE (Inches) TYPE TYPE POSITION FREQUENCY TEST REQUEST NO.

I CE- A B C 36 1-7 FF 46 1-8 FF 56 1-9 FF 1157 H-7 RL RL 1158 H-8 RL RL 1159 H-9 RL RL iSI=?03 Rvv, 0 P~ge 33 oi 1 18

SHNPP VALVE TEST PROGRAM SYSTEM: Service Water (SW) Dwg. No, (Rev.) 2165-S-0547(2) Page I of 7 VALVE SECT ION X I DRAW I NG VALVE S I ZE VALVE ACTUATOR NORHAL TEST REQUIRED RELIEF NOTE NO. CLASS COORDINATES 'ATEGORY PASSIVE (inches) TYPE TYPE POSITION FREQUENCY TEST REQUEST NO.

ISW- A B C B-6 30 BF FS TH Pl 8-4 30 BF FS TH Pl C-l 96 BF FS TM Pl C-3 96 BF FS TM PI D-2 30 FF 10 D-3 30 . FF 20 E-I BA FS FL TH Pl 23 E-3 BA FS FL TH Pl 39 30 BF FS TM Pl IS I-203 Rev, 0 Page 34 ot I lu

i SHNPP VALVE TEST PROGRAM SYSTEM: Service Water (SW) Dug. No. (Rev.) 2165-S-0547(2) Page 2 of 7 VALVE SECTION XI DRAWING VALVE S I ZE VALVE ACTUATOR NORMAL TEST REQUIRED REL I EF NOTE NO, CLASS COORDINATES CATEGORY PASSIVE (inches) TYPE TYPE POSITION FREQUENCY TEST REQUEST NO.

ISW- A 8 C 40 I-2 30 BF FS TM .

Pl 45 H-2 GL FS FL TM PI 47 1-3 GL PO FS FL TM PI 86 F-6 14 FF BS 220 F-14 14 FF BS 91 D-6 FS TM Pl 92 D-7 I FS I TM 5 Pl 227 D-13 BF FS TM PI 225 D-14 BF MO FS TM PI ISI-203 Rev, 0 Page 35 of I III

SHNPP VALVE TEST PROGRAM SYSTEM: Service Water (SW) Dwg. No. (Rev.) 2165-S-0547(2) Page 3 ot 7 VALVE SECTION XI DRAWING VALVE S I ZE VALVE ACTUATOR NORMAL TEST REQUIRED RELIEF NOTE NO, CLASS COORDINATES CATEGORY PASS I VE (inches) TYPE TYPE POSITION FREQUENCY TEST REQUEST NO.

I SW- A B C 97 0-8 BF FS TM Pl 98 D-9 BF FS TM Pl

'4 109 D-12 BF FS TM Pl I IO D-13 BF FS TM Pl 116 H-7 14 AO FS FL TM Pl 118 G-13 BF AO FS FL TM Pl 141 H-8 FF BS 143 H-8 FF BS 152 H-9 FF BS 154 H-10 FF BS

SHNPP VALVE TEST PROGRAM SYSTEM: Service Water (SW) Dwg. No. (Rev.) 2165-S-0547(2) Page 4 of 7 VALVE SECTION XI DRAWING VALVE SIZE VALVE ACTUATOR NORMAL TEST REQUIRED RELIEF NOTE NO. CLASS COORDINATES CATEGORY PASSIVE (inches) TYPE TYPE POSITION FREPUENCY TEST REPUEST NO.

I SW- A B C 165 H-ll FF BS 165 H-12 FF BS 179 1-14 GA FS FL TM Pl 180 1-15 GA FS FL TH Pl 206 K-16 GA FS FL TH Pl 204 K-16 GA FS FL TH Pl 124 1-8 BF FS TH Pl 126 1-8 BF FS TH Pl 127 1-9 HO FS TH Pl

- SHNPP VALVE TEST PROGRAM SYSTEM: Service Water (SW) D~g. No. (Rev,) 2165-S-0547(2) Page 5 of 7 VALVE SECTION XI DRAWING VALVE S I ZE VALVE ACTUATOR NORHAL TEST REPUIRED RELIEF NOTE NO. CLASS COORDINATES CATEGORY PASSIVE (inches) TYPE TYPE POSITION FREPUENCY TEST REPUEST NO, ISW- A B C 129 1-9 I FS I TH 5 Pl 121 J-8 BF FS TH Pl 123 J-8 BF FS TM Pl 130 J-9 BF FS TH PI 132 J-9 BF FS TH Pl 275 L-16 30 BF FS TM Pl 274 L-16 30 FS TH Pl 270 K-17 30 BF FS TH Pl 271 J-17 30 BF FS TM PI ISI-203 Rev, 0 Page 38 of 118

- SHNPP VALVE TEST PROGRAM SYSTEM: Service Water (SW) Dug, No. (Rev.) 2165-S-0547(2) Page 6 of 7 VALVE SECT ION X I DRAW I NG VALVE SIZE VALVE ACTUATOR NORMAL TEST REQUIRED RELIEF NOTE NO. CLASS COORDINATES CATEGORY PASSIVE (inches) TYPE TYPE POSITION FREQUENCY TEST REQUEST NO.

ISW- A B C 233 C-15 12 BS R-26 231 D-15 12 BF AO FS R-26 FL TS Pl 240 D-17 12 AO FS R-26 FL TS Pl 242 E-17 12 BF AO FS R-26 FL TS Pl 95 C-8 RL RL 96 C-9 RL RL 107 C" 12 I RL RL 108 C-13 I RL RL 150 F-8 3/4 RL RL 160 F-9 3/4 RL RL 171 F-10 3/4 RL RL 60 1-6 3/4 RL RL 257 1-13 3/4 RL RL ISI-203 Rev, 0 Page 39 of 148

SHNPP VALVE TEST PROGRAM SYSTEM: Service Water (SW) Dug, No (Rev.) 2165-S-0547(2) Page 7 of 7 VALVE SECTION XI DRAWING VALVE SiZE VALVE ACTUATOR NORMAL TEST REQUIRED RELiEF NOTE NO, CLASS COORDINATES CATEGORY PASSIVE (inches) TYPE TYPE POSITION FREPUENCY TEST REPUEST NO, I SW- A B C 276 M-15 36 BF FS TM Pl 50 36 BS R-21 ISI-203 Rev. 0 Page 40 of 14(I

- SHNPP VALVE TEST PROGRAM SYSTEM: Containment Spray (CT) Dwg, No. (Rev.) 2165-S-0550(l ) Page I of 2 VALVE SECTION XI DRAWING VALVE S I ZE VALVE ACTUATOR NORMAL TEST REQUIRED RELIEF NOTE NO. CLASS COORDINATES CATEGORY PASSIVE (Inches) TYPE TYPE POSITION FREQUENCY TEST REPUEST NO.

ICT- A 8 C 26 F-15 12 GA FS TH PI 71 K-I6 12 GA FS TM PI 27 F-14 12 FF 72 L-15 12 FF 105 12 GA FS TH Pl 102 12 GA FS TM PI 62 H-7 FF 65 J-7 FF 47 E-4 GA MO FS TM Pl 95 L-4 GA FS TH Pl 50 F-4 GA FS TS Pl fbi-?05 Rev. 0 Page 41 of 14@

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Sl e SHNPP VALVE TEST PROGRAM SYSTEM: Containment Spray (CT) Dwg. No. (Rev.) 2165-S-0550(l ) Page 2 of 2 VALVE SECTION XI DRAWING VALVE SIZE VALVE ACTUATOR NORMAL TEST REQUIRED RELIEF NOTE NO. CLASS COORDINATES CATEGORY PASSIVE (Inches) TYPE TYPE POSITION FREQUENCY TEST REQUEST NO.

ICT- A B C 88 K-4 GA FS TS Pl 53 F-3 FF R-I BS 91 FF R-I BS 24 H-14 GL FS TH Pl 12 GL FS TM Pl GL FS TH PI B-9 RL RL 25 H-14 GL FS TH Pl 40 G-12 3/4 RL RL 70 K-12 3/4 RL RL

>Sl-203 Rev, 0 Page 42 of 1 18

- SHNPP VALVE TEST PROGRAM SYSTEH: S.G. Blowdown (BD) Dwg. No. (Rev.) 2165-S-0551(l) Page I of 2 VALVE SECTION XI DRAWING VALVE S I ZE VALVE ACTUATOR NORMAL TEST REQUIRED RELIEF NOTE NO CLASS COORDINATES CATEGORY PASS I VE ( inches ) TYPE TYPE POSITION FREQUENCY TEST REQUEST NO, IBD- A B C D-7 GL FS FL TS Pl 30 I-6 GL FS FL TS Pl 49 N-7 GL FS FL TS PI D-3 GL AO FS FL TH Pl C-3 GA PO FS FL TH Pl 20 l-3 GL AO FS FL TH PI 26 M-3 GA FS FL TM PI

.SI-203 Rev. 0 Page 43 of I48

SHNPP VALVE TEST PROGRAM SYSTEM: ST G, Blowdown (BD) Dwg. No. (Rev.) 2I65-S-0551(I) Page 2 of 2 VALVE SECTION XI DRAW I NG VALVE SIZE VALVE ACTUATOR NORMAL TEST REQUIRED RELIEF NOTE NO CLASS COORDINATES CATEGORY PASSIVE (Inches) TYPE TYPE POSITION FREQUENCY TEST REQUEST NO ~

IBD- A 8 C 39 N-3 GL AO FS FL TM PI 45 M-3 GA PO FS FL TM PI

~

SI-203 Rev. 0 Page 44 of l48

Sl SHNPP VALUE TEST PROGRAM SYSTEM: Sampling (SP) D~g. No, (Rev.) 2165-S-0551(l ) Page I of 2 VALVE SECTION XI DRAWING VALVE SIZE VALVE ACTUATOR NORMAL TEST REQUIRED RELIEF NOTE NO. CLASS COORDINATES CATEGORY PASSIVE (inches) TYPE TYPE POSITION FREQUENCY TEST REQUEST NO ~

ISP A 8 C 224 L-4 3/4 GL SO FS Fl.

TH PI 226 M-4 3/4 GL SO FS FL TH Pl 219 H-4 3/4 GL SO FS FL TH PI 221 1-4 3/4 GL SO FS FL TM PI 214 C-4 3/4 GL SO FS FL TH PI 217 C-6 3/8 GL SO FS FL TS Pl 222 H-6 3/8 GL SO FS FL TS Pl ISI-203 Rev. 0 Page 45 of 14u

SHNPP VALVE TEST PROGRAM SYSTEM: Sampling (SP) Dwg. No. (Rev.) 2165-S-0551(1) Page 2 of 2 VALVE SECTION XI DRAWING VALVE S I ZE VALVE ACTUATOR NORMAL TEST REQUIRED REL IEF NOTE NO ~ CLASS COORDINATES CATEGORY PASSIVE (inches) TYPE TYPE POSITION FREQUENCY TEST REQUEST NO ~

'I SP- A B C 227 M-6 3/8 GL SO FS FL TS Pl 216 0-4 3/4 GL SO FS FL TM Pl iSI-203 Rev. 0 Page 46 ot 148

SHNPP VALVE TEST PROGRAM 'YSTEM:

Sampling (SP) Dwg. No. (Rev.) 2165-S-0552(l) Page I of VALVE SECTION XI DRAIIING VALVE S I ZE VALVE ACTUATOR NORMAL TEST REQUIRED RE L I EF NOTE NO CLASS COORDINATES CATEGORY PASSIVE (inches) TYPE TYPE POSITION FREQUENCY TEST REQUEST NO,

)SP- A B C 60 D-4 3/8 GL SO FS FL TS Pl 41 C-4 3/8 GL SO FS FL TS PI 949 8-4 3/8 GL SO FS FL TS Pl 59 D-4 3/8 GL SO FS FL TS Pl 40 C-4 3/8 GL SO FS FL TS Pl

'Sf-203 Rev. 0 Page 47 of I It)

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SHNPP VALVE TEST PROGRAM SYSTEM: Sampling (SP) D~g. No. (Rev.) 2165-S-0552(l ) Page 2 of 3 VALVE SECTION XI DRAWING VALVE S I ZE VALVE ACTUATOR NORMAL TEST REQUIRED RE L I EF NOTE NO, CLASS COORDINATES CATEGORY PASSIVE (Inches) TYPE TYPE POSITION FREQUENCY TEST REQUEST NO.

ISP- A 8 C 948 B-4 3/8 GL SO FS FL TS Pl 85 F-4 3/8 GL SO FS FL TS Pl 78 E-2 3/8 GL SO FS FL TS Pl 81 F-2 3/8 GL SO I FS I FL I TS 5 Pl 84 F-2 3/8 GL SO FS FL TS Pl 200 M-6 GL SO FS FL TS PI 201 M-4 GL SO FS FL TS Pl fSI-203 Rev, 0 Page 48 of 148

SHNPP VALVE TEST PROGRAM SYSTEM: SAMPLING (SP) DMg. No, (Rev,) 2165-S-0552(l) Page 3 of 3 VALVE SECTION XI DRAWING VALVE S I ZE VALVE ACTUATOR NORMAL TEST REQUIRED REL IEF NOTE NO, CLASS COORDINATES CATEGORY PASSIVE (Inches) TYPE TYPE POSITION FREPUENCY TEST REPUEST NO.

ISP- A B C 208 N-6 3/4 GL SO FS FL TS Pl 209 3/4 GL SO FS FL TS Pl ISI-203 Rev. 0 Page 49 ot l4II

SHNPP VALVE TEST PROGRAM SYSTEM: Diesel Fuel Oil (FO) Dug. No. (Rev.) 2165-S-0563(1) Page I of I VALVE SECTION XI DRAWING VALVE SIZE VALVE ACTUATOR NORMAL TEST REQUIRED RELIEF NOTE NO. CLASS COORDINATES CATEGORY PASSIVE (inches) TYPE TYPE POSITION FREQUENCY TEST REQUEST NO.

IDFO- A B C 168 G-2 FF 186 G-6 FF 170 G-I 3/4 RL RL 188 G-5 3/4 RL RL ISI-203 Rev. 0 Page 50 ot 148

- SHNPP VALVE TEST PROGRAM SYSTEM: Radiation Monitoring (SP) Dog No, (Rev.) 2165-S-0605(0) Page I of 2 VALVE SECTION XI DRAWING VALVE SIZE VALVE ACTUATOR NORMAL TEST REQUIRED RELIEF NOTE NO. CLASS COORDINATES CATEGORY PASSIVE (inches) TYPE TYPE POSITION FREQUENCY TEST REQUEST NO, ISP- A B C 12 C-12 GL SO FS FL TS Pl 30 D-12 GL SO FS FL TS Pl 916 C-13 GL SO FS FL.

TS PI 918 D-13 GL SO FS FL TS Pl 42 G-11 GL SO FS FL TS PI 62 GL SO FS FL TS Pl 919 F-12 GL SO FS FL TS Pl

>Sl-203 Rev, 0 Page 51 of IIII

SHNPP VALVE TEST PROGRAM SYSTEM: Radiation Monitoring (SP) Dog, No. (Rev.) 2165-S-0605(0) Page 2 of 2 VALVE SECTION XI DRAWING VALVE SIZE VAI.VE ACTUATOR NORMAL TEST REQUIRED RELIEF NOTE NO, CLASS COORDINATES CATEGORY PASSIVE (Inches) TYPE TYPE POSITION FREQUENCY TEST REQUEST NO.

ISP- A B C 56 J-12 GL SO FS FL TS PI 915 C-12 GL SO FS FL TS PI 917 D-12 GL SO FS FL TS Pl 16 C-13 GL SO FS FL TS PI 28 D-I3 GL SO FS FL TS Pl ISI-203 Rev ~ 0 Page 52 of 118

C 0

SHNPP VALVE TEST PROGRAM SYSTEM: Diesel Generator Dwg, No. (Rev.) 2165-S-0633(2) Page I of I VALVE SECTION XI DRAWING VALVE SIZE VALVE ACTUATOR NORMAL TEST REQUIRED RELIEF NOTE NO. CLASS COORDINATES CATEGORY PASSIVE (inches) TYPE TYPE POSITION FREQUENCY TEST REQUEST NO.

IEA- A B C B-3 RL RL 21 C-3 RL RL 37 B-13 RL RL 52 D-13 RL RL

<SI-203 Rev. 0 Page 53 of I4II

s SHNPP VALVE TEST PROGRAM SYSTEM: Diesel Generator Dwg. No. (Rev.) 2165-S-0633SOI(l) Page I of I VALVE SECTION XI DRAIIING VALVE S I ZE VALVE ACTUATOR NORMAL TEST REPU I RED RE L I EF NOTE NO, CLASS COORDINATES CATEGORY PASSIVE (inches) TYPE TYPE POSITION FREQUENCY TEST REQUEST NO, IDLO- A B C H-6 RL RL 35 M-13 RL RL 27 RL RL 57 H-15 RL RL

>SI-203 Rev, 0 Page 54 of 14II

1 SHNPP VALVE TEST PROGRAH SYSTEM: Misc, Drains (HD) Dwg. No. (Rev.) 2165-S-0685(0) Page 1 of I VALVE SECTION XI DRAIIING VALVE SIZE VALVE ACTUATOR NORMAL TEST REQUIRED RELIEF NOTE NO, CLASS COORDINATES CATEGORY PASSIVE (inches) TYPE TYPE POSITION FREQUENCY TEST REQUEST NO.

IED- A 6 C 94 H-7 GA FS TS Pl 95 H-7 GA FS TS Pl ISI-203 Rev, 0 Page 55 of 148

lt

'I

SHNPP VALVE TEST PROGRAM SYSTEM: Demineralized Water (DW) Dug. No (Rev.) 2165-S-0799(0) Page I of I VALVE SECTION XI DRAWING VALVE SIZE VALVE ACTUATOR NORMAL TEST REQUIRED RELIEF NOTE NO, CLASS COORDINATES CATEGORY PASSIVE (Inches) TYPE TYPE POSITION FREPUENCY TEST REPUEST NO.

IDW- A B C BS R-33 ISI-203 Rev ~ 0 Page 56 of 148

SHNPP VALVE TEST PROGRAM SYSTEM: Service Air (SA) Dwg. No. (Rev.) 2165-S-0800(1) Page I of I VALVE SECTION XI DRAWING VALVE SIZE VALVE ACTUATOR NORMAL TEST REQUIRED RELIEF NOTE NO CLASS COORDINATES CATEGORY PASSIVE (Inches) TYPE TYPE POSITION FREQUENCY TEST REQUEST NO, A 8 C I SA-82 2 C-3 BS R-33

>Sl-203 Rev, 0 Page 57 of 148

- SHNPP VALVE TEST PROGRAM SYSTEM: Instrument Air (IA) Dwg, No, (Rev,) 2165-S-0801(0) Page I of 1 VALVE SECTION XI DRAW I NG VALVE S I ZE VALVE ACTUATOR NORMAL TEST REQUIRED RELIEF NOTE NO, CLASS COORDINATES CATEGORY PASS I VE (inches) TYPE TYPE POSITION FREQUENCY TEST REQUEST NO.

A B C I I A-216 2 C-3 GA FS R-23 FL TS Pl IIA-220 2 C-3 BS R-23 ISI-203 Rev. 0 Page 58 of 148

SHNPP VALVE TEST PROGRAM SYSTEM: Fuel Pool Cooling Dwg, No. (Rev.) 2165-S-805(2) Page I of I VALVE SECTION XI DRAIIING VALVE SIZE VALVE ACTUATOR NORMAL TEST REQUIRED RELIEF NOTE NO. CLASS COORDINATES CATEGORY PASSIVE (Inches) TYPE TYPE POSITION FREQUENCY TEST REQUEST NO.

ISF- A B C G-9 12 FF 13 12 FF 45 H-3 3/4 RL RL 66 K-3 3/4 RL RL

>St-203 Rev. 0 Page 59 of 118

SHNPP VALVE TEST PROGRAM SYSTEM: Emergency Screen Wash (SC) Dug. No. (Rev.) 2165-S-0808(0) Page I of I VALVE SECTION XI DRAW I NG VALVE SIZE VALVE ACTUATOR NORMAL TEST REQUIRED RELIEF NOTE NO, CLASS COORD I NATES CATEGORY PASSIVE (inches) TYPE TYPE POSITION FREQUENCY TEST REQUEST NO.

I SC- A B C 24 C- I 5 FF 34 C-12 FF 40 B-16 GL EH FS TM PI FL 37 B-13 GL EH FS TM Pl FL 20 D-16 GL EH FS TM PI FL 30 D-13 GL EH FS TM Pl FL 3SC-41 3 B"16 GL EH FS TM Pl FL ISI-203 Rev. 0 Page 60 of 148

0 SHNPP VALVE TEST PROGRAM SYSTEM: Fire Protection (FP) Dwg. No. (Rev.) 2165-S-0888(0) Page I of I VALVE SECTION XI DRAWING VALVE SIZE VALVE ACTUATOR NORMAL TEST REQU I RED RE L I EF NOTE NO CLASS COORDINATES CATEGORY PASSIVE (inches) TYPE TYPE POS I T I ON FREQUENCY TEST REQUEST NO, IFP- A B C 355 L-2 GL AO FS FL TS Pl 357 L-3 BS R-33 347 L-2 GL AO FS FL TS Pl 349 BS R-33 ISI-203 Rev. 0 Page 61 of 148

I E,

SHNPP VALVE TEST PROGRAM SYSTEM: ESW Bearing Lubrication Dwg. No. (Rev.) 2165-S-936(2) Page I of I VALVE SECTION XI DRAWING VALVE SIZE VALVE ACTUATOR NORMAL 'EST REPUIRED RELIEF NOTE NO, CLASS COORDINATES CATEGORY PASSIVE (inches) TYPE TYPE POSITION FREpUENCY TEST REpUEST NO.

ISW- A B C 1317 3/4 CK FF 1319 J-13 3/4 CK FF 280 3/4 GA SO FS FL TM Pl 282 1-13 3/4 GA SO FS FL TM PI 1335 J-15 GL SO FS FL TM Pl 1326 K-15 GL SO FS FL TM Pl 1331 J-13 RL RL 1323 K-13 RL RL iSI-203 Rev, 0 Page 62 of 148

Cl

- SHNPP VALVE TEST PROGRAM SYSTEM: HVAC Chilled Mater Dug, No, (Rev.) 2165-S-0998(0) Page I of I VALVE SECT ION XI DRAWING VALVE SIZE VALVE ACTUATOR NORMAL TEST REQUIRED RELIEF NOTE NO, CLASS COORDINATES CATEGORY PASSIVE (Inches) TYPE TYPE POSITION FREQUENCY TEST REQUEST NO.

I CH- A B C 115 H-14 BF AO FS FL TM Pl 126 L-10 BF AO FS FL TM Pl 116 H-14 BF AO FS FL TM Pl 125 L-10 BF AO FS FL TM Pl rSI-203 Rev, 0 Page 63 of 148

I 4

SHNPP VALVE TEST PROGRAM SYSTEH: Chilled Water Dwg, No, (Rev.) 2165-S-998S02(0) Page I of 2 VALVE SECTION XI DRAWING VALVE S I ZE VALVE ACTUATOR NORMAL TEST REQUIRED RELIEF NOTE NO, CLASS COORDINATES CATEGORY PASSIVE (inches) TYPE TYPE POSITION FREQUENCY TEST REQUEST NO A B C ISW-1171 3 G-5 GL -

SO FS FL TH Pl ISW-1175 E-6 10 EH FS FL TH Pl I SW-1199 3 C-8 FF BS I CH-6 F-3 RL RL I CH-10 H-3 RL RL IF P-1015 3 1-4 GL SO FS FL TH PI IF P-1014 3 1-4 GL SO FS FL TH Pl ISA-494 3 E-3 GL SO FS FL TH PI ISA-495 3 GL SO FS FL TH Pl Page 64 of 148

l

- SHNPP VALVE TEST PROGRAM SYSTEM: Chilled Water Owe No, (Rev,) 2165-S-998S02(0) Page 2 of VAI.VE SECTION XI DRAWING VALVE SIZE VALVE ACTUATOR NORMAL TEST REQUIRED RELIEF NOTE NO CLASS COORDINATES CATEGORY PASSIVE (inches) TYPE TYPE POSITION FREQUENCY TEST REQUEST NO.

A B C I SW-1170 3 F-5 FF ISW-1198 -3 C-B 3/4 RL RL I CH-19 3 H-6 3/4 RL RL I CH-34 3 F-11 3/4 RL RL ISW-1183 3 E-8 RL RL ISI-203 Rev. 0 Page 65 of 148

ll SHNPP VALVE TEST PROGRAH SYSTEM: Chilled Water Dwg. No (Rev.) 2165-S-998S03 Page I of VALVE SECTION XI DRAWING VALVE SIZE VALVE ACTUATOR NORMAL TEST REQUIRED RELIEF NOTE NO CLASS COORDINATES CATEGORY PASSIVE (inches) TYPE TYPE POSITION FREQUENCY TEST REQUEST NO.

ICH- A B C 199 B-l 3W AO FS FL TH Pl 213 B-5 3W AO FS FL TM Pl 232 B-8 AO FS FL TH Pl 251 B-I I 3W AO FS FL TM Pl 265 B-15 3W AO FS FL TM Pl 485 G-I 2% GA AO FS FL TH Pl 279 G-5 AO FS FL TH PI

El-203 Rev. 0 Page 66 of 14II

SHNPP VALVE TEST PROGRAH SYSTEH: Chilled Water D~g. No. (Rev,) 2165-S-998S03 Page 2 of 2 VALVE SECT ION X I DRAW I NG VALVE SIZE VALVE ACTUATOR NORMAL TEST REQUIRED RELIEF NOTE NO, CLASS COORDINATES CATEGORY PASSIVE (inches) TYPE TYPE POSITION FREQUENCY TEST REQUEST NO.

ICH- A B C 299 G-8 3W AO FS FL TH PI 323 G-15 EH FS FL TH Pl 343 K-I 3W AO FS FL TM Pl 363 K-5 AO FS FL TH Pl 381 K-8 23 3W AO FS FL TH Pl 394 K-15 3W AO FS FL TH Pl ISI-203 Rev. 0 Page 67 of 148

• I SHNPP VALVE TEST PROGRAM SYSTEH: Chilled Water Dwg. No. (Rev.) 2165-S-998S04 Page I of I VALVE SECTION XI DRAWING VALVE SIZE VALVE ACTUATOR NORMAL TEST REQUIRED RELIEF NOTE NO. CLASS COORDINATES CATEGORY PASSIVE (inches) TYPE TYPE POSITION FREQUENCY TEST REQUEST NO.

ICM- A B C 409 B-I GA AO FS FL TH PI 422 B-4 GA AO FS FL TH Pl 434 B-8 GA AO FS FL TM Pl 446 B-ll 3W AO FS FL TH Pl 460 F-8 3W AO FS FL TH Pl 472 F-ll 3W AO FS FL TM PI ISI-203 Rev. 0 Page 68 of 148

SHNPP VALVE TEST PROGRAM SYSTEH: Chilled Water Dug. No. (Rev.) 2165-S-999 Page I of I VALVE SECTION XI DRAWING VALVE SIZE VALVE ACTUATOR NORMAL TEST REQUIRED RELIEF NOTE NO, CLASS COORDINATES CATEGORY PASSIVE (inches) TYPE TYPE POSITION FREQUENCY TEST REQUEST NO.

I CH- A 8 C 148 A-16 AO FS FL TH Pl 196 L-15 BF AO FS FL TH Pl 149 A-16 BF AO FS FL TH PI 197 L-16 AO FS FL TH Pl ISI-203 Rev. 0 Page 69 of 14U

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SHNPP VALVE TEST PROGRAM SYSTEM: Chilled Water Owg, No, (Rev.) 2165-S-999S02 Page I of 2 VALVE SECTION XI DRAWING VALVE SIZE VALVE ACTUATOR NORMAL TEST REQUIRED REL I EF NOTE NO, CLASS COORDINATES CATEGORY PASSIVE (inches) TYPE TYPE POSITION FREQUENCY TEST REQUEST NO, A B C I SW-1204 3 M-5 GL SO FS FL TH Pl I SW-1208 3 F-6 10 BF EH FS FL TH Pl I SW-1232 3 D-8 FF BS I CH-50 3 G-3 RL RL ICH-54 3 1-3 RL RL IFP-1025 3 J-4 GL SO FS FL TM Pl IFP-1026 3 J-4 GL SO FS FL TH Pl ISA-502 3 GL SO I FS I FL I TM 5 Pl I SA-503 3 f-3 GL SO FS FL TM Pl

SHNPP VALVE TEST PROGRAM SYSTEM: Chilled Water Dwg. No. (Rev.) 2I65-S-999S02 Page 2 of 2 VALVE SECTION XI DRAWING VALVE SIZE VALVE ACTUATOR NORMAL TEST REQUIRED RELIEF NOTE NO CLASS COORDINATES CATEGORY PASSIVE (inches) TYPE TYPE POSITION FREQUENCY TEST REQUEST NO.

A B C I SW-1216 3 E-9 RL RL ISW-1203 FF I SW-1231 C-8 3/4 RL RL I CH-63 3 H-7 3/4 RL RL I CH-78 3 F-10 3/4 RL RL ISI-203 Rev. 0 Page 71 of 148

SHNPP VALVE TEST PROGRAM SYSTEM: Chilled Hater Dwg. No, (Rev,) 2165-S-999S03 Page I of 2 VALVE SECTION XI DRAWING VALVE SIZE VALVE ACTUATOR NORMAL TEST REQUIRED RELIEF NOTE NO CLASS COORDINATES CATEGORY PASSIVE (inches) TYPE TYPE POSITION FREQUENCY TEST REQUEST NO.

I CH- A 8 C 551 8-1 AO FS FL TM Pl 564 8-5 3W AO I FS I FL I . TH 5 PI 583 8-8 3W AO FS FL TM Pl 603 8-13 GA AO FS FL TH PI 616 F-5 3W AO FS FL TH Pl 630 F-8 3W AO FS FL TH Pl 643 K-I GA AO FS FL TM PI Page 72 of I40

S SHNPP VALVE TEST PROGRAM SYSTEM: Chilled Hater Dwg. No. (Rev.) 2165-S-999S03 Page 2 of 2 VALVE SECTION XI DRAWING VALVE SIZE VALVE ACTUATOR NORMAL TEST REQUIRED RELIEF ALTERNATE NOTE NO. CLASS COORDINATES CATEGORY PASSIVE (inches) TYPE TYPE POSITION FREQUENCY TEST REQUEST TEST NO, I CH- A B C 660 K-5 3W AO FS FL TM PI 680 K-9 3W AO FS FL TM Pl 703 K-12 3W EH FS FL TM PI tSI-203 Rev, 0 Page 73 of 148

- SHNPP VALVE TEST PROGRAM SYSTEH: Chilled Water Dwg. No. (Rev,) 2165-S-999S04 Page I of 2 VALVE SECTION XI DRAWING 'ALVE S I ZE VALVE ACTUATOR NORMAL TEST REQUIRED REL I EF NOTE NO CLASS COORDINATES CATEGORY PASS I VE ( inches ) TYPE TYPE POS I T I ON FREQUENCY TEST REQUEST NO.

I CH- A 8 C 726 8-1 3W AO FS FL TH PI 745 8-5 3W AO FS FL TM Pl 764 8-10 AO FS FL TM Pl 777 8-1'3 3W AO FS FL TH Pl 793 G-7 GA AO FS FL TM PI 807 GA AO FS FL TM Pl 820 J-5 3W AO FS FL TM PI

~ SI-203 Rev, 0 Page 74 of 148

V

- SHNPP VALVE TEST PROGRAM SYSTEM: Chilled Water Dog. No. (Rev.) 2I65-S-999S04 Page 2 of 2 VALVE SECTION XI DRAWING VALVE SIZE VALVE ACTUATOR NORMAL TEST REQUIRED RELIEF NOTE NO. CLASS COORDINATES CATEGORY PASSIVE (inches) TYPE TYPE POSITION FREQUENCY TEST REQUEST NO.

ICH- A B C 833 J-9 GA AO FS FL TM Pl 846 J-13 3W AO FS FL TM Pl ISI-203 Rev, 0 Page 75 ot l4II

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SHNPP VALVE TEST PROGRAH SYSTEH: Reactor Coolant (RC) Dwg. No. (Rev.) 2165-S-1301(0) Page I of 3 VALVE SECTION XI DRAWING VALVE S I ZE VALVE ACTUATOR NORMAL TEST REQUIRED RE L I EF NOTE NO. CLASS COORDINATES CATEGORY PASSIVE (inches) TYPE TYPE POSITION FREQUENCY TEST REQUEST NO.

IRC- A 8 C

'I 27 F-8 RL RL 125 F-6 RL RL 123 F-4 RL RL 117 E-2 GA FS TH PI 115 F-2 GA FS TM PI 113 H-2 FS TH Pl 118 E-I GL AO FS R-17 FL TM Pl 116 F-I GL AO FS R-17 FL TM PI 114 H-I GL AO FS R-17 FL TM Pl ISI-203 Rev, 0 Page 76 of 14II

0

- SHNPP VALVE TEST PROGRAM SYSTEM: Reactor Coolant (RC) D~g. No. (Rev.) 2165-S-1301(0) Page 2 of 3 VALVE SECTION XI DRAWING VALVE SiZE VALVE ACTUATOR NORMAL TEST REQuiREO RELiEF NOTE NO. CLASS COORDINATES CATEGORY PASSIVE (inches) TYPE TYPE POSITION FREQUENCY TEST REQUEST NO.

IRC- A B C 141 C-16 OA AO FS FL TS Pl 144 C- 17 DA AO FS FL TS Pl 164 D-16 BS R-33 161 0-17 X OA AO FS FL TM PI B-7 GL SD FS R-15 FL TM Pl 901 B-7 GL SD FS R-15 FL TM PI 902 B-7 GL SD FS R-15 FL TM Pl 903 A-7 GL SD FS R-15 FL TM Pl

51-203 Rev ~ 0 Page 77 of 148

SHNPP VALVE TEST PROGRAM SYSTEM: Reactor Coolant (RC) Dwg. No. (Rev.) 2165-S-1301(0) Page 3 of VALVE SECTION XI DRAWING VALVE SIZE VALVE ACTUATOR NORMAL TEST REQU I RED REL I EF NOTE NO, CLASS COORDINATES CATEGORY PASSIVE (inches) TYPE TYPE POS I T ION FREQUENCY TEST REQUEST NO, IRC- A B C 904 A-7 GL SD FS R-15 FL TM Pl 905 A-8 GL SD FS R-15 FL TM Pl

<SI-203 Rev, 0 Page 78 of I Iu

SHNPP VALVE TEST PROGRAM SYSTEH: CVC (CS) Dwg, No (Rev.) 2165-S-1303(2) Page I of 3 VALVE SECTION XI DRAWING VALVE S I ZE VALVE ACTUATOR NORMAL TEST REQUIRED RELIEF NOTE NO. CLASS COORDINATES CATEGORY PASSIVE (inches) TYPE TYPE POSITION FREQUENCY TEST REQUEST NO, I CS- A B C 341 K-3 GL FS R-4 TS Pl 344 BS R-18 460 D-8 GL AO FS FL TH Pl 461 D-8 GL AO FS FL TH Pl 470 D-17 GL FS R-4 TS PI 472 D-17 GL FS R-4 TS Pl 471 E-17 3/4 CK FF R-4 BS A-3 GL AO FS FL TH Pl ISI-203 Rev ~ 0 Page 79 of 148

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SHNPP VALVE TEST PROGRAM SYSTEM: CVC (CS) Dwg. No. (Rev.) 2165-S-1303(2) Page 2 of 3 VALVE SECTION XI DRAWING VALVE SIZE VALVE ACTUATOR NORMAL TEST REQUIRED RELIEF NOTE NO CLASS COORDINATES CATEGORY PASSIVE (inches) TYPE TYPE POSITION FREQUENCY TEST REQUEST NO, ICS- A 8 C A-4 X GL AO FS FL TM Pl 8-10 GL AO FS FL TS Pl 8-11 GL AO FS FL TS Pl 8-12 GL AO FS FL TS Pl 10 A-10 RL RL A-17 GL AO FS FL TS Pl 238 8-17 GA FS TS PI 477 8" 16 FF R-19 BS ISI-203 Rev, 0 Page 80 of 148

E SHNPP VALVE TEST PROGRAM SYSTEM: CVC (CS) Dwg. No. (Rev.) 2165-S-1303(2) Page 3 of 3 VALVE SECTION XI DRAWING VALVE S I ZE VALVE ACTUATOR NORMAL TEST REQUIRED RELIEF NOTE NO, CLASS COORDINATES CATEGORY PASS I VE (inches) TYPE TYPE POSITION FREQUENCY TEST REQUEST NO.

ICS- A B C 467 D" 16 RL 4 RL 492 C-4 GL AO FS FL TM Pl 497 FF 500 C-2 FF 493 C-3 3/4 'K FF R-34 s>-203 Rev, 0 Page Bl ot 14(I

SHNPP VALVE TEST PROGRAM SYSTEM: CVC (CS) Dwg. No. (Rev.) 2165-S-1303 SOI(1) Page I of I VALVE SECTION XI DRAWING VALVE SIZE VALVE ACTUATOR NORMAL TEST REQUIRED RELIEF NOTE NO. CLASS COORDINATES CATEGORY PASSIVE (inches) TYPE TYPE POSITION FREQUENCY TEST REQUEST NO.

'I CS- A B C 382 K-3 GL FS R-4 TS Pl 385 K-3 BS R-18 iSI-203 Rev. 0 Page 82 of 148

y 4 SHNPP VALVE TEST PROGRAM SYSTEM: CVC (CS) &g No, (Rev,) 2165-S-1303S02(l) Page I of I VALVE SECTION XI DRAWING VALVE S I ZE VALVE ACTUATOR NORMAL TEST REQUIRED RELIEF NOTE NO, CLASS COORD I NATES CATEGORY PASSIVE (Inches) TYPE TYPE POSITION FREQUENCY TEST REQUEST NO.

I CS- A B C 423 K-3 GL FS R-4 TS PI 426 K-3 BS R-I8 iSI-203 Rev, 0 Page 83 of l48

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II

- SHNPP VALVE TEST PROGRAM SYSTEM: CVC (CS) Dwg, No, (Rev.) 2165-S-1304(2) Page I of I VALVE SECTION XI DRAWING VALVE SIZE VALVE ACTUATOR NORMAL TEST REQUIRED RELIEF NOTE NO. CLASS COORDINATES CATEGORY PASSIVE (inches) TYPE TYPE POSITION FREQUENCY TEST REQUEST NO.

ICS- A 8 C 744 H-I6 RL RL 755 1-16 RL RL 746 H-I7 GL FS TM PI 752 1-17 GL FS TM Pl 98 J-14 GL AO FS TM FL Pl 47 E-12 RL RL ISI -203 Bev. 0 Page 84 of 14II

- SHNPP VALVE TEST PROGRAM SYSTEM: CVC (CS) Dwg. No (Rev,) 2165-S-1305(3) Page I of 4 VALVE SECTION XI DRAWING VALVE S I ZE VALVE ACTUATOR NORMAL TEST REQUIRED REL I EF NOTE NO ~ CLASS COORDINATES CATEGORY PASSIVE (Inches) TYPE TYPE POSITION FREQUENCY TEST REQUEST NO.

ICS- A B C 165 G-ll GA FS R-5 TM Pl 166 G-11 GA FS R-5 TH PI 278 J-16 GL FS TH Pl 279 J-16 FF R-20 292 K-ll GA HO FS I TM Pl 291 1-12 GA FS TH PI 170 GA FS TH Pl 168 GA FS TH Pl 169 GA FS TM PI ISI-203 Rev. 0 Page 85 of 148

SYSTEM:

VALVE NO, ICS-171 294 179 207 193 178 206 192 182 CVC CLASS (CS)

SECT ION X I DRAWING J-14 H-8 J-8 K-8 H-7 J-7 K-7 G-7

'F COORDINATES A

VALVE CATEGORY B C PASSIVE SHNPP VALVE TEST PROGRAM SIZE (inches )

VALVE TYPE GA CK GL ACTUATOR TYPE NORMAL POSITION Dug, No, (Rev.)

TEST FREQUENCY REQUIRED TEST FS TM Pl FF BS FF BS FF BS FF BS FF BS FF BS FS TM Pl 2165-S-1305(3)

RELIEF REQUEST R-6 NOTE NO.

Page 2 of 4 210 1-7 GL FS TM PI 196 J-7 GL FS TM Pl

<51-203 Rev, 0 Page 86 ol 148

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" SHNPP VALVE TEST PROGRAH SYSTEH: CVC (CS) Dwg. No. (Rev.) 2165-S-1305(3) Page 3 of 4 VALVE SECTION XI DRAIIING VALVE SIZE VALVE ACTUATOR NORMAL TEST REQUIRED RELIEF NOTE NO, CLASS COORDINATES CATEGORY PASSIVE (Inches) TYPE TYPE POSITION FREQUENCY TEST REQUEST NO.

I CS- A 8 C 219 1-6 GA FS R-7 TH Pl 217 1-6 GA FS R-7 TH PI 218 K-6 GA FS R-7 TM Pl 220 K-6 GA FS R-7 TH PI 235 H-2 GA FS TH PI 290 J-12 3/4 RL RL 293 K-12 3/4 RL RL 167 G-11 4 CK FF 214 F-4 GA FS TM Pl 3'IO E-3 RL RL 127 C-IO RL RL iSI-203 Rev. 0 Page 87 of 118

" SHNPP VALVE TEST PROGRAM SYSTEM: CVC (CS) D~g. No. (Rev.) 2165-S-1305(3) Page 4 of 4 VALVE SECTION XI DRAWING VALVE S I ZE VALVE ACTUATOR NORMAL TEST REQUIRED RELIEF NOTE NO, CLASS COORDINATES CATEGORY PASSIVE (inches) TYPE TYPE POSITION FREQUENCY TEST REQUEST NO.

I CS- A B C 231 H-4 GL AO FS FL TM Pl 151 F-15 GL AO I FS I FL I TM 5, Pl ISI-203 Rev. 0 Page 88 of 148

" SHNPP VALVE TEST PROGRAM SYSTEM: CVC (CS) D~g. No. (Rev.) 2165-S-1306 Page I of I VALVE SECTION XI DRAWING VALVE SIZE VALVE ACTUATOR NORMAL TEST REQUIRED RELIEF NOTE NO. CLASS COORDINATES CATEGORY PASSIVE (inches) TYPE TYPE POSITION FREQUENCY TEST REQUEST NO.

ICS- A 8 C 570 8-5 DA AO FS FL TM PI 662 DA AO FS FL TM PI 601 F-17 3/4 RL RL ISI-203 Rev, 0 Page 89 of 148

- SHNPP VALVE TEST PROGRAM SYSTEM: CVC (CS) pwg, No (Rev,) 2I65-S-1307(l ) Page I of I VALVE SECTION XI DRAW I NG VALVE SIZE VALVE ACTUATOR NORMAL TEST REQUIRED RELIEF NOTE NO, CLASS COORDINATES CATEGORY PASSIVE (Inches) TYPE TYPE POSITION FREQUENCY TEST REQUEST NO, I CS- A 8 C 536 E-7 X. FF BS 546 G-7 FF BS 559 E-4 FS FL TM Pl 563 E-2 FS FL TH PI

~ II ISI-203 Rev, 0 . Page 90 of 148

9 os'YS(EM:

SHNPP VALVE TEST PROGRAM Satety Injection (Sl) Dwg. No. (Rev.) 2165-S-1308(1) Page I ot 2 VAI Vf; SECT(0~ Xl DRAWING VALVE SIZE VALVE ACTUATOR NORMAL TEST REQUIRED RELIEF NOTE NO, CLASS COORDINATES CATEGORY PASSIVE (inches) TYPE TYPE POSITION FREQUENCY TEST REQUEST NO.

ISI- A B C F-2 GA FS TS PI GA FS TS Pl 0-3 X CK R-32 0-4 CK FF R-32 IO CK FF R-32 B-3 R-32 8/ C-3 fF R-32 il 5 0-3 FF R-32 F-12 GA MO FS R-8 TM Pl 104 D-12 R-32 105 D-13 fF R-32 106 0-14 CK FF R-32 134 B-II CK ff LK I '55 C-l I X CK Ff LK I ii .AI 5 In;v ~ I I'.<<Iv 91 or I ~ IN

ii SHNPP VALVE TEST PROGRAM SYSTEH: Safety Injection (Sl), Dwg. No. (Rev.) 2165-S-1308(1) Page 2 of 2 VALVE SECTION XI DRAWING VALVE SIZE VALVE ACTUATOR NORMAL TEST REQUIRED RELIEF NOTE NO, CLASS COORDINATES CATEGORY PASSIVE (inches) TYPE TYPE POSITION FREQUENCY TEST REQUEST NO ISI- A B C 136 B-I7 FF R-32 137 C-17 FF R-32 138 D-17 FF R-32 107 F-14 GA FS R-8 TH Pl 127 D-15 FF R-32 128 D-15 FF R-32 129 D-16 FF R-32 52 F-11 GA FS R-8 TM Pl 72 D-6 FF R-32 73 D-7 FF R-32 74 D-8 FF R-32 GA FS TM Pl N-5 GA FS TH Pl ISI-203 Rev. 0 Pdge 92 of 148

OSI SHNPP VALVE TEST PROGRAM SYSfLH: SafeTy Injec1ion (Sl) Dwg. No. (Rev.) 2165-S-1309(2) Page I of 2 VAIVE SECTION XI DRAWING VALVE S I ZE VALVE ACTUATOR NORMAL TEST REQUIRED REL IEF NOTE NU. CLASS COORD I NATES CATEGORY PASS I VE ( inches ) TYPE TYPE POS I T ION F REQUE NCY TEST NO.

REQUEST ISI A B C 0-3 12 CK FF R-14 LK 252 G-3 12 CK FF R-14 LK 254 J"3 12 CK FF R- I 4 LK 249 0-5 12 CK FF R-14 LK G-5 12 CK FF R-14 LK

.'55 J-5 12 CK Ff'K R-14 225 8-12 RL RL 226 E-12 RI. RL H-12 RL RL 264 D-4 3/4 GL AO I FS I FL I TS 5 f'I 263 0-4 3/4 GL AO FS f'L 1S Pl J-16 R-33 i ~ ~ .'o5 In v, I I'.>)o 95 of I la

SHNPP VALVE TEST PROGRAM SYSTEM: Safety Injection (SI) D~g, No, (Rev,) 2165-S-1309(2) Page 2 of 2 VALVE SECTION XI DRAWING VALVE S I ZE VALVE ACTUATOR NORMAL TEST REQUIRED REL IEF NOTE NO CLASS COORDINATES CATEGORY PASSIVE (inches) TYPE TYPE POSITION FREQUENCY TEST REQUEST NO.

ISI- A 8 C 179 J-l7 GL AO FS FL TS PI 290 C" 16 BS R-33 287 C"17 GL AO FS FL TS Pl IS I -203 Rev, 0 Page 94 of 148

SHNPP VALVE TEST PROGRAM SYSTEH: Safety Injection (Sl ) Dug, No (Rev,) 2165-S-1310(2) Page I of 2 VALVE SECTION XI DRAWING VALVE SIZE VALVE ACTUATOR NORMAL TEST REQUIRED RELIEF NOTE NO, CLASS COORDINATES CATEGORY PASS I VE (inches) TYPE TYPE POSITION FREQUENCY TEST REQUEST NO.

ISI- A 8 C 301 M-6 X 14 GA FS TH Pl N-6 14 GA I FS I TH 5 PI 311 M-7 14 GA FS TH Pl 310 N-7 14 GA I, I

FS TH 5 PI 323 M-10 14 GA FS TM Pl 322 N-10 14 GA HO FS TH Pl 321 H-12 14 FF 320 N-12 14 FF 329 E-4 3/4 RL RL 328 8-4 3/4 RL RL 327 E-5 10 GA FS TH Pl ISI-203 Rev, 0 Page 95 of 14(I

" SHNPP VALVE TEST PROGRAM SYSTEM: Safety Injection (Sl ) Owg. No. (Rev.) 2165-S-1310(2) Page 2 ol 2 VALVE SECTION XI DRAMING VALVE SIZE VALVE ACTUATOR NORMAL TEST REPU I RED REL I EF'OTE NO ~ CLASS COORDINATES CATEGORY PASSIVE (inches ) TYPE TYPE POSITiON FREPUENCY TEST REPUEST NO, ISI- A 8 C 326 0-5 10 GA MO FS TM Pl 559 B-3 10 FS TM Pl 341 F-4 IO GA MO FS TM Pl 5 lu C-4 10 GA FS 1M Pl 347 F-3 10 CK FF LK 346 C-3 10 2 FF R-9 5 LK C-I CK 2 FF R-9 5 LK 357 E-I CK FF R-9 LK 358 F-I FF R-9 LK 330 3/4 RL RL

.'1>5 I<c>v. I

~ '

osi SHNPP VALVE TEST PROGRAM SYSTEM: Containment Waste Processing Dwg. No. (Rev.) 2165-S-1313(2) Page I of I VALVE SECTION XI DRAWING VALVE SIZE VALVE ACTUATOR NORMAL TEST REQUIRED RELIEF NOTE NO," CLASS COORD I NATES CATEGORY PASSIVE (inches) TYPE TYPE POSITION FREQUENCY TEST REQUEST NO.

IED- A B C 164 E-6 3/4 DA AO I FS I FL I TS 5 Pl 161 C-7 3/4 DA AO FS FL TS PI 125 0-16 DA AO FS FL TS Pl 121 E-16 GL AO FS FL TS Pl ISI-203 Rev. 0 Page 97 of 148

I, A

S1 SHNPP VALVE TEST PROGRAM

~

SYSTEM: Component Cooling Water (CC) Dug. No. (Rev.) 2165-S-1319(0) Page I of 2 VALVE SECTION XI DRAWING VALVE S I ZE VALVE ACTUATOR NORMAL TEST REQUIRED REL I EF NOTE NO, CLASS COORDINATES CATEGORY PASSIVE (inches) TYPE TYPE POSITION FREQUENCY TEST REQUEST NO I CC- A B C E-8 18 FF BS 64 H-8 18 FF BS 50 K-8 18 FF BS 99 F-17 18 BF FS TM Pl 113 G-17 I8 FS TH PI C-3 RL RL 128 G-3 18 FS TH Pl 127 H-3 18 BF FS TM Pl 29 G-4 3/4 RL RL 114 G-18 DA AO FS FL TM Pl ISI-203 Rev, 0 Page 98 ot 148

- SHNPP VALVE TEST PROGRAH SYSTEH: Component Cooling Water (CC) Dwg. No. (Rev.) 2165-S-1319(0) Page 2 ot 2 VALVE SECTION XI DRAWING VALVE SIZE VALVE ACTUATOR NORMAL TEST REQUIRED RELIEF NOTE NO, CLASS COORDINATES CATEGORY PASSIVE (inches) TYPE TYPE POSITION FREQUENCY TEST REQUEST NO.

ICC- A B C

'I 15 F-18 DA AO FS FL TM Pl 118 BS R-22 119 BS R-22 ISI-203 Rev, 0 Page 99 of 118

OS I SHNPP VALVE TEST PROGRAM SYSTEM: Component Cooling Water (CC) Dug. No. (Rev.) 2165-S-1320(0) Page 1 of I VALVE SECTION XI DRAWING VALVE SIZE VALVE ACTUATOR NORMAL TEST REQUIRED RELIEF NOTE NO. CLASS COORDINATES CATEGORY PASSIVE (inches) TYPE TYPE POSITION FREQUENCY TEST REQUEST NO.

ICC- A B C

- 147 A-7 12 GA FS TM Pl 167 L-7 12 GA FS TM Pl 145 RL RL 165 L-8 RL RL ISI-203 Rev, 0 Page 100 of 118

, I~

- SHNPP VALVE TEST PROGRAM SYSTEM: Component Cooling Water (CC) Dwg. No. (Rev. ) 2165-S-1321 (I ) Page I of 2 VALVE SECTION XI DRAWING VALVE S I ZE VALVE ACTUATOR NORMAL TEST REQUIRED RELIEF NOTE NO CLASS COORDINATES CATEGORY PASS I VE (inches) TYPE TYPE POSITION FREQUENCY TEST REQUEST NO, I CC- A B C 176 GA FS TS Pl 202 B-10 GA I FS TS 5 Pl 208 F-I GA FS R-10 TS Pl 211 F-I BS R-13 294 F-12 RL RL 297 E-12 GA FS R-10 TS Pf 298 F-13 3/4 CK FF R-29 BS 299 E-13 GA FS R-10 TS Pl 249 E-15 GA FS R-10 TS Pl 250 F-16 3/4 CK FF R-29 BS ISI-203 Rev, 0 Page 101 of 1 18

4 os'YSTEM:

SHNPP VALVE TEST PROGRAM Component Cooling Water (CC) Dog. No. (Rev.) 2165-S-1321(l) Page 2 of 2 VALVE SECTION XI DRAWING VALVE SIZE VALVE ACTUATOR NORMAL TEST REQUIRED RELIEF NOTE NO, CLASS COORDINATES CATEGORY PASSIVE (inches) TYPE TYPE POSITION FREQUENCY TEST REQUEST NO, ICS- A B C 251 E-15 GA FS R-10 TS Pl 207 GA FS R-10 TS Pl 186 D-8 3/4 RL RL 194 E-8 RL RL 219 N-4 3/4 RL RL 230 N-8 3/4 RL RL 241 N-11 3/4 RL RL 215 N-I BS R-13 216 BS R-13 226 N-3 BS R-13 227 N-5 BS R-13 237 N-9 BS R-13 238 N-9 BS R-13 252 D-15 GA FS R-10 TM Pl

>Sf-203 Rev. 0 Page 102 ot 118

0 J

s SHNPP VALVE TEST PROGRAM SYSTEM: Component Cooling Water (CC) Dwg. No.(Rev.) 2165-S-1322(0) Page I of I VALVE SECTION XI DRAWING VALVE SIZE VALVE ACTUATOR NORMAL TEST REQUIRED RELIEF NOTE NO ~ CLASS COORDINATES CATEGORY PASSIVE (inches) TYPE TYPE POSITION FREQUENCY TEST REQUEST NO, I CC- A B C 304 A-6 3/4 DA AO I FS I FL I TM 5 Pl 305 A-6 3/4 DA AO FS FL TM Pl 313 3/4 RL RL 322 J-2 3/4 RL RL 335 J-4 X 3/4 RL RL 352 J-8 X 3/4 RL RL 355 J-10 3/4 RL RL 362 J-12 3/4 RL RL 306 C-6 3/4 CK BS R-22 307 D-6 3/4 CK BS R-22 ISI-203 Rev, 0 Page 103 ot 148

1 0

- SHNPP VALVE TEST PROGRAM SYSTEM: Component Cooling Mater (CC) D~g, No, (Rev.) 2165-S-1322SOI(0) Page I of I VALVE SECTION XI DRAWING VALVE SIZE VALVE ACTUATOR NORMAL TEST REQUIRf D REL IfF NOTE NO, CLASS COORDINATES CATEGORY PASS I VE (inches) TYPE TYPE POSITION FREQUENCY TEST REQUEST NO.

I CC- A B C 381 G-3 3/4 RL RL 397 3/4 RL RL 486 G-10 3/4 RL RL 472 D-14 3/4 RL RL ISI-203 Rev ~ 0 Page 104 of 141I

" SHNPP VALVE TEST PROGRAM SYSluM: Residual Meat Removal (RM) Dwg. No. (Rev. ) - 2165-S-1324 (2) Page I ol VAI-VL SECTION XI DRAWING VALVE SIZE VALVE ACTUATOR NORMAL TEST REQUIRED REL IEF NOTE NO. CLASS COORDINATES CATEGORY PASSIVE (inches) TYPE TYPE POS IT ION FREQUENCY TEST REQUEST NO.

II(II- A B C 1-3 12 GA FS R-12 TH Pl LK 40 1-4 12 GA HO FS R-12 TH PI LK 12 GA FS R-12 TM PI LK L-4 12 GA FS R-12 TM PI LK 45 I(-6 RL RL K-6 RL 4 - RL 20 0-i I BF AO FS FL TH Pl 58 G-13 BF AO FS I FL I TM 5 Pl

.'ll i l<uv, I I>u)u IU5 ot I lit

- SHNPP VALVE TEST PROGRAM SYSTEM: Residual Heat Removal (RH) Dwg. No, (Rev,) 2165-S-1324(2) Page 2 of 2 VALVE SECTION X I DRAWING VALVE S I ZE VALVE ACTUATOR NORMAL TEST REQUIRED REL I EF NOTE NO CLASS COORDINATES CATEGORY PASS I VE ( Inches ) TYPE TYPE POSITION FREQUENCY TEST REQUEST NO.

I CS- A B C 63 F-12 GA . MO I FS

'I TM 5 PI 25 D-12 GA FS TM Pl 66 E- I I IO AO FS FL TM PI 30 C-ll 10 BF AO FS FL TM PI 70 E-8 10 FF BS 34 C-7 10 FF BS 31 H-7 GA FS TM PI 69 H-8 GA FS TM Pl 120 1-4 3/4 RL RL 121 L-4 3/4 RL RL ISI-203 Rev, 0 Page 106 of 148

SHNPP VALVE TEST PROGRAM SYSTEM: Containment-HVAC Dwg. No. (Rev.) 2168-G-517 (5) Page I of 2 VALVE SECTION XI DRAWING VALVE S I ZE VALVE ACTUATOR NORMAL TEST REQUIRED REL IEF NOTE NO. CLASS COORDINATES CATEGORY PASS I VE ( Inches ) TYPE TYPE POSITION FREQUENCY TEST REQUEST NO, A 8 C CM-85 E-3 BF AO FS FL TM Pl CP-85 I-3 BF AO I FS I FL I TS 5 . Pl CP-86 1-2 AO FS FL TS PI CP-87 H-3 42 BF AO LC FS R-27 FL TS Pl CP-88 H"2 42 BF AO LC FS R-27 FL TS Pl CP-81 AO FS FL TS PI CP-82 J-3 . X BF AO FS FL TS PI ISI-203 Rev, 0 Page 107 of I III

OS I SHNPP VALVE TEST PROGRAM SYSTEM: Containment-HVAC Dog, No. (Rev.) 2168-G-517 (5) Page 2 of 2 VALVE SECTION XI DRAI(ING VALVE SIZE VALVE ACTUATOR NORMAL TEST REQUIRED RELIEF NOTE NO. CLASS COORDINATES CATEGORY PASSIVE (inches) TYPE TYPE POSITION FREQUENCY TEST REQUEST NO A 8 C CP-83 K-3 42 BF AO LC FS R-27 FL TS Pl CP-84 K-2 42 BF AO LC 2 FS R-27 2 FL 2 TS 5 PI CB-Vl 24 FF R-I BS CB-81 L-2 24 BF AO FS FL TS PI CB-V2 M-3 24 FF R-I BS CB-82 2 M-2 24 BF AO FS FL TS PI CM-V I FF R-I BS ISI-203 Rev. 0 Page 108 of 148

- SHNPP VALVE TEST PROGRAM SYSTEH: Auxiliary Bldg. IIVAC Dug. No. (Rev.) 2168-G-517S03 Page I of I VALVE SECTION XI DRAWING VALVE SIZE VALVE ACTUATOR NORMAL TEST REQUIRED RELIEF NOTE NO, CLASS COORDINATES CATEGORY PASS I VE (inches) TYPE TYPE POSITION FREQUENCY TEST REPUEST NO, A 8 C 3AV-81 3 F-14 20 FS TM PI 3AV-82 3 F-17 20 FS

'M Pl 3AV-83 3 E-14 FS TH 3AV-84 3 F-14 20 BF FS TH Pl 3AV-85 F-17 20 FS TH Pl 3AV-86 G-14 FS TM 3AV-V3 3 E-14 FF 3AV-V4 3 G-14 FF ISI-203 Rev, 0 Page 109 ot I III

E

'I I

SHNPP VALVE TEST PROGRAM SYSTEM: Control Room HVAC Dug. No. (Rev.) 2168-G-517S04 Page I of 2 VALVE SECTION XI DRAW I NG VALVE S I ZE VALVE ACTUATOR NORMAL TEST REQUIRED REL I EF NOTE NO CLASS COORDINATES CATEGORY PASSIVE (Inches) TYPE TYPE POSITION FREPUENCY TEST REPUEST NO.

A 8 C 3CZ-817 3 G-2 36 BF C FS TM Pl 3CZ-818 3 G-2 36 BF FS TM PI 3CZ-BI 3 H-2 16 BF FS TM Pl 3CZ-82 3 H-2 16 BF FS TM Pl 3CZ-B25 3 G-4 X 36 BF FS TM 3CZ-826 3 H-4 36 BF FS TM 3CZ-83 3 E-2 12 BF FS TM PI 3CZ-B4 3 12 BF FS TM Pl 3CZ-813 3 8-4 30 FS TM Pl 3CZ-814 8-4 30 BF FS TM Pl 3CZ-89 3 N-5 12 BF FS TM Pl 3CZ-BIO 3 N-5 12 BF FS TM PI

~

Sl-203 Rev, 0 Page 110 of 148

- SHNPP VALVE TEST PROGRAM SYSTEM: Control Room MVAC Dwg. No. (Rev.) 2168-G-517S04 Page 2 of 2 VALVE SECTION XI DRAWING VALVE SIZE VALVE ACTUATOR NORHAL TEST REQUIRED RELIEF NOTE NO, CLASS COORDINATES CATEGORY PASS I VE (inches) TYPE TYPE POSITION FREQUENCY TEST REQUEST NO, A 8 C 3CZ-BII 3 N-11 12 BF FS TM PI 3CZ-B12 3 N-ll 12 FS TH PI 3CZ-823 3 L-6 20 FS TM Pl 3CZ-821 K-6 20 BF FS TM Pl 3CZ-824 L-7 20 BF FS TM PI 3CZ-822 L-6 20 BF FS TH Pl 3CZ-BI 9 3 II-7 20 BF FS TH Pl 3CZ-820 3 M-8 20 BF FS TH Pl 3CZ-Vl L"7 FF 3CZ-V2 3 L-7 FF ISI-203 Rev. 0 Page lll of 14(I

',I g

os'YSTEM:

SHNPP VALVE TEST PROGRAM Switchgear 8, Protection Room HVAC Owg. No, (Rev,) 2168-G-517S05 Page I of I VALVE SECTION XI ORAWING VALVE SIZE VALVE ACTUATOR NORMAL TEST REQUIRED REl.iEF NOTE NO, 'LASS COORDINATES CATEGORY PASSIVE (inches) TYPE TYPE POSITION FREQUENCY TEST REQUEST NO.

A B C 3CZ"B5 3 L-3 12 BF FS TM Pl 3CZ-B6 3 12 BF FS TM PI 3CZ-B7 3 K-10 12 FS TM Pl 3CZ-B8 3 K-9 12 FS TM Pl ISI-203 Rev, 0 Page 112 of 1 18

- SHNPP VALVE TEST PROGRAM SYSTEM: Fuel Handling Bldg. HVAC Dwg. No. (Rev.) 2168-G-533(7 ) Page I of I VALVE SECTION XI DRAWING VALVE S I ZE VALVE ACTUATOR NORMAL TEST REQUIRED RELIEF NOTE NO, CLASS COORDINATES CATEGORY PASS I VE (inches) TYPE TYPE POSITION FREQUENCY TEST REQUEST NO, A B C 3FV-B2 3 G-14 24 BF FS TM PI 3FV-B4 3 F-14 24 FS TM PI ISI-20$ Rev. 0 Page 113 of 148

pW OS1 Relief Request: R-1 Valves: CB-V1, CB-V2, 1CT-53, 1CT-91, CM-Vl Category.'

Class: 2 Function: Containment Spray (CT), Containment Vacuum Relief (CB),

and Containment Hydrogen Purge Makeup Test Requirement: Demonstrate operability by performing forward Elow and backseat tests quarterly.

Basis for Relief: These check valves cannot be tested with system fluid flow through the valves. Entrance must be made into Containment to test the valves.

Entry into Containment quarterly to perform these tests would result in personnel radiation exposure that is not in compliance with requirements of the NRC mandated ALARA Program. As these valves sole function is to mitigate the consequences of an accident, and are not in contact with any process liquid, it is not expected that their mechanical condition

,.will degrade from test to test.

Alternate Test: Demonstrate operability by performing forward flow and backseat tests at refueling.

ISI-203-Rev. 0 Page 114 o f 148

Relief Request: R-2 Valves: 1MS-80, 82, 84 Category'B Class: 2 Function'Main Steam Isolation Valves (MSIV)

Test Requirement: Exercise for operability', observe proper operation of fail-safe mechanism'and measure stroke time quarterly.

Basis for Relief: Cycling t'hese'alves during normal operation results in a loss of main steam to the turbine, causing a reactor trip.

Alternate Test: Exercise valve for operability', observe proper operation of fail-safe mechanism', and measure stroke time during cold shutdown. Partial stroke valve during normal operation in accordance with Technical Specification at least quarterly.

ISI-203-Rev. 0 Page 115 o f 148

re )

OS1 Relief Request: R-3 Valves'1FM-159, 217, 277 Category'. B Class: 2 Function.'ain Feedwater Isolation Valves (MFIV)

Test Requirement: Exercise for operability; observe proper operation of fail-safe actuator', and measure stroke time quarterly.

Basis for Relief: Cycling th'ese valves during normal operation results in a loss of feedwater to the steam genera'tors, causing a reactor trip.

Alternate Test: Exercise valve for operability', observe proper operation of fail.-safe actuator', and measure stroke time during cold shutdown. Partial stroke during normal operation at least quarterly.

ISI-203-Rev. 0 Page 116 of 148

f OS1 Relief Request: R-4 Valves: 1CS-341, 382, 423, 470, 471, 472 Category: B, C Class'2 Function.'Reactor Coolant Pump Seal Water Lines Test Requirement: Exercise for operability and measure stroke time quarterly for the motor operated valves, and perform'orward flow and backseat tests quarterly for the check valve.

Basis for Relief: Cycling these valves during normal operation or cold shutdown results in loss of normal seal water flow through the reactor coolant pump seals, resulting in possible damage to the seals.

Alternate Test: Exercise for operability and measure stroke time at refueling for the motor operated valves, and perform forward flow and backseat tests at refueling for the check valve.

ISI-203-Rev. 0 Page 117 of 148

OSL h

Relief Request: R"5 Valves: 1CS-165, 166 Category: B Class: 3 Function: Isolate Volume Control Tank on Safety Injection Signal Test Requirement: Exercise for operability and measure stroke time quarterly.

Basis for Relief: These valves cannot be cycled during normal operation because of the loss of normal charging source of borated water (the volume control tank). Aligning charging pumps to alternate source of water would either cause uncontrolled boration or diLution of the reactor coolant system. In addition, testing during normal operation or at cold shutdown with.a CSIP in operation could result in loss of RCP seal injection and CSIP damage if both the VCT and RWST supply valves were inadvertently closed.

Alternate Test: Exercise for operability and measure stroke time at refueling.

ISI-203-Rev. 0 Page 118 of 148

OS1 Relief Request: R-6 Valves: 1CS-294 Category: C Class: 2 Function: Supply Water from Refueling Water Storage Tank to Suction of High-Head Safety Injection Pumps.

Test Requirement: Demonstrate operability by performing a forward flow test quarterly.

Basis for Relief: This valve cannot be tested during normal operation because the charging pumps would be taking suction from the refueling water storage tank to test the valve. This operation would cause an uncontrolled boration of the reactor coolant system.

Alternate Test: Demonstrate operability by performing a forward flow test at refueling.

ISI-203-Rev. 0 Page 119 of 148

OS1 Relief Request: R-7 Valves: 1CS-218, 217, 219, 220 Category'. B Class'2 Function.'solate High-Head Safety Injection System Headers During the Long-Term Recirculation Phase After a LOCA.

Test Requirement: Exercise for operability and measure stroke time quarterly.

Basis for Relief: These valves cannot be cycled during normal operation because cycling them would cause loss

, of seal injection to RCP and safety injection from pumps A 6 C to high head safety injection. Loss of seal injection to the reactor coolant pumps will cause degradation of pump seals.

Alternate Test: Valves will be exercised at cold shutdown.

Partial stroking is precluded by valve design.

ISI-203-Rev. 0 Page 120 o f 148

OS1 Relief Request: R-8 Valves'1SI-52, 86, 107 Category: B Class'2 Function.'High head safety injection isolation valves Test Requirement: Exercise valve for operability and measure stroke time quarterly.

Basis for Relief: Cycling these valves during normal operation or cold shutdown would cause RCS injection flow to bypass the regenerative heat exchanger, thereby thermalLy shocking the RCS piping and causing an overtemperature condition in the letdown line. During cold shutdown with the RCS solid, a cold overpressurization event could occur.

Alternate Test: Exercise valve for operability and measure stroke time at refueling.

ISI-203-Rev. 0 Page 121 of 148

OS1 Relief Request: R-9 Valves: 1SI-134, 135, 346, 347, 356, 35?, 358 Category.'

Class.', 2 Function: Safety Injection Test Requirement: Demonstrate operability by performing a forward flow test quarterly.

Basis for Relief: These check valves cannot be tested during normal operation because RC system pressure is greater than RHR system pressure, and flow cannot be established through these valves.

Alternate Test: Demonstrate operability by performing a forward flow test at cold shutdown.

ISI-203-Rev. 0 Page 122 of 148

OS1 Relief Request: R-10 Valves.'CC-208, 249, 251, 297, 299, 207, 252 Category: B, C Class'2 Function'Isolate Component Cooling Water to RCP's Test Requirement: Exercise for operability and measure stroke time quarterly.

Basis for Relief: Cooling water cannot be isolated to the RCP's during normal operation nor at cold shutdown, as one or more RCP is running while in cold shutdown and RC temperature above 140'F.

Alternate Test: Exercise for operability and measure stroke time at refueling.

ISI-203-Rev. 0 Page 123 of 148

OS1 Relief Request: R-11 Valves: 1FW-307, 319, 313

'2 Category. 'B Class.

Function'Feedwater Isolation Valve Bypass Isolation Test Requirement: Exercise valve for operability, observe proper operation of fail-safe mechanism, and measure stroke time quaterly.

Basis for Relief: Feedwater system control interlocks prevent opening these valves during normal operation above approximately 15 percent power. When operating below 15 percent power, cycling these valves could result in feedwater flow control instability.

Alternate Test: Exercise valve for operability, observe proper operation of fail-safe mechanism, and measure stroke time during cold shutdown. Partial stroking is precluded by valve design.

ISI-203-Rev. 0 Page 124 o f 148

OS1 Relief Request: R-12 Valves: 1RH-1, 2, 39, 40 Category: A Class: 1 Function: RHR Suction from RCS Hot Legs Isolation Test Requirement: Exercise valve for operability and measure stroke time quarterly.

Basis for Relief: These valves are equipped with protective interlocks to prevent them from being opened during normal operation. This would result in a loss of reactor coolant and overpressurization of the RHR system.

H Alternate Test: Exercise valve for operability and measure stroke time during cold shutdown.

ISI-203-Rev. 0 Page 125 o f 148

OS1 Relief Request: R-13 Valves'1CC-211, 215, 216, 226, 227, 237, 238 Category'. C Class'2, 3 Function.'Component Cooling Mater Check Valves Test Requirement: Demonstrate operability by performing a backseat test quarterly.

Basis for Relief: Cooling water cannot be interrupted to the RCP's during normal operation nor at cold shutdown, since one or more RCP may be running during cold shutdown. In addition, due to system design, six of these valves can only be tested in pairs as follows'1CC-215 & 216, 1CC-266 6 277, 1CC-237 6 238.

Alternate Test: Demonstrate operability by performing a backseat test at refueling.

ISI-203-Rev. 0 Page 126 of 148

,A OS1 Relief Request: R-14 Valves: 1S1-249, 250, 251, 252, 253, 254 Category: A/C Class: 1 Function: Accumulator Check Valves Test Requirement: Demonstrate operability by performing a forward flow test quarterly.

Basis for Relief: The pressure differential across these valves during normal operation prevents them from being tested quarterly.

Alternate Test: Demonstrate operability by performing a forward flow test at cold shutdown.

ISI-203-Rev. 0 Page 127 of 148

I OS1 Relief Request: R-15 Valves: 1RC-900, -901, "902, -903, -904, -905 Category.'

Class: 2 Function: RCS Vent Valves Test Requirement: Exercise valve for operability, observe proper operation of fail-safe actuators, an/ measure stroke time quarterly.

Basis for Relief: Testing these valves during operation could cause an uncontrolled loss of reactor coolant if one of the valves were to leak or fail to reclose. For added safety, these valves will be tested at cold shutdown.

Alternate Test: Exercise valve for operability, observe proper operation of fail-safe actuators, and measure stroke time at cold shutdown.

ISI-203-Rev. 0 Page 128 of 148

OS1 Relief Request:

Valves.'All valvesR-16tested at cold shutdown Category: A, B, C or A/C CLass: 1, 2; or 3 Function: Various Test Requirement: Test all valves with cold shutdown test frequencies at each cold shutdown unless it has been less than three months since the last cold shutdown test.

Basis for Relief: Testing all valves with cold shutdown would have a severe impact on plant availability.

Substantial generating capacity would be lost in those instances where only a brief shutdown is necessary for minor repairs'perational readiness of these valves is maintained, and the impact on plant availability is minimized by allowing the first 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> of a cold shutdown to pass before valve testing is commenced. In addition, once the conditions have been established for plant heatup, valve testing will stop and plant heatup will proceed. This prevents the plant from being held in cold shutdown for valve testing alone.

Alternate Test: Test all valves with cold shutdown test frequencies at each cold shutdown unless: (1) it has been less than three months since the last cold shutdown test, or (2) the cold shutdown has lasted for less than 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />, or (3) valve testing is the only thing preventing going above cold shutdown.

ISI-203-Rev. 0 Page 129 of 148

Os 1 Relief Request: R-17 Valves.'RC-114, 116, 118 Category: B Class: 1 Function Pressurizer Power Operated Relief Valves Test Requirement: Exercise valve for operability, demonstrate proper operation of fail-safe actuators, and measure stroke time quarterly.

Basis for Relief: Cycling these valves during normal operation would increase the possibility of a self-imposed plant transient. An uncontrolled loss of reactor coolant could result if: 1) a PORV were to fail to reseat following a test or 2) a PORV block valve were to fail to provide adequate pressure isolation. The added confidence in valve operability afforded by quarterly testing during normal operation does not justify the increased possibility of a serious self-imposed transi'ent. At cold shutdown, testing is not possible because of Tech Spec requirements to have two PORV's operable for cold overpressure protection.

Alternate Test: Exercise valve for operability, demonstrate proper operation of fail-safe actuators, and measure stroke time at cold shutdown.

ISI-203-Rev. 0 Page 130 of 148

OS1 Relief Request: R-18 Valves.'1CS-344, 385, 426 Category.'

Class: 2 Function Reactor Coolant Pump seal injection check valves Test Requirement: Exercise valve for operability by performing a backseat test quarterly.

Basis for Relief: Performing a backseat test on these valves during normal operation or cold shutdown requires interruption of flow to the reactor coolant pump seals, resulting in possible damage to the seal.s.

Alternate Test: Exercise valve for operability by performing a backseat test at refueling.

ISI-203-Rev. 0 Page 131 of 148

OS1 Relief Request: R-19 Valve'. 1CS-477 Category: C Class: 2 Function: Normal charging line check valve Test Requirement: Exercise valve for operability by performing a backseat test quarterly.

Basis for Relief: A backseat test on this valve requires isolation of normal charging and installation of test equipment. Performance of this test during normal operation would result in the loss of charging flow for an unacceptably long period of time. Also, performance of this test during cold shutdown with the RCS solid .would create RCS pressure control problems.

Alternate Test: Exercise valve for operability by performing a backseat test at refueling.

ISI-203-Rev. 0 Page 132 of 148

OSl Relief Request: R-20 Valve.'1CS-279 Category'. C Class: 2 Function: Emergency boration check valve Test Requirement: Exercise valve for operability by performing a forward flow test quarterly.

Basis for Relief: Verification of boric acid flow through this valve during normal operation would result in an excessive boration of the RCS, and a test at cold shutdown would result in highly concentrated boric acid being injected through the reactor coolant pump seals thus, increasing the possibility of seal failure. This valve will be tested at refueling when the impact on primary system boron concentration and on plant equipment is minimized.

Alternate Test: Exercise valve for operability by performing a forward flow test at refueling.

ISI-203-Rev. 0 Page 133 of 148

OS1 Relief Request: R-21 Valve: 1SW-50 Category: C Class: 3 Function'Check valve in normal service water supply to ESW Test Requirement: Perform a backseat test quarterly.

Basis for Relief: Backseat testing of this valve cannot be performed during normal operation since isolation of normal service water would be required. NSW supplies cooling to various secondary plant components, and without it, a prompt plant shutdown is necessary.

Alternate Test: Perform a backseat test at refueling.

ISI-203-Rev. 0 Page 134 o f 148

OS1 Relief Request: R-22 Valves.'1CC-118, 119, 306, 307 Class. '3 Category:

Function.'CW C

check valves from sample panel and gross failed fuel detector Test Requirement: Demonstrate operability by performing a backseat test quarterly.

Basis for Relief: Due to system design, these valves cannot be individually tested. However, a test of the valves as pairs is adequate to demonstrate their ability to isolate safet'y and non-safety portions of the CCW system. The test will prove that the valves prevent back flow of CCW. If the valves should fail the test, then both valves will receive inspection and if necessary corrective maintenance.

Alternate Test: Demonstrate operability by performing a backseat test of the valves as pairs quarterly.

ISI-203-Rev. 0 Page 135 of 148

t' OS1 Relief Request: R-23 Valves: 1IA-216, 220 Category.'lass:

B, C 2

Function'. Instrument air containment isolation valves Test Requirement: Exercise for operability, demonstrate proper operation of fail-safe actuators, and measure stroke time quarterly for the power operated valve'and demonstrate operability by performing a backseat test quarterly for the check valve.

Basis for Relief: Testing these valves result's in temporary loss of instrument air to containment. Air operated valves inside containment that are not equipped with backup accumulators could not be operated. This would result in a serious self-imposed transient. Adequate assurance that these valves will function properly is maintained by testing at refueling when the impact on plant operation is least.

Alternate Test: Exercise for operability, demonstrate proper operation of fail"safe actuators, and measure stroke time at refueling for the power operated valve, and demonstrate operability by performing a backseat test at refueling for the check valve.

ISI-203-Rev. 0 Page 136 of 148

OS1 Relief Request: R-24 Valves: 1AF-64, 102, 81 Category.'

Class: 2 Function.'Steam generator preheater bypass valves Test Requirement: Exercise valve for operability, demonstrate proper operation of fail-safe actuators, and measure stroke time quarterly.

Basis for Relief: At 100K power, these valves carry 18X of total feedwater flow. Cycling them during operation would result in partial loss of feedwater to the steam generators.

Alternate Test: Exercise valve for operability, demonstrate proper operation of fail-safe actuators, and measure stroke time at cold shutdown.

ISI-203-Rev. 0 Page 137 of 148

Relief Request: R-25 Valves: 1MS-58, 60, 62 Category: B Class: 2 Function: Main steam power operated relief valves Test Requirement: Exercise valve for operability, demonstrate proper operation of fail-safe actuators, and measure stroke time quarterly.

Basis for Relief: Testing these valves during normal operation would cause an increase in secondary system steam demand resulting in a serious self-imposed plant transient.

Alternate Test: Exercise valve for operability, demonstrate proper operation of fail"safe actuators, and measure stroke time at cold shutdown.

ISI-203-Rev. 0 Page 138 of 148

OS1 Relief Request: R-26 Valves'. 1SW-231, 233, 240, 242 Category'. C Class: 2 Function.',Fan coil units normal service water containment isolation valves Test Requirement: Exercise for operability, demonstrate proper operation of fail-safe actuators, and measure stroke time quarterly for the power operated valves; and demonstrate operability by performing a backseat test quarterly for the check valve.

Basis for Relief: Normally all three containment fan coil units are in operation along with a portion of the containment fan coolers to maintain containment temperature below Tech Spec limits. Testing these valves during normal operation would result in loss of cooling water to the fan coil units resulting in reduced cooling capacity.

Not only would the margin to the Tech Spec temperature limit. be reduced, the loss of cooling to areas containing important components, such as RCP's, could lead to their premature failure.

Alternate Test: Exercise for operability, demonstrate proper operation of fail-safe actuators, and measure stroke time at refueling for the power operated valves; and demonstrate operability by performing a backseat test at refueling for the check valve..

ISI-203-Rev. 0 Page 139 of 148

OS1 Relief Request: R-27 Valves: CP-B7, -B8, -B3, -B4 Category.'

Class: 2 Function.'Normal containment purge and pre entry purge isolation valves Test Requirement: Exercise for operability, demonstrate proper operation of fail-safe actuators, and measure stroke time quarterly.

Basis for Relief: These valves are locked closed during normal operation and therefore cannot be tested until cold shutdown.'lternate Test: Exercise for operability, demonstrate proper operation of fail-safe actuators, and measure stroke time at cold shutdown.

ISI-203-Rev. 0 Page 140 of 148

Relief Request: R-28 Valves: 1FW-133, 191, 249, 140, 198, 256 Category: B Class: 3 Function: Main and,bypass feedwater flow control valves Test Requirement: Exercise for operability, demonstrate proper operation of fail-safe actuators, and measure stroke time quarterly.

Basis for Relief: Cycling the main control valves during normal operation would result in a loss of feedwater to the steam generators, causing a reactor trip, and c'ycling the bypass control valves would produce a severe feedwater flow transient also possibly causing a trip.

Alternate Test: Exercise for operability, demonstrate proper operation of fail-safe actuators, and measure stroke time at cold shutdown.

ISI-203-Rev. 0 Page 141 of 148

Relief Request: R-29 Valves'1CC-250, 298 Category. 'C Class: 2 Function.'omponent Cooling Water Check Valves Test Requirement: Demonstrate operability by performing forward flow and backseat tests quarterly.

Basis for Relief: Cooling water cannot be interrupted to the RCP's during normal operation nor at cold shutdown, since one or more RCP's may be running during cold shutdown.

Alternate Test: Demonstrate operability by performing forward flow and backseat tests at refueling.

ISI-203-Rev. 0 Page 142 of 148

OS1 Relief Request: R-30 Valves'1MS-71, -73 Category: C Class: 3 Function.'heck valves in Main Steam supply to AFP turbine Test Requirement: Perform a backseat test quarterly.

Basis for Relief: Backseat testing of these valves requires installation in the main steam tunnel of special test equipment, which during normal operation, presents an undue risk to personnel and plant safety. The possibility of a steam leak 'via test connections exists whenever steam is being supplied to the main steam lines.

Alternate Test: Perform a backseat test at cold shutdown.

ISI-203-Rev. 0 Page 143 of 148

OSL Relief Request: R-31 Valves'1FW-158, -216, -276, 1AF-65, -84, -103 Category. C CLass.'

Function: Feedwater check valves Test Requirement: Perform a backseat test quarterly.

Basis for Relief: Backseat testing of these valves requires reversal of the pressure differential. across the valves. This cannot be accomplished during normal operation since it would result in loss of feedwater to the steam generators.

Alternate Test: Perform a backseat test at cold shutdown.

ISI-203-Rev. 0 Page 144 of 148

OS1 Relief Request: R-32 Valves'. 1SI-8, 9, 10, 81, 82, 83, 104, 105, 106, 136, 137, 138~127~ 128~ 129~ 72~ 73~ 74 Category. 'C Class: 1 Function'Safety Injection check valves Test Requirement: Perform a forward flow test quarterly.

Basis for Relief: Passing flow through these valves during normal-operation would cause RCS injection flow to bypass the regenerative heat exchanger, thereby thermally shocking the RCS piping and causing an overtemperature condition in the letdown line. Testing these valves at cold shutdown with the RCS solid could cause a cold overpressure event.

Alternate Test: Perform a forward flow test at refueling.

ISZ-203-Rev. 0 Page 145 o f 148

+ 1 OS1 Relief Request: R-33 Valves.'1DW-65, 1SA-82, 1FP-357,1FP-349, 1RC-164, 1SI-182,1SI-290 Category: C Class: 2.

Function'Containment isolation check valves Test Requirement: Perform a backseat test quarterly.

Basis for Relief: These valves cannot be tested using system fluid. An entry into containment must be made to perform these tests using temporary test equipment. Quarterly entries would result in personnel radiation exposure that is not in keeping with the plants'LARA program.

Alternate Test: Perform a backseat test at refueling.

ISI-203-Rev. 0 Page 146 of 148

OS1 Relief Request: R-34 Valve: 1CS-493 Category: C Class: 2 Function Normal charging line bypass check valve Test Requirement: Perform a forward flow test quarterly.

Basis for Relief: Positive verification that this valve will pass forward flow can only be made by closing 1CS-492 and verifying flow through the line.

During normal operation this would cause an imbalance in charging and letdown flows resulting higher letdown temperature and possible flashing. During cold shutdown with the RCS solid, primary pressure control would be adversely affected.

Alternate Test: Perform a forward flow test at refueling.

ISI-203-Rev. 0 Page 147 of 148

CHAPTER 1 PURPOSE OF THE PROPOSED FACILITY AND ASSOCIATED TRANSMISSION TABLE OF CONTENTS SECTION TITLE PAGE 1.0 PURPOSE OF THE PROPOSED FACILITY AND ASSOCIATED TRANSMISSION 1.1-1 SYSTEM DEMAND AND RELIABILITY 1 ~ 1-1 1.1.1 LOAD CHARACTERISTICS 1 ~ l-l 1.1.1.1 Load Analysis l. 1-1 1.'1 ~ l. 2 Demand Pro ections 1 ~ 1-2 1.1.1.2.1 Energy Forecast 1.1-2 1.1.1.2.2 Demand Forecast 1.1-3 1 ~ 1 ~ 1.2,3 Load Management a d Conservation 1 ~ 1-3 1.1 ~ 1.3 Power Exchan e 1 ~ 1-5 1.1.2 SYSTEM GAPA TY 1.1-5 RESERVE GINS 1.1-6 EXTERN SUPPORTING STUDIES 1.1-7

1. 2-1 1.3 CONSEQUENCES OF DELAY 1.3-1

SHNPP ER 1.0 PURPOSE OF THE PROPOSED FACILITY AND ASSOCIATED TRANSMISSION 1.1 SYSTEM DEMAND AND RELIABILITY Carolina Power & Light Company (CP&L) is an investor-owned utility serving portions of North and South Carolina. Carolina Power & Light Company provides electric service for a 30,000 square mile area and for approximately 725,000 customers as of December 1979. A general map of the service area is shown in Figure 1.1-1. Other maps are included with Sections 1.1.1.3 and 1.1.2.

In the 1969-1970 time period, CP&L's peak demand forecasts indicated a need for additional capacity of about 800 MW per year for the years 1977 and 1978 to meet projected peaks and to provide an adequate generating reserve. In December of 1970, CP&L's Board of Directors approved construction of the Shearon Harris Nuclear Power Plant (SHNPP) (initially called White Oak) to be placed in service in 1977 and 1978. Subsequently, the plans for SHNPP were revised to include the construction of four units. Due to lower load growth projections, financial considerations, and changing regulatory requirements, the first unit at the SHNPP is now scheduled to begin operation in 1984.

Table 1.1.3-1 shows reserves on the CP&L system with and without the SHNPP.

In January 1974, CP&L was granted an exemption to do certain site preparation and related activities prior to the issuance of a construction permit. The NRC granted CP&L a construction permit for the SHNPP in January 1978.

) 1. 1. 1 Carolina Power LOAD CHARACTERISTICS

& Light Company provides service to a mixture of customer classifications with varying load characteristics. The major customer classifications are Residential, Commercial, Industrial, Sales for Resale (wholesale), Public Street and Highway Lighting, and other Sales to Public Authorities (governmental). This mix of customer load characteristics produces an annual load factor of approximately 60 percent. A representative annual load duration curve is shown on Figure 1.1.1-1.

1.1.1.1 Load Analysis This'section discusses historical and projected peak demands and energy requirements. In Table 1.1.1-1 actual monthly peak demands are listed for January 1972 through March 1980. Actual and projected annual peak demands and increases for the period 1970 through 1993 are tabulated in Table 1 '.1-2.

Figure 1.1.1-2 graphically illustrates historical and forecasted annual peak demands and shows the trend of the historical loads as compared to the current forecast. The decrease in load growth in recent years can be attributed to such things as a downturn in the economy, load management and conservation activities, and the availability of alternative energy sources. These effects have been incorporated into the current load forecast.

Table 1.1.1-3 compares actual peak demands for the period 1969-1979 with the "latest" forecast made for each year.

Table 1.1.1-4 shows total monthly megawatt-hour sales for the period January 1972 through March 1980. Table 1.1.1-5 contains CP&L's annual 1.1-1

SHNPP ER historical and projected system energy requirements for the period 1969 through 1993. These energy figures include total megawatt-hour sales, system losses, CP&L Company usage, and wheeled energy.

l. 1. 1. 2 Demand Projections In the forecasting procedure used by CP&L, the energy forecast serves as a basis for the demand forecast and is therefore described first.

1. l. l. 2. 1 Energy Forecast To develop the forecast of future system energy requirements, data on historical energy usage and anticipated changes in energy requirements are forecast for six classifications of customers (Residential, Commercial, Industrial, Public Street and Highway Lighting, Other Sales to Public Authorities, and Sales for Resale) ~ Predicted energy requirements for these customer classifications are then combined with other energy requirements, such as system losses, Company use, and energy wheeled for delivery from the federal power project (Kerr Dam in Virginia) to Southeastern Power Administration (SEPA) preference customers. The combined energy requirements for these nine energy classifications make up the total system energy requirement. This methodology is limited to the forecast of future energy usage by the six customer classes. Additions for losses, Company use and wheeled energy are included in the methodology for the Company's Load Forecast.

In developing the forecast of energy requirements for each of the sales classifications, consideration is given to many factors which influence customer electric energy requirements. Among these factors are number and type of new customers; availability of other energy forms; indicated customer preference; anticipated levels of market saturation for major energy-using equipment, such as water heaters, electric heat, and air conditioning; the anticipated price of electric energy relative to other energy forms; and conservation and load-management opportunities.

In the current energy forecast, the real price of electricity (nominal price deflated by the consumer price index). is assumed to increase by 1% per year.

The Company reviews and updates its forecast at least annually.

One of the mathematical procedures used in the preparation of the forecasts is a regression analysis. The basic concept behind the regression analysis procedure is that a number of factors influence the amount of electricity that the typical customer in the service area uses. Some of the factors which influence usage are weather, real disposable income of the service area, customer attitude toward conservation, the price of substitute fuels, and structural shifts, such as strikes in a predominant industry, the oil embargo of 1973, or anything which causes a radical change in the customers'ehavior.

In setting up the regression equations, one takes the energy usage for each month and applies the known values of each of these variables for the same month over a period of time These equations are solved simultaneously to get the coefficient or the magnitude of the impact of each one of these variables on the monthly energy usage. The results indicate that the coefficients 1.1-2

SHNPP ER explain the contribution of each of these variables to the total usage for the historical period.

Each of these regressions was initially set up with a number of variables, and coefficients were obtained. The resulting coefficients were analyzed statistically and those which were found to be statistically insignificant, or which were colinear with some other variable, were deleted. They were deleted, not because they were small, but because they might in fact detract from the explanatory value of some of the very significant variables.

In order for the significance to be verified statistically, a number of observations are needed. The observation period should include data which are not uniform but which vary significantly. This way, the impact during the period of observation can be measured for each of the variables; and if the total of these impacts closely tracks the actual usage, then the variables are said to be explanatory. Further statistical tests indicate the amount of the actual usage which is explained over the entire observation period by the variables used.

1~ 1.1.2.2 Demand Forecast The Energy Forecast serves as a basis for the Demand Forecast. Projected annual system load factors are determined for each year of the forecast. The annual system load factors and forecasted system energy requirements determine the forecasted annual peak loads.

Projected annual system load factors are derived by determining the coincident peak load factor for each of the components of the total system energy requirement. The coincident peak load factor for a sales classification is determined by the ratio of the sales classification' average demand during the year to its demand at the time of the annual system peak.

These load factors are called coincident peak load factors (CPLF) because they relate usage at the time of the annual CP&L system peak to the average usage of the particular sales classification. This takes into account the fact that each sales classification peak does not necessarily coincide with the system peak.

Once the coincident peak load factors for each of the six sales classifications plus Company use, SEPA, and system losses have been determined, the coincident demand for the system is calculated by applying these load factors to the proper class and combining the demands. Adjustments are made for certain demand controllers and for municipal peak shaving equipment. The resulting numbers are the system peak load forecasted annual demands.

1.1.1.2.3 Load Management and Conservation Carolina Power & Light Company's load and energy forecasting practices take into account reductions attributed to load management, conservation and alternative energy sources. Carolina Power & Light Company has emphasized conservation and the wise use of electricity for many years with some formal

SHNPP ER activities under way as early as 1970. The Company categorizes its activities in load and energy management in the following primary areas:

a) Load management and conservation through pricing activities; b) Load management and conservation through the control of customer-owned equipment; c) Load management and conservation through customer education, contact, and assistance; and d) Load management through other means.

Carolina Power & Light Company is involved in these load management and conservation activities for all four of its major classes of customers (Residential, Commercial, Industrial, and Sales for Resale).

Under the Residential classification, five programs are involved: Common Sense Program, Wrap-up Program, Heat Pump Program, Consumer Awareness, and Thermal Storage Rates. The Common Sense Program originated in 1977 with the "Common Sense House." A direct result of the "Common Sense House" was-the Wrap-up Program. In 1976, CF&L began to encourage the installation of heat pumps. Thermal storage time-of-day rates were introduced to the CP&L system in March 1979.

The Company is preparing to implement a Residential Electric Water Heater Control Program in Raleigh, North Carolina. The program is voluntary for qualifying residential customers and involves the installation of radio control equipment at the residences. Control sequences will be established to interrupt power to the desired number of water heater loads. Up to 15,000 installations are expected by the end of 1981. The program may be expanded once a full evaluation has been completed.

Under the Commercial classification, each of the above mentioned programs, excluding Water Heater Control are in effect. Demand controllers in commercial buildings have also played a role in reducing CP&L's peak load.

Under the Industrial cl'assification, the system load and energy requirements are affected by five different areas: Interruptible Rates, Heat Pump Program, Customer Contact, Demand Control, and Self-Generation. Carolina Power & Light Company is involved in a program to offer voluntary industrial interruptible rates to its customers. Also CP&L is currently engaged in several cogeneration negotiations which could affect the peak load and energy requirements on the system.

Load management programs, conservation efforts, and generation ventures of wholesale customers are impacting the load growth on the CP&L system. Load management programs are presently under way with new programs being investigated. Wholesale customers also have their consumer education programs to encourage conservation. These load management and conservation efforts are taken into consideration in the sales for resale forecasts.

SHNPP ER Additional load management activities being considered by CP&L include:

Time-of-Use Rates, Appliance Control Projects, Voltage Reduction -Energy Conservation Study, Energy Management Exposition, and Residential Conservation Rate. Also the impact of solar energy and renewable resources on system load and energy requirements are considered in CP&L's load and energy forecasts.

A copy of the report supplied in 1973 to the FPC (now FERC) in accordance with Order 496 is provided as Appendix 1.1A. This report describes the steps undertaken internally. by CP&L to reduce electricity consumption at that time.

Since that time, CP&L has annually updated its General Load Reduction Plan which describes steps undertaken by CP&L during emergency situations to reduce demand on its system to a level which can be safely carried until either the demand diminishes or arrangements can be made for additional sources of power.

The plan includes internal steps taken by CP&L to reduce load at its own facilities as well as those of its customers.

1.1.1.3 Power Exchan es Table 1.1.1-6 shows CP&L net long-term and short-term purchases during the time of the annual summer peak from 1969 through 1979. Table 1.1.1-7 shows the projected net purchases for the period 1980 through 1993 that are under long-tenn contract. The other short-term purchases cannot be predicted at this time; however, unscheduled economical and emergency transactions do occur regularly. Carolina Power & Light Company is interconnected to neighboring utilities with numerous ties as shown in Figure 1.1.1-3.

1.1.2 SYSTEM CAPACITY Carolina Power & Light Company is one of seven members of the Virginia-Carolinas (VACAR) Subregion which is one of four subregions of the Southeastern Electric Reliability Council (SERC). The other subregions of SERG are Florida, Southern Companies, and Tennessee Valley Authority. See Figures 1.1.2-1 through 1.1.2-3 for a geographical description. Other systems comprising VACAR are Duke Power Company, South Carolina Electric & Gas Company, 'South Carolina Public Service Authority, Southeastern Power Administration, Virginia Electric & Power Company, and Yadkin, Inc.

The construction and operation of the SHNPP Units 1, 2, 3, and 4 are essential to the ability of Carolina Power & Light Company to meet its load requirements during the period 1984-1991 and beyond. These units also contribute to adequate reserve situations in both the VACAR Subregion and SERG Region.

Carolina Power & Light Company presently has seven fossil-fired steam electric generating plants with a summer net capability of 3,956 MW, four hydroelectric plants with a net capability of 214 MW, two nuclear plants with a net capability of 2,245 MW, and combustion turbine generating units with a net capability of 1,018 MW, for a total installed summer net capability of 7,433 MW. Table 1.1.2-1 shows CP&L's system capability (summer), including net power available under purchase/sale agreements, for the period 1975-1993 and comparable figures for VACAR for 1975-1993. System capability anticipated for the summer of 1980 is 7,600.5 MW.

1. 1-5

SHNPP ER Table 1.1.2-2 lists the major (100 MW or greater) existing and planned units for the CP6L system, indicating unit location, type (nuclear, fossil, etc.),

capability and function (base load, intermediate, peaking).

In a general sense, Carolina Power & Light Company distinguishes between base load, intermediate load, and peaking capacity based on the amount of time the unit is expected to be used. An economic dispatch procedure is used whereby available units are loaded in order of increasing generation costs to meet customers'emands and then retired in reverse order. This assures CP&L of meeting its customers'eeds in the most economical manner possible. When this method is used, however, the amount of generation that is required from any given unit is tied directly to its cost of operation, load characteristics, and system conditions. With delivered fuel costs varying monthly, load characteristics changing seasonally, and system conditions changing daily, it becomes difficult to state categorically that a given unit will always be base loaded or will be cycled as intermediate or peaking capacity. -The exceptions to this are nuclear (base load) and combustion turbine or hydroelectric units which are energy limited (peaking capacity) ~

When a new unit becomes commercial, it will be used in accordance with economic dispatch procedures and its effect on the use of other units on the system will be determined by the variables mentioned above.

Table 1.1.2-3 lists all existing and planned generating units for the VACAR Subregion, and includes a key to the symbols used throughout the table'apacity factors on the CP6L system are expected to range from 50-70 percent for base loaded units, from 20-50 percent for intermediate units, and below 20 percent for peaking units.

1o 1 ~ 3 RESERVE MARGINS Generating capacity additions are planned to maintain a system reserve level of 20 percent or greater. Carolina Power & Light Company feels, based on historical experience and judgment, that this level of reserves is necessary to maintain reliable service to its customers during system peak periods.

This reserve level is supported by the North Carolina Utilities Commission in its December 1978 Report (see Section 1.1.4). The 20 percent minimum reserve criteria allows for miscellaneous generating plant curtailments and forced outages Major planned outages are scheduled to the extent possible when they will least impact the CP&L power system from an economic and reliability standpoint. Normally, major maintenance is planned for the spring and fall periods when the loads are somewhat less (and therefore resources are greater) than the summer and winter peak load periods. Studies are conducted and scheduling of generating units for major maintenance is normally done a year in advance.

Although VACAR has no established reserve criteria, the outage schedule is then reviewed with the other VACAR systems to assure that the overall maintenance planning within the VACAR Subregion meets sound reliability considerations.

1 ~ 1-6

SHNPP ER Carolina Power & Light Company currently has" installed 1018 HW of oil"fired IC turbine (peaking) capacity which comprises a large part of its reserves. Due to the uncertainty of future oil supplies for operation of these ICs, the reserves as shown in Table 1.1.3-1 including IC's may be overstated.

Therefore, included in this table are reserves without IC's.

Postponing the SHNPP indefinitely would result in firm power resources approximately 12 percent less than the proJected peak demand in 1991. When completed the SHNPP will constitute 27 percent of CP&L's generating capability. In terms of actual electrical energy production, SHNPP is even more significant than its relative size would indicate. As a base load plant, it will be operating at a higher capacity factor than the average plant for the generating system.

1~ 1. 4 EXTERNAL SUPPORTING STUDIES In December 1978, the North Carolina Utilities Commission issued a report entitled, "Future Electricity Needs for North Carolina: Load Forecast and Capacity Plan." This report covered generation requirements as seen by the Commission for North Carolina, for the period 1978-1992.

The following statement concerning reserve margins deemed necessary by the Commission for reliable and adequate service is taken from the above mentioned report.

"The generating reserves needed to ensure system reliability for ~ . ~ CP&L . . . are 20% for both the summer and winter peak seasons."

Carolina Power & Light Company's current reserve planning criteria calls for a minimum reserve margin of.20 percent of the forecast peak. The SHNPP is included in the current construction schedule which satisfies these reserve requirements.

1. 1-7

SHNPP ER TABLE 1 ~ 1 ~ 1-1.

CAROLINA POWER h LIGHT COMPANY MONTHLY PEAK DEMAND (MW) 1972 1973 1974 1975 1976 1977 1978 1979 1980 January 3,625 3,957 4, 019 4, 197 4,968 5,509 5,476 5,588 5,295 February 3,505 3,884 4,219 4,054 4,381 5, 002 5, 605 5,436 5,809 March 3$ 250 3$ 564 3,924 -4, 171 4,162 4,206 4,762 4,817 5$ 226 April 3$ 073 3,413 3,713 3,631 3,681 3,723 3,958 3,872 May 2>994 3,621 3,883 4,243 3,765 .4, 262 4,487 4,299 June 3,602 4,059 4,479 4,537 4,542 5,060 5,379 4,713 July 4,090 4$ 448 4,695 4,759 5,121 5,597 5,398 5,489 August 4,119 4,711 4,771 5>060 4,923 5,381 5,538 5,907 Spetember 3,829 4,404 4,440 4,774 4,465 4,994 5,315 5,141 October 3,442 3,943 3,960 3,677 4,484 4$ 216 4$ 089 4,352 November 3$ 612 3,759 4,097 4,055 4,712 4,511 4,276 4,925 December - 3)851 4,129 4,261 4,761 4,974 5,048 5$ 148 5,330 NOTE: Monthly load forecasts not made.

1. 1-8

SHNPF ER TABLE )el ~ )-2 ANNUAL PEAK DEMANDS AND lNCREASES Peak Loads(<) increase Year MW 1970 3484 313 9.9 1971 3625 141 4.0 1972 4119 494 13.6 1973 4711 592 ~ 14.4 1974 Actual 4771 60 1.3 1975 5060 289 6.1 1976 5509 449 8.9 1977 5605 96 1.7 1778 5588 -17 -0.3 1979 5907 319 5.7 1980 6047 140 2.4 198) 6354 307 5~ 1 1982 6681 327 5.1 1983 7007 326 4.9 1984 7366 359 5~ 1 1985 7738 372 5.1 1986 8102 364 4.7 1987 Projected 8476 374 4.6 1988 8841 365 4.3 1989 9204 363 4.1 1990 9543 339 3.7 1991 9889 346 3.6 1992 )0235 346 3.5 1993 10601 366 3.6 Winter peaks are forecast to be equal to previous summer peaks from 1979 through 1993 because the forecasted winter peak loads developed using winter coincident peak load factors were not significantly different from the forecasted summer peak loads using summer coincident peak load factors

SHNPP ER TABLE 1 i 1. 1-3.

CAROLINA POMER & LIGHT COMPANY COMPARISON OF ACTUAL VERSUS FORECAST SUMMER PEAK DEMANDS 1969 - 1979 Forecast Deviation of Date of Actual Forecast From Actual Year Forecast NW 1969 3043 3-69 3055 {12) 0.4 1970 3415 11-69 3484 (69) (2 0) 1971 3818 10-70 3625 193 5.3 1972 4279 7-71 4119 160 3.9 1973 4679 5-73 4711 (32) (0 7) 1974 5019 6-74 4771 248 5.2 1975 5001 3-75 5060 (59) (1. 2) 1976 5396 10-75 5121 275 5.4 1977 5548 9-76 5597 (49) (0. 9) 1978 5829 11-77 5538 291 5.3 1979 5958 4-79 5907 51 0.9

( ) Indicates actual peak demand was greater than forecast.

1. 1-10

TABLE 1 ~ 1 ~ 1-4 CAROLINA POWER & LIGHT COMPANY TOTAL MONTHLY MWH SALES JANUARY 1972 TO MARCH 1980 1972 1973 1974 1975 1976 1977 1978 1979 1980 January 1,821,607 2,099>287 2,105,158 2,147,374 2,403,591 2,552>304 2,529,948 2,535,057 2,587,378 February 1,834,445 2,029,895 1,922,033 1,934,972 2>284,465 2,509,095 2,578,992 2,712>451 2,721,050 March 1,794,395 1,925,731 1,886,634 1>838>300 2,044,910 2,122,712 2>597,806 2,547,090 2,654,803 April 1,651,914 1.811,210 1,851,196 15795,648 1,952,975 2,042,613 2,067>153 2,145,366 May 1,687>064 1>798,730 1,863,918 1>706,099 1,941,072 1,891,199 1,904,501 2,069,850 June 1,804,578 1,903,803 2,015,178 1,986,011 2,002,664 2>097,612 2,249,162 2,204,248 Jul.y 2>070,159 2,087,914 2>087>914 2,061>709 2,205,428 2,437,036 2,372,945 2>303>168 August 2,166,608 2,224,426 2,224,426 2,256,492 2,404>147 2,616 775 2,577>482 2,731,624 September 1,854,763 2,227,359 2,227>359 2,364,746 2,330,480 2,637,450 2,647,179 2,673,848 October 1,886>011 1,935,757 1,935,756 1,983,489 2,098,409 2,245,809 2,229,911 2,273,478 November 1,827,603 1,913,406 1>913,406 1,973,616 2,124,793 1>997>321 2,034,806 2,222,334 December 1,889,656 1,947,568 2,043,469 2,069,777 2>383>444 2,166>799 2,203,686 2,249,367 Total 22,101,472 24,081,319 24,076,446 24,118,233 26,176,379 27,316,727 27,933,572 28,667,879 Note: Monthly energy forecasts not made.

SHNPP ER TABLE le le 1-5'AROLINA POWER & LIGHT COMPANY HISTORICAL & PROJECTED ENERGY REQUIREMENTS System Energy Requirements Year (MwH) 1969 16,913,764 1970 18,616,630 1971 20,277$ 463 1972 22$ 329,076 1973 24,881,983 Actual 1974 25,303,452 1975 25,906,928 1976 27,577,168 1977 29,025,737 1978 29,849$ 721 1979 30,450,325 1980 31,598,000 1981 33,042,000 1982 34,647,000 1983 36$ 283,000 1984 38,072,000 1985 39,933,000 1986 41$ 801,000 Projected 1987 43,641,000 1988 45,484,000 1989 47,330,000 1990 49,129,000 1991 50$ 940,000 1992 52$ 803,000 1993 54,726,000

SHNPP ER TABLE 1 ~ 1.1-6.

CAROLINA POWER 6 LIGHT COMPANY NET PURCHASES AND SALES AT TIME OF ANNUAL SUMMER PEAK DEMAND 1969 1979 Net Long-Term Net Short-Term Year Purchase & (Sale) {MV) Purchase 6 {Sale) {MW) 1969 212 (109) 197,0 212 174 1971 213 (358) 1972 213 (288) 1973 228 (133) 1974 228 (108) 1975 228 (160) 1976 228 (145) 1977 128 40 1978 128 40 1979 128 40 1 ~ 1-13

0 SHNPP ER TABLE lolol-7 CAROLINA POWER & LIGHT COHPANY NET FIRM PURCHASES AND SALES 1980 1993 Net Purckases & Sales Year (m) 1980 167.5 1981 135. 0 1982 135. 0 1983 135. 0 1984 135.0 1985 135.0 1986 135.0 1987 135.0 1988 135.0 1989 135.0 1990 135. 0 1991 135. 0 1992 135. 0 1993 135. 0

1. 1-14

SHaIP P ER TABLE 1 ~ 1 ~ 2-1 SYSTEM CAPABILITIES {iMW)

CPSL & VACAR Year CP6L VACAR 1975 5,781 ' 31,332 1976 6,620.5 32,269 1977 7,495.5 33,267 1978 7,495.5 34,451 1979 7,495.5 36,003 1980 7,600.5 35,761 1981 8;288 38>861 1982 8>288 40,041 1983 9,008 40,761 1984 9>908 44,346 1985 10,628 46>445 1986 10,628 46$ 510 1987 11,528 48,267 1988 11>528 49,996 1989 12,428 51)756 1990 125428 54,317 1991 13,328 56>767 1992 13,328 59,047 1993 13,328 61>353 1 ~ 1-15

SHNPP ER TABLE 1.1 '-2 CP6L GENERATING UNITS 100 HW OR GREATER Date Plant Unit Tyye Capability .'tW Function Present Br unswick Nuclear 790 Base Load Present Br un swic k Nuclear 790 Base Boad Present Robinson Nuclear 665 Base Load Present Roxboro Fossil 7201 Base/Intermediate Load Present Roxboro Fossil 670 Base/Intermediate Load Present Roxboro Fossil 385 Intermediate Load Present Lee Fossil 252 Intermediate Load Present Asheville Fossil 198 Intermediate Load Present Asheville Fo ssil 194 Intermediate Load Present Cape Fear Fossil 143 Intermediate Load Present Cape Fear fo ssil 173 Intermediate Load Present Sutton Fossil 106 Intermediate Load Present Sutton Fossil 4202 In termed ia te Load Present Robinson Fossil 174 Intermediate Load Fall 198U Roxboro Fossil 720 Base/In termed iate Load Spring 1983 tokyo Fossil 720 Base/Intermediate Load Spring 1984 SHNPP Nuclear 900 Base Load Spring 1987 SHNPP nuclear 900 Base Load Spring 1985 Hayo Fossil 720 Base/Intermediate Load Spring 1989 SHNPP Nuclear 900 Base Load Spring 1991 SHNPP nuclear 900 Base Load Includes an uprate of 7U HW scheduled for the summer of 1980.

Includes an uprate of 35 ttW scheduled for the summer of 1980.

1 ~ 1-16

SHNPP ER TABLE 1 ' '-1 CP&L POWER RESOURCES, LOAD, AND RESERVES WITH AND WITHOUT SHNPP 1984-1991 (SU~i R)

WITH SHNPP ON SCHEDULE 1984 1985 1986 1987 1988 1989 1990 1991 Resources (MW) 9908 10628 10628 11528 11528 12428 12428 13328 Load (MW) 7366 7738 8102 8476 8841 9204 9543 9889 Reserve (MW) 2542 2890 2526 3052 2687 3224 2885 3439 Reserve (%) 34.5 37.3 31.2 36.0 30. 4 35.0 30.2 34.8 W/0 IC* Reserve (%) 20. 7 24. 2 18. 6 24. 0 18. 9 24.0 19.6 24.5 WITHOUT SHNPP 1984 1985 1986 1987 1988 1989 1990 1991 Resources (MW) 9008 9728 9728 9728 9728 9728 9728 9728 Load (MW) 7366 7738 8102 8476 8841 9204 9543 9889 Reserve (MW) 1642 1990 1626 1252 887 524 185 -161 Reserve (%) 22.3 25.7 20.1 14.8 10.0 5. 7 1.9 -1.6 W/0 IC* Reserve (%) 8.5 12 6 7.5 2. 8 -1 5 -5.4 -8.7 -11 '

• IC turbines rated at 1018 MW.

1. 1-39

z( 0 C p O ln Zl Q CD rZ mm m l. A mO 10,000 oo OZ 00 0 CCD H Z

~ n m I p po 3 0 XI po m u ~0 CD

+ CCl z ~~

4 I-1,000 m

O LEGEND:

O

~ ACTUAL m

O ~ ~ p PROJECTED TREND

~~

100 32 34 36 38 42 44 46 48 52 54 56 58 62 64 66 68 72 74 76 78 82 84 86 88 1930 1940 1950 1960 1970 1980 ll YEAR 9

ill

SHNPP ER 1 ~ 3 CONSE UENCES OF DELAY The impact of delays in the operation of the SHNPP units beyond the current schedule would be serious to CP&L and its customers. The impact would be significant economic penalties and reduced reliability. Tables 1.3-1 and 1.3-2 show reserve margins for the CP&L system and the VACAR Subregion with delays of one, t~e, and three years of the SHNPP units, and for postponing the project indefinitely.

In the Spring of 1979, CP&L made a study of the cost of deferring SHNPP Unit 1

'oy one year. This study indicated that for the SMNPP Unit 1> 41 percent of the Unit's budget would have been spent by the end of 1979. A one-year delay would increase construction costs by 11 percent. In addition, increased production costs for a one-year delay would total approximately $ 57,000,000.

As indicated in Section 1.1.3, delay of the project will place CP&L in a position where reserves will be inadequate for reliable service in several yeax s. 'his is of particulax sign'icance because CP&L and neighboring utilities with which CP&L is interconnected are in similar situations with respect to the prospects of importing large quantities of power. Each utility is confronted with long lead times for construction of generating facilities and the uncertainties of maintaining construction schedules. None of these other companies are installing extra generating capacity in quantities required to allow the selling of power to CP&L on a firm basis in the amounts required if the SMNPP units are not brought into operation in the years 1984-1991 as scheduled. Sufficient transmission interconnection capacity for interchanges of large blocks of power between CP&L and its neighboxs is planned under the VACAR agreement for the primary purpose of providing emergency assistance in the event of equipment failure.

1. 3-1

SHNPP ER TABLE 1.3-1 CP&L RESOURCES LOAD & RESERVES Delay 1 year all 4 SHNPP units:

W/0 XC*

Year Total Power Resources Load Reserves  % Reserves % Reserves 1984 9008 7366 1642 22. 3 8.5 1985 10628 7738 2890 37. 3 24. 2 1986 10628 8102 2526 31. 2 18. 6 1987 10628 8476 2152 25. 4 13.4 1988 11528 8841 2687 30. 4 18.9 1989 11528 9204 2324 25. 2 14.2 1990 12428. 9543 2885 30.2 19.6 1991 12428 9889 2539 25.7 15.4 1992 13328 10235 3093 30.2 20.3 Delay 2 years all 4 SHNPP units:

W/0 ZC*

Year Total Power Resources Load Reserves  % Reserves % Reserves Oo 1984 9008 7366 1642 22. 3 8.5 1985 9728 7738 1990 25.7 12. 6 1986 10628 8102 2526 31.2 18. 6 1987 10628 8476 2152 25.4 13. 4 1988 10628 8841 1787 20. 2 8.7 1989 11528 9204 2324 25. 2 14. 2 1990 11528 9543 1985 20. 8 10. 1 1991 12428 9889 2539 25.7 15.4 1992 12428 10235 2193 21.4 11. 5 1993 13328 10601 2727 25.7 16. 1

• IC turbines rated at 1018 %l

1. 3-2

SHNPP ER TABLE 1 3-1 (CONT'D)

Delay 3 years all 4 SHNPP units:

W/0 XC*

Year Total Power Resources Load Reserves % Reserves % Reserves 1984 9008 7366 1642 22. 3 8.5 1985 9728 7738 1990 25.7 12. 6 1986 9728 8102 1626 20. 1 7.5 1987 10628 8476 2152 25.4 13.4 1988 10628 8841 1787 20.2 8.7 1989 10628 9204 1424 15.5 4.4 1990 11528 9543 1985 20.8 10.1 1991 11528 9889 1639 16.6 6.3 1992 12428 10235 2193 21.4 11.5 1993 12428 10601 1827 17. 2 7.6 1994 13328 10971 2357 21. 5 12. 2 Indefinitely Postpone all 4 SHNPP units:

W/0 ZC~

Year Total Power Resources Load Reserves % Reserves % Reserves 1984 9008 7366 1642 22. 3 8.5 1985 9728 7738 1990 25.7 12. 6 1986 9728 8102 1626 20. 1 7.5 1987 9728 8476 1252 14. 8 2.8 1988 9728 8841 887 10. 0 -1.5 1989 9728 9204 524 5.7 -5.4

)990 9728 9543 185 1 ~ 9 -8. 7 1991 9889 -161 -l. 6 -11 '

lc turbines rated at 1018 NN

1. 3-3

SHNPP ER TABLE 1.3-2 VACAR RESOURCES LOAD & RESERVES Delay 1 year all 4 SHNPP units:

Year Total Power Resources Load Reserves  % Reserves 1984 43746 34904 '8842 25. 3 1985 46745 36531 10214 ,28.0 1986 46510 38149 8361 21.9 1987 47367 39869 7498 18.8 1988 49996 41635 8361 20. 1 1989 50856 43433 7423 17. 1 1990 54317 45895 8422 18. 4 1991 55867 47840 8027 16. 8 1992 59047 49849 9198 18.5 Delay 2 years all 4 SHNPP units:

Year Total Power Resources Load Reserves  % Reserves 1984 43746 34904 8842 25.3 1985 45845 36531 9314 25.5 1986 46510 38149 8361 21.9 1987 47367 39869 7498 18.8 1988 49096 41635 7461 17.9 1989 50856 43433 7423 17. 1 1990 53417 45895 7522 16.4 1991 55867 47840 8027 16.8 1992 58147 49849 8298 16.6 1993 61353 51953 9400 18. 1 Note: As of 1980, approximately 19% of VACAR resources were composed of oil-fired capacity.

1 ~ 3-4

e SHNPP ER TABLE 1.3-2 (CONT'D)

Delay 3 years all 4 SHNPP units:

Year Total Power Resources load Reserves % Reserves 1984 43746 34904 8842 25. 3 1985 45845 36531 9314 25. 5 1986 45610 38149 7461 19. 6 1987 47367 39869 7498 18. 8 1988 49096 41635 7461 17. 9 1989 49956 43433 6523 15. 0 1990 53417 45895 7522 16. 4 1991 54967 47840 7127 14.9 1992 58147 49849 8298 16.6 1993 60453 51953 8500 16.4 1994 63931 54120 9811 18. 1 Indefinitely Postpone all 4 SHNPP units:

Year Total Power, Resources Load Reserves % Reserves 1984 43746 34904 8842 25. 3 1985 45845 36531 9314 25. 5 1986 45610 38149 7461 19. 6 1987 46467 39869 6598 16.5 1988 48196 41635 6561 15.8 1989 49056 43433 5623 12. 9 1990 51617 45895 5722 12. 5 1991 53167 47840 5327 ll ~ 1

1. 3-5

ENVIRONMENTAL REPORT OPERATING LICENSE STAGE CHAPTER 2 LIST OF TABLES (Cont'd)

TABLE TITLE PAGE 2.3.5-2 SHNPP ONSITE EXTREME RAINFALL RATES 203 25 2.3.5-3 PRECIPITATION FREQUENCIES AND AMOUNTS (1951 1960: January, April, July, October) 2.3-26 2.3.5-4 SHNPP HOURLY PRECIPITATION OCCURRENCE 2 ~ 3 27 2.3.6-1A JOINT PERCENTAGE FREQUENCIES OF WIND DIRECTION AND SPEED FOR THE PERIOD 4:00 PM 1/14/76 TO 11:00 PM 12/31/78 2. 3-28 2 ' '-1B JOINT PERCENTAGE FREQUENCIES OF WIND DIRECTION AND SPEED FOR THE PERIOD 4:00 PM 1/14/76 TO 11:00 PM 12/31/78 2.3-29 2.3.6-1C JOINT PERCENTAGE FREQUENCIES OF WIND DIRECTION AND SPEED FOR THE PERIOD 4:00 PM 1/14/76 TO 11:00 PM 12/31/78 2. 3-30 2 '.6-1D JOINT PERCENTAGE FREQUENCIES OF WIND DIRECTION AND SPEED FOR THE PERIOD 4:00 PM 1/14/76 TO 11:00 PM 12/31/78 2.3-31 2.3.6-1E JOINT PERCENTAGE FREQUENCIES OF WIND DIRECTION AND SPEED FOR THE PERIOD 4:00 PM 1/14/76 TO 11:00 PM 12/31/78 2%3 32 2.3.6-1F JOINT PERCENTAGE FREQUENCIES OF WIND DIRECTION AND SPEED FOR THE PERIOD 4:00 PM 1/14/76 TO 11:00 PM 12/31/78 2%3 33 2.3.6-1G JOINT PERCENTAGE FREQUENCIES OF WIND DIRECTION AND SPEED FOR THE PERIOD 4:00 PM 1/14/76 TO 11:00 PM 12/31/78 2. 3-34 2.3.6-1H JOINT PERCENTAGE FREQUENCIES OF WIND DIRECTION AND SPEED FOR THE PERIOD 4:00 PM 1/14/76 TO 11:00 PM 12/31/78 2 ~ 3 35 2.3.6-1I JOINT PERCENTAGE FREQUENCIES OF WIND DIRECTION AND SPEED FOR THE PERIOD 4:00 PM 1/14/76 TO 11:00 PM 12/31/78 2. 3-36 2.3.6-1J JOINT PERCENTAGE FREQUENCIES OF WIND DIRECTION AND SPEED FOR THE PERIOD 4:00 PM 1/14/76 TO 11:00 PM 12/31/78 2 ~ 3 37

ENVIRORiENTAL REPORT OPERATING LICENSE STAGE CHAPTER 2 LIST OF TABLES (Cont'd)

TITLE PAGE JOINT PERCENTAGE FREQUENCIES OF WIND DIRECTION AND SPEED FOR THE PERIOD 4:00 PM 1/14/76 TO 11:00 PM 12/31/78 2. 3-38 JOINT PERCENTAGE FREQUENCIES OF WIND DIRECTION AND SPEED FOR THE PERIOD 4:00 PM 1/14/76 TO 11:00 PM 12/31/78 2. 3-39 JOINT PERCENTAGE FREQUENCIES OF WIND DIRECTION AND SPEED FOR THE PERIOD 4:00 PM 1/14/76 TO ll:00 PM 12/31/78 2. 3&0 JOINT PERCENTAGE FREQUENCIES OF WIND DIRECTION AND SPEED FOR THE PERIOD 4:00 PM 1/14/76 TO 11:00 PM 12/31/78 2. 3%1 JOINT PERCENTAGE FREQUENCIES OF WIND DIRECTION AND SPEED FOR THE PERIOD 4:00 PM 1/14/76 TO 11:00 PM 12/31/78 2. 3%2 JOINT PERCENTAGE FREQUENCIES OF WIND DIRECTION AND SPEED FOR THE PERIOD 4:00 PM 1/14/76 TO 11:00 PM 12/31/78 2. 3%3 WIND DISTRIBUTION BY PASQVILL STABILITY CLASSES (STAR PROGRAM) 2. 3%4 WIND DISTRIBUTION BY PASQUILL STABILITY CLASSES (STAR PROGRAM) 2. 3&6 WIND DISTRIBUTION BY PASQUILL STABILITY CLASSES (STAR PROGRAM) 2. 3%8 WIND DISTRIBUTION BY PASQUILL STABILITY CLASSES (STAR PROGRAM) 2. 3-50 WIND DISTRIBUTION BY PASQUILL STABILITY CLASSES (STAR PROGRAM) 203 52 WIND DISTRIBUTION BY PASQUILL STABILITY CLASSES (STAR PROGRAM) 2. 3-54 WIND DISTRIBUTION BY PASQUILL STABILITY CLASSES (STAR PROGRAM) 2. 3-56 WIND DIRECTION PERSISTENCE DATA HARRIS ONWITE METEROLOGICAL FACILITY JANUARY 14, 1976 TO DECEMBER 31, 1978 STABILITY CLASS A 2. 3-58 2~Xii

ENVIRORKNTAL REPORT OPERATING LICENSE STAGE CHAPTER 2 LIST OF TABLES (Cont'd)

TABLE TITLE PAGE 2.3.6-3B WIND DIRECTION PERSISTENCE DATA HARRIS ON-SITE METEOROLOGICAL FACILITY JANUARY 14, 1976 TO DECEMBER 31, 1978 STABILITY CLASS B 2.3-59 2.3.6-3C WIND DIRECTION PERSISTENCE DATA HARRIS ON-SITE METEOROLOGICAL FACILITY JANUARY 14, 1976 TO DECEMBER 31, 1978 STABILITY CLASS C 2.3-60 2.3.6-3D WIND DIRECTION PERSISTENCE DATA HARRIS ON-SITE METEOROLOGICAL FACILITY JANUARY 14, 1976 TO DECEMBER 31, 1978 STABILITY CLASS D 2. 3-61 2.3.6-3E WIND DIRECTION PERSISTANCE DATA HARRIS ON-SITE METEOROLOGICAL FACILITY JANUARY 14, 1976 TO DECEMBER 31, 1978 STABILITY CLASS E 2.3-62 2.3.6-3F WIND DIRECTION PERSISTANCE DATA HARRIS ON-SITE METEOROLOGICAL FACILITY JANUARY 14, 1976 TO DECEMBER 31, 1978 STABILITY CLASS F 2.3-63 2.3.6-3G WIND DIRECTION PERSISTANCE DATA HARRIS ON-SITE METEOROLOGICAL FACILITY JANUARY 14, 1976 TO DECEMBER 31, 1978 STABILITY CLASS G 2.3-64 2.3.6-3H WIND DIRECTION PERSISTANCE DATA HARRIS ON-SITE METEOROLOGICAL FACILITY JANUARY 14, 1976 TO DECEMBER 31, 1978

SUMMARY

2. 3-65 2.3.6-3I WIND DIRECTION PERSISTANCE DATA HARRIS ON-SITE METEOROLOGICAL FACILITY JANUARY 14, 1976 TO DECEMBER 31, 1978 STABILITY CLASS A 2. 3-66 2.3.6-3J WIND DIRECTION PERSISTANCE DATA HARRIS ON-SITE METEOROLOGICAL FACILITY JANUARY 14>

1976 TO DECEMBER 31, 1978 STABILITY CLASS B 2.3-67 2.3.6-3K WIND DIRECTION PERSISTANCE DATA HARRIS ON-SITE METEOROLOGICAL FACILITY JANUARY 14, 1976 TO DECEMBER 31, 1978 STABILITY CLASS C 2.3-68 2.3.6-3L WIND DIRECTION PERSISTANCE DATA HARRIS ON-SITE METEOROLOGICAL FACILITY JANUARY 14, 1976 TO DECEMBER 31, 1978 STABILITY CLASS D 2.3-69

ENVIROAKNTAL REPORT OPERATING LICENSE STAGE CHAPTER 2 LIST OF TABLES (Cont'd)

TABLE TITLE PAGE 2.3.6-3M WIND DIRECTION PERSISTANCE DATA HARRIS ON-SITE METEOROLOGICAL FACILITY JANUARY 14, 1976 TO DECEMBER 31, 1978 STABILITY CLASS E 2.3-70 2.3 '-3N WIND DIRECTION PERSISTANCE DATA HARRIS ON-SITE METEOROLOGICAL FACILITY JANUARY 14, 1976 TO DECEMBER 31, 1978 STABILITY CLASS F 2 ~ 3-71 2.3.6-30 WIND DIRECTION PERSISTANCE DATA HARRIS ON-SITE METEOROLOGICAL FACILITY JANUARY 14, 1976 TO DECEMBER 31, 1978 STABILITY CLASS G 2 ~ 3 72 2.3.6-3P WIND DIRECTION PERSISTANCE DATA HARRIS ON-SITE METEOROLOGICAL FACILITY JANUARY 14, 1976 TO DECEMBER 31, 1978

SUMMARY

2 '-73 2.3.6-4 EXTREME WINDS AND PRECIPITATION ASSOCIATED WITH HURRICANES RALEIGH-DURHAM AIRPORT (1950-1978) 2. 3-74 2.4.2-1 ESTIMATED MONTHLY AVERAGE FLOW IN CAPE FEAR RIVER AT BUCKHORN DAM IN CUBIC FEET PER SECOND DRAINAGE AREA 3196 sq. mi. 2.4.2-20 2.4.2-2 MINIMUM FLOW OF THE CAPE FEAR RIVER AT BUCKHORN DAM 2 '.2-22 2.4.2-3 TRIBUTARIES OF CAPE FEAR RIVER BETWEEN RIVER MILES 123 AND 192 2.4.2-23 2.4.2-4 FLOW CHARACTERISTICS AT USGS GAGING STATIONS CAPE FEAR RIVER BASIN 2.4.2-24 2.4.2-5 COMPREHENSIVE PLAN OF DEVELOPMENT OF WATER RESOURCES FOR THE CAPE FEAR RIVER BASIN 2.4.2-25 2.4.2-6 STREAM FLOWS IN CUBIC FEET PER SECOND COINCIDENT CAPE FEAR RIVER AND BUCKHORN CREEK DURING DROUGHT PERIODS 2.4.2-27 2.4.2-7 MAXIMUM FLOOD FLOW OF THE CAPE FEAR RIVER AT BUCKHORN DAM 2.4 '-28 2-x

ENVIRONMENTAL REPORT OPERATING LICENSE STAGE CHAPTER 2 LIST OF TABLES (Cont'd)

TABLE TITLE PAGE

2. 4. 2-8 ESTIMATED MONTHLY AVERAGE FLOWS OF BUCKHORN CREEK IN CUBIC FEET PER SECOND (AVERAGE 1924 1978 88.1 DRAINAGE AREA ~ 79. 5 sq. mi..) 2. 4. 2-29

2. 4. 2-9 COMPARISON OF 110NTHLY AVERAGE FLOW BETWEEN ESTIMATED AND ACTUAL FLOW OF BUCKHORN CREEK (DRAINAGE AREA ~ 74.2 sq mi. AT GAGE STATION) 2. 4. 2-32 2.4. 2-10 CALCULATED MINIMUM FLOWS FOR BUCKHORN CREEK AT THE MAIN DAM 2. 4. 2-34

2. 4. 2-11 RESERVOIR ANALYSIS NORMAL OPERATION ALL FOUR UNITS CRITICAL PERIOD FEBRUARY 1925 FEBRUARY 1 926 2.4. 2-36

2. 4. 2-12 RESERVOIR ANALYSIS - NORMAL OPERATION ALL FOUR UNITS CRITICAL PERIOD MARCH 1933 APRIL 1934 2. 4 ~ 2-37 2.4.2-13 RESERVOIR ANALYSIS NORMAL OPERATION ALL FOUR UNITS CRITICAL PERIOD MAY 1941 - APRIL 1942 2. 4. 2-38

2. 4. 2-14 RESERVOIR ANALYSIS NORMAL OPERATION ALL FOUR UNITS CRITICAL YEAR 1925/26 - WORST MONTHLY EVAPo CONDITION MONTHS OF NOVe 6 DECo 2. 4. 2-39

2. 4. 2-15 NORtiAL OPERATION ALL FOUR UNITS 100 YRo RETURN PERIOD DROUGHT WORST MONTHLY EVAP, CONDITIONS 2.4. 2&2 2.4.2-16 NORMAL OPERATION ALL FOUR UNITS 100 YEAR RETURN PERIOD DROUGHT WORST MONTHLY EVAPo CONDITIONS 2.4. 2&3 2.4. 2-1 7 CAPE FEAR RIVER NBiBER PUMPING DAYS AND MAKEUP VOLUME (BASED ON 25% NAT. FLOW AND 600 CFS RESTRICTION) 2.4. 2&6

2. 4. 2-1 8 MAKEUP PUMPING FROM THE CAPE FEAR RIVER 2. 4. 2&8

2. 4. 2-1 9 AVERAGE EVAPORATION AND PERCOLATION LOSSES 2.4.2%9

2. 4. 2-20 NORMAL MONTHLY METEOROLOGICAL CONDITIONS AT SITE 2. 4. 2-50 2 ~ 4. 2-21 AUXILIARY RESERVOIR OPERATION - LOSS OF ALL OTHER WATER SOURCES SIMULTANEOUS ACCIDENT CONDITION IN ONE UNIT AND NORMAL SHUTDOWN OF THREE UNITS 2. 4. 2-51 2-xi

ENVIR0%KNTAL REPORT OPERATING LICENSE STAGE LIST OF TABLES (Cont'd)

TABLE TITLE PAGE 2.4.2-22 ESTIMATED MAXIMUM FLOOD PEAKS FOR BUCKHORN CREEK AT THE CAPE FEAR RIVER-DISCHARGE AREA = 79.5 SQ. MI~ 2.4. 2-52 2.4.2-23 ESTIMATED AND MEASURED MAXIMUM FLOOD PEAKS FOR BUCKHORN CREEK AT USGS GAGE STATION NEAR CORINTH, N.C. (D.A. 74.2 sq. mi.) 2.4.2-54 2.4.2-24 PROBABLE MAXIMUM PRECIPITATION 2.4.2-55 2.4.2-25 TIME DISTRIBUTION OF PROBABLE MAXIMUM PRECIPITATION 2 '.2-57 2 '.2-26 WAVE RUNUP PAIUQKTERS FOR STRUCTURES PROTECTED BY RIPRAP 2.4.2-59 2.4.2-27 WAVE RUNUP PARAMETERS FOR PLANT ISLAND 2.4.2-60 2.4.3-1

SUMMARY

OF WATER-BEARING PROPERTIES OF MAPPED LITHOLOGIC UNITS IN DURHAM~ NoC ~ AREA 2.4.3-7 2.4.3-2 DATA ON PUBLIC GROUNDWATER SUPPLY SYSTEMS WITHIN 50 MILES OF THE PLANT 2.4.3-8 2.4.3-3 PUBLIC WELLS WITHIN A 10-MILE RADIUS OF THE PLANT (AS REGISTERED WITH N.CD DIVISION OF ENVIRONMENTAL MANAGEMENT) 2.4.3-10 2.4.3-4 LOCATION OF SITE WELLS AND PIEZOMETERS 2.4.3-12 2.4.3-5 ESTIMATED SITE GROUNDWATER USE 2.4.3-13 2.4.3-6 MINIMUM, MAXIMUM, AND MEDIAN CONCENTRATIONS OF CHEMICAL CONSTITUENTS IN GROUNDWATER IN THE DURHAM AND RALEIGH, N.C. AREAS 2.4.3-14 2.4.3-7 CHEMICAL QUALITY OF SITE GROUNDWATER 2.4.3-15 2.4.4-1 PERMEABILITY OF MATERIALS IN PLANT SITE AND AUXILIARYRESERVOIR AREAS BASED ON DOWN-HOLE PRESSURE TESTS 2.4.4-2 2,4.5-1 CAPE FEAR RIVER INDUSTRIAL WATER WITHDRAWALS DOWNSTREAM OF BUCKHORN DAM 2.4. 5-2 2.4.5-2 CAPE FEAR RIVER MUNICIPAL WATER WITHDRAWALS DOWNSTREAM OF BUCKHORN DAM 2.4.5-3

ENVIRORiENTAL REPORT - OPERATLNG LICENSE STAGE CHAPTER 2 LIST OF TABLES (Cont'd)

TABLE TITLE .PAGE

2. 7~ 2-1 AMBIENT NOISE MEASUREMENTS LOCATIONS 20 7-3 Z. 7. 2-2 WEATHER OBSERVATIONS SHNPP AREA 2. 7H

2. 7. 3-1 Al'iBIENT NOISE MEASUREMENTS SHNPP AREA 2. 7-5

ENVIROR1ENTAL REPORT OPERATING LICENSE STAGE CHAPTER 2 LIST OF FIGURES (Cont'd)

'l FIGURE TITLE

2. 3. 8-2 Maximum Elevation Versus Distance from the Center of the Plant

2. 3. 8-3 Maximum Elevation Versus Distance from the Center of the Plant

2. 3. 8-4 Maximum Elevation Versus Distance from the Center of the Plant

2. 3. 8-5 Topographic Features Within a 5+1ile Radius of the Plant

2. 3. 8-b Topographic Features Within a 50+file Radius of the Plant

2. 4. 1-1 Project Site Plan

2. 4. 1-2 Location of Cape Fear River Basin

2. 4 ~ 1-3 Cape Fear River l Basin 2,4. 1% Watersheds in the Vicinity of Site

2. 4. 1-5 Finished Contours and Drainage Pattern

2. 4. l-b Major Surface Water Bodies 5<iile Radius

2. 4. 1-7 Major Surface Water Bodies 25<file Radius

'I 2.4.2-1 Water Bodies Within 50+iile Radius 2.4. 2-2 Cape Fear River'Flow (at Buckhorn Dam) Duration Curve

2. 4. 2-3 Cape Fear River 1Way and 7&onsecutive Days Low Flow (at Buckhorn Dam) Frequency Analysis (LOG Pearson Type III Distribution) 1925-1 978 2.4. 2-4 Cape Fear River (at Buckhorn Dam) Flood Peaks Frequency Analysis (LOG Pearson Type III Distribution) 1924-1978

2. 4. 2-5 Correlation of Monthly Average Flow Between Estimated 6 Actual Flow of Buckhorn..'Creek

2. 4. 2-6 Buckhorn Creek 7Wonsecutive Days Low Flow Frequency Analysis (LOG Pearson Type III Distribution) 1941-1978 Main Reservoir Area and Capacity Curves

SHNPP ER 2.0 THE SITE AND ENVIRONMENTAL INTERFACES 2.1 GEOGRAPHY AND DEMOGRAPHY 2 '.1 SITE LOCATION AND DESCRIPTION 2.1.1.1 Specification of Location The SHNPP site is located in the extreme southwest corner of Wake County, North Carolina, and the southeast corner of Chatham County, North Carolina.

The City of Raleigh, North Carolina, is approximately 16 mi. northeast and the City of Sanford is about 15 mi. southwest.

Carolina Power & Light Company has constructed a dam on Buckhorn Creek about 2.5 mi. north of its confluence with the Cape Fear River. This dam has created an approximately 4000-acre reservoir which will be used for cooling tower makeup requirements. The power block structures are located on the northwest shore of the Main Reservoir about 4.5 mi. north of the Main Dam.

Coordinates of the reactors are:

Unit No. 1 Unit No. 2 Latitude Longitude (North)

(West) 35'8'0" 78'7'2" 35'8'3" 78 57'4" North Carolina (North) 685,444.524 685,716 417 Plane Coordinates (East) 2j013~001 262 2,012,874.476 Universal Transverse (North) 3,945,013.683 3,945,095.767 Mercator Coordinates (East) 6859064 ~ 389 685,024.074 Unit No. 3 Unit No. 4 Latitude Longitude (North)

(West) 35o 78'7I 38t 02" 26" 35'7'9" 78 57'5" North Carolina (North) 685,631.893 685,360.000 Plane Coordinates (East) 2,012,693.215 2,102,820.000 Universal Transverse (North) 3,945,068.890 3 > 944 j 986 ~ 806 Mercator Coordinates (East) 684,969.342 685,009.655 The universal transverse Mercator zone number for the SHNPP is 17.

2.1 ~ 1.2 Site Area A site area map is included as Figure 2.1.1-1 and indicates the site boundary line (which is the same as the station property boundary), the exclusion boundary, and principal transportation routes. Figure 2.1.1-2 details'he exclusion area boundary and identifies principal station structures. There are no industrial, recreational, or residential structures on CP&L property.

However, as discussed in Section 2.1.3, CP&L will cooperate with appropriate State agencies to provide public access for boating, fishing, hunting, and other recreational uses which are not inconsistent with the primary purpose of

2. l. 1-1 Amendment No. l

SHNPP ER the lands and waters. As such, some recreational facilities such as boat ramps and access areas may be located on station property for public use.

Carolina Power & Light Company's Harris Energy & Environmental Center, as in Sections 2.1.2.3 and 2.1.3, is located approximately 2.1 mi. ENE

'iscussed of the plant.

2.1.1.3 Boundaries for Establishing Effluent Release Limits The exclusion area includes approximately 3534 acres (Figure 2,1.1-2) ~ The boundary of this area is used to determine effluent release limits. All effluent release limits meet requirements as specified in 10CFR Part 20.

Airborne effluent release points for each of the four units are indicated in Figure 3.1-5. The liquid effluent release point for the plant (via the cooling tower blowdown discharge line) is identified in Figure 2.4.1-1.

Minimum distance from the center point of the four reactors to the exclusion boundary is 7000 ft. in all directions, with the exceptions of the N (6980 ft.), WNW (6660 ft.), NW (6640 ft.), NNW (6640 ft.), and S (7200 ft.).

2. l. 1-2

SHNPP ER 2~ I~ 2 POPULATXON DISTRXBUTXON Estimates of existing population distribution are based on 1980 census data and were derived by using methods described in the Electric Power Research Institute's Guidelines for Estimating Present and Forecasting Future Population Distributions Surrounding Reactor Sites (Draft of a Standard)

Reference 2.1.2-1 . As a general procedure, calculations of population were made using the smallest geographic unit used by the U. S. Bureau of the Census. Where a Census Bureau geographical unit did not fall entirely into a "standard nuclear site display geographical unit," population of such census unit was distributed proportionately to the standard display units.

2.1.2.1 Population Within Ten Miles Population distribution within a 10-mile radial area of the plant is for the most part considered rural'he exception to this is in Apex, North Carolina 1 (9 mi. NE) where the 1980 population was 2847.

A map showing the 10-mile radial area of the site is presented in Figure 2.1.2-1 Concentric circles have been drawn at distances of 1, 2, 3, 4,

~

5, and 10 miles using the center line of the four reactors as center point.

The circles have ben divided into 22-1/2-degree segments with each segment centered on one of t'e 16 compass points. The 1980 estimates of residential population within each of these areas are presented in Table 2.1.2-1. Also presented are population progections for 1985 {the expected first year of plant operation), for each census decade through the projected plant life, and for the year 2031.

Population projections have been based on population growth patterns and projections as described in Update North Carolina Population Progections (Reference 2.1.2-2). County growth patterns have been assumed to apply evenly throughout each county area.

Age distribution pro)actions for the midpoint of the station life (2M8) are l presented in Table 2.1.2-2. Progections are based on population estimates and progections prepared by the U.S. Bureau of the Census (Reference 2.1.2-3) ~

2.1.2.2 Population Between Zero and Fifty Miles The population within a 50-mile radius of the plant site is marked by concentrations of people in and around Raleigh (16 mi. NE), Durham 50,000 'in (19 mi. N), and Fayetteville (37 mi. S), each having populations greater than other smaller cities and towns have populations greater than 10,000. Away from these population concentrations, there is a rural type

~i population distribution with small towns interspersed through the area. A map showing the 50-mile radial area and identifying ma]or cities and towns is presented as Figure 2.1.2-2. Concentric circles have been drawn at distances of 10, 20, 30, 40, and 50 miles, using the center line of the four reactors as center point. The circles have been divided into 22-1/2-degree segments with each segment centered on one of the 16 compass points. The 1980 estimates of I residential population within each of these areas are presented in Table 2.1.2-3. Also presented are population projections for 1985 (the expected first year of plant operation), for each census decade through the projected plant life, and for the year 2031. Cumulative totals of population

2. 1.2-1 Amendment No. 1

SHNPP ER estimates and.progections are included in Table 2.1.2-4. Pro]ected age distributions for the midpoint of the station life (2008) are presented in Table 2.1.2-5.

Methods used for, determining population, population progections and age distributions were similar to those described in Section 2.1.2.1.

2.1.2.3 Transient Population Recreational land uses which would attract transient concentrations of people within the 50-mile radius of the site are not extensive and are limited to Umstead State Park (20 mi. NE), Raven Rock State Park (13 mi. SSE), Eno River State Park (30 mi. N), and when completed, the New Hope Prospect (3 mi. NNW) and the Falls of the Neuse Prospect (22 mi. NNE). Although the Falls Project has not been completed, it was originally estimated that the project will have an annual attendance of 2,431,000 in 2000 (Reference 2.1.2-4). Figure 2.1.2-3 includes locations of principal recreation areas.

On occasions, there are high concentrations of people at sporting events and at functions at the various universities in the area. The North Carolina State Fair, held during October of each year in Raleigh, attracted 110,925 people during a one-day period in 1981.

Daily transient population concentrations in and around the ma)or industrial areas of the region are a result of commuting patterns of workers.

Approximately 20 mi. NNE of the site, the Research Triangle Park attracts about 19,000 workers daily. In Moncure (7 mi. WSW) approximately 1300 workers are employed; and in Apex (8 mi. NE) industries employ approximately 2200 people. Additionally, the Harris Energy and Environmental Center, located 2.1 mi. ENE of the plant site, employs approximately 150 people and may attract up to 60 additional people for training sessions. The associated Visitors Center currently attracts an average of 63 people daily.

Land use and land use compatibility are discussed in Sections 2.1.4 and 3.1 (respectively) of the SHNPP Construction Permit Environmental Report.

2. l. 2-2 Amendment No. 1

SHNPP ER TABLE 2 ' ~ 2-1 POPULATION ESTIMATES FOR 1980 AND POPULATION PROJECTIONS FOR THE YEARS 1985 TO 2031 BETWEEN ZERO AND TEN MILES OF THE SHNPP 0 TO 1 MILES DIRECTION 1980 1985 1990 2000 2010 2020 2030 2031 N 0 NNE 0 NE 0 ENE 0 E

ESE SE SSE S

SSW SW WSW W

WNtJ NW NNW TOTAL 0 ~

2. l. 2-3 Amendment: No. 1

SHNPP ER TABLE 2.1.2-1 {continued)

POPULATION ESTIMATES FOR 1980 AND POPULATION PROJECTIONS FOR THE YEARS 1985 TO 2031 BETWEEN ZERO AND TEN MILES OP THE SHNPP 1 TO 2 MILES DIRECTION 1980 1985 1990 2000 2010 2020 2030 2031 N

NNE NE ENE E 0 0 0 0 0 0 0 0 ESE 0 0 0 0 0 0 0 0 SE 0 0 0 0 0 0 0 0 SSE 0 0 0 0 0 0 0 0 S 0 0 0 0 0 -

0 0 SSW 0 0 0 0 0 0 0 0 SW 0 0 0 0 0 0 0 0 WSW 0 0 0 0 0 0 0 0 W 0 0 0 0 0 0 0 0 WNW 0 0 0 0 0 0 0 0 NW 0 0 0 0 0 0 0 0 NNW 25 28 32 40 48 56 64 65 TOTAL 25 28 32 40 48 56 64 65

2. l. 2-4 Amendment No. 1

SHNPP ER TABLE 2.1.2-1 (continued)

POPULATION ESTIMATES FOR 1980 AND POPULATION PROJECTIONS FOR THE YEARS 1985 TO 2031 BETWEEN ZERO AND TEN MILES OP THE SHNPP 2 TO 3 MILES DIRECTION 1980 1985 1990 2000 2010 2020 2030 2031 N 30 34 38 47 56 66 76 77 NNE 39 44 50 62 74 87 100 101 NE 47 53 60 74 89 104 119 120 ENE 3 3 4 5 6 7 8 8 E 8 9 10 12 14 16 18 18 ESE . 17 19 . 22 27 32 37 42 43 SE 0 0 0 0 0 0 0 0 SSE 0 0 0 0 0 0 0 0 S 0 0 0 0 0 0 0 0 SSW 0 0 0 0 0 0 0 0 SW 5 5 6 7 8 9 10 10 WSW 0 0 0 0 0 0 0 0 15 16 17 19 21 23 25 25 17 18 19 21 23 25 27 27 20 21 22 24 26 28 30 30 95 105 114 134 155 176 197 200 TOTAL 296 327 362 432 504 578 652 659

2. 1.2<<5 Amendment No. j.

SHNPP ER TABLE 2.1.2-1 (continued)

POPULATION ESTIMATES FOR 1980 AND POPULATION PROJECTIONS FOR THE YEARS 1985 TO 2031 BETWEEN ZERO AND TEN MILES OF THE SHNPP 3 TO 4 MILES DIRECTION 1980 1985 1990 2000 2010 2020 2030 2031 N 38 42 47 57 67 78 89 90 NNE 43 49 55 68 82 96 110 111 NE 43 49 55 68 82 96 110 111 ENE 72 82 92 114 137 160 183 185 E 62 70 80 99 118 138 158 160 ESE 69 78 89 110 132 154 176 178 SE 56 63 71 88 105 123 141 143 SSE 53 60 68 84 100 117 134 136 S 28 30 32 36 40 44 48 48 SSW 26 27 29 32 35 38 41 41 SW 26 27 29 32 35 38 41 41 WSW 26 27 29 32 35 38 41 41 W 26 27 29 32 35 38 41 41 WNW 26 27 29 32 35 38 41 41 NW 26 27 29 32 35 38 41 41 NNW 26 27 29 32 35 38 41 41 TOTAL 646 712 792 948 1108 1272 1436 1449

2. 1.2-6 Amendment No. 1

SHNPP ER TABLE 2.1.2-1 (continued)

POPULATION ESTIMATES FOR 1980 AND POPULATION PROJECTIONS FOR THE YEARS 1985 TO 2031 BETWEEN ZERO AND TEN MILES OF THE SHNPP 4 TO 5 MILES DIRECTION 1980 1985 1990 2000 2010 2020 2030 2031 N 45 50 55 66 77 88 99 100 NNE 55 62 71 88 106 124 142 144 NE 55 62 71 88 106 124 142 )44 ENE 76 86 98 122 146 171 196 ,

199 E 97 110 124. 154 185 216 248 251 ESE 97 110 124 154 185 216 248 251 SE 91 102 115 141 168 195 222 224 SSE 48 51 56 64 72 80 88 88 S 34 36 38 42 46 50 54 54 SSW 34 36 38 42 46 50 54 54 SW WSW 34 34 36 36 38 38 42 42 46 46 50'4 50 54 54 54 34 36 38 42 46 50 54 54 34 36 38 42 46 50 54 54 34 36 38 42 46 50 54 54 34 36 38 42 46 50 54 54 TOTAL 836 921 1018 1213 1413 1614 1817 1833

2. 1.2-7 Amendment No. j.

SHNPP ER TABLE 2.1.2-1 (continued)

POPULATION ESTIMATES FOR 1980 AND POPULATION PROJECTIONS FOR THE YEARS 1985 TO 2031 BETWEEN ZERO AND TEN MILES OF THE SHNPP 5 TO 10 MILES DIRECTION 1980 1985 1990 2000 2010 2020 2030 2031 N 439 477 519 603 689 776 863 871 NNE 863 978 1110 1370 1650 1930 2210 2240 NE 3760 4250 4820 5970 7160 8380 9610 9730 ENE 871 987 1120 1390 1660 1950 2230 2260 E 1490 1690 1920 2380 2850 3330 3820 3870 ESE 2550 2890 3280 4060 4870 5700 6540 6620 SE 764 846 939 1130 1320 1510 1700 1720 SSE 575 623 675 777 881 985 1090 1100 S 515 556 601 690 779 869 959 968 SSW 449 487 529 613 699 786 873 881 SW 600 653 710 827 946 1070 1190 1200 WSW 690 750 816 948 1080 1220 1360 1370 607 646 687 770 853 937 1020 1030 539 570 603 668 733 798 863 869 368 390 411 455 499 543 587 591 340 360 380 421 462 503 544 548 TOTAL 15420 17153 19120 23072 27131 31287 35459 35868

2. 1.2-8 Amendment No. 1

SHNPP ER TABLE 2.1+2-2 AGE DISTRIBUTION FOR THE YEAR 2008 FOR THE AREA BETWEEN ZERO AND TEN MILES OF THE SHNPP 0 TO 1 MILES AGE AGE AGE DIRECTION 0-13 14-18 OVER 18 N 0 0 0 NNE 0 0 0 NE 0 0 0 ENE 0 0 0 0 0 0 ESE 0 0 0 SE 0 0 0 SSE 0 0 0 S 0 0 0 SSW 0 0 0 SW 0 0 0 WSW 0 0 0 W 0 0 0 WNW 0 0 0 NW 0 0 0 NNW 0 0 0'OTAL 0 0

2. l. 2-9 Amendment No. 1

SHNPP ER TABLE 2.1.2-2 (continued)

AGE DISTRIBUTION FOR THE YEAR 2008 FOR THE AREA BETWEEN ZERO AND TEN MILES OF THE SHNPP 1 TO 2 MILES AGE AGE AGE DIRECTION 0-13 14-18 OVER 18 N 0 NNE 0 NE 0 ENE 0 E 0 ESE 0 SE -0 SSE 0 S 0 0

'SW 0 0 SW 0 0, WSW 0 0.

W 0 0 WNW 0 0 NW 0 0 NNW ll 32 TOTAL 32

2. 1. 2-10 Amendment No. 1

SHNPP ER TABLE 2.1.2-2 (continued)

AGE DISTRIBUTION FOR THE YEAR 2008 FOR THE AREA BETWEEN ZERO AND TEN MILES OF THE SHNPP 2 TO 3 MILES AGE AGE AGE DIRECTION 0-13 14-18 OVER 18 N 13 38 NNE 17 50 NE 20 60 ENE 1 4 10 ESE 22 SE 0 SSE 0 S

SSW SW WSW W 5 14 WNW 5 16 NW 6 18 NNW 35 105 TOTAL 114 30 343 2 ~ 1 ~ 2 11 Amendment No. 1

SHNPP ER TABLE 2.1.2-2 (continued)

AGE DISTRIBUTION POR THE= YEAR 2008 POR THE AREA BETWEEN ZERO AND TEN MILES OP THE SHNPP 3 TO 4 MILES AGE AGE AGE DIRECTION 0-13 14-18 OVER 18 N 15 46 NNE 19 55 NE 19 55 ENE 31 93 E 27 80 ESE 30 89 SE 24 71 SSE 23 68 S 27 SSW 24 SW 24 WSW 24 24 24 24 24 TOTAL 253 65 752

2. l. 2-12 Amendment No. 1

SHNPP ER TABLE 2.1.2-2 (continued)

AGE DISTRIBUTION FOR THE YEAR 2008 FOR THE AREA BETWEEN ZERO AND TEN MILES OF THE SHNFF 4 TO 5 MILES AGE AGE AGE DIRECTION 0-13 14-18 OVER 18 N 18 5 53 NNE 24 6 72 NE 24 6 72 ENE 33 9 99 E 42 ll 125 ESE 42 ll 125 SE 38 10 114 SSE 17 4 50 S 11 32 SSW 11 32 SW 11 32 WSW ll 32 W ll 32 WNW 11 32 NW 11 32 NNW ll 32 TOTAL 326 86 966

2. 1.2-13 Amendment No. 1

SHNPP ER TABLE 2.1.2-2 (continued)

AGE DISTRIBUTION FOR THE YEAR 2008 FOR THE AREA BETWEEN ZERO AND TEN MILES OF THE SHNPP 5 TO 10 MILES AGE AGE AGE DIRECTION 0-13 14-18 OVER 18 N 158 42 470 NNE 375 100 1110 NE 1630 435 4840 ENE 378 101 1120 E 649 173 1930 ESE 1110 296 3290 SE 301 80 894 SSE 202 54 601 S 180 48 533 SSW 161 43 477 SW 217 58 646 WSW 249 67 740 W 198 53 587 WNW 170 45 505 NW 116 31 343 NNW 107 29 318 TOTAL 6201 1655 18404 2, 1.2-14 Amendment No. 1'

SHNPP ER TABLE 2+1.2-3 POPULATION ESTIMATES FOR 1980 AND POPULATION'ROJECTIONS FOR THE YEARS 1985 TO 2031 BETWEEN ZERO AND FIFTY MILES OF THE SHNPP 0 TO 10 MILES DIRECTION 1980 1985 1990 2000 2010 2020 2030 2031 N 552 603 659 773 889 1010 1130 1140 NNE 1000 1130 1280 1590 1910 2240 2560 2590 NE 3900 4420 5000 6200 7440 8710 9980 10100 ENE 1020 1160 1310 1630 1950 2280 2620 2650 F 1660 1880 2130 2640 3170 3700 4250 4300 ESE 2740 3100 3510 4350 5220 6110 7000 7090 SE 911 1010 1130 1350 1590 1830 2070 2090 SSE 676 734 799 925 1050 1180 1310 1320 S 577 622 671 768 865 963 1060 1070 SSW 509 550 596 687 780 874 968 976 SW 665 721 783 908 1040 1160 1290 1310 WSW 750 813 883 1020 1170 1310 1460 1470 W 682 725 771 863 955 1050 1140 1150 WNW 616 651 689 763 837 911 985 991 NW 448 474 500 553 606 659 712 716 NNW 520 556 593 669 746 823 900 908 TOTAL 17226 19149 21304 25689 30218 34810 39435 39871

2. 1.2-15 'Amendment No. 1

SHNPP ER TABLE 2.1.2-3 (continued)

POPULATION ESTIMATES FOR 1980 AND POPULATION PROJECTIONS FOR THE YEARS 1985 TO 2031 BETWEEN ZERO AND FIFTY MILES OF THE SHNPP 10 TO 20 MILES DIRECTION 1980 1985 1990 2000 2010 2020 2030 2031 N 17100 18600 20100 23100 26100 29200 32200 32500 NNE 5520 6030 6590 7700 8850 10000 11200 11300 NE 50100 56800 64300 79600 95600 112000 128000 130000 ENE 43400 49200 55700 69100 82900 97000 111000 113000 E- 8430 9550 10800 13400 16100 18800 2)600 21800 ESE 6950 7790 8750 10700 12700 14800 16800 17000 SE 5710 6190 6720 7750 8790, 9840 10900 11000 SSE 5260 5700 6)80 7120 8070 9030 9990 10100 S 2970 3220 3490 4020 4560 5100 5640 5690 SSW 5090 5550 6040 7050 8080 9120 10200 10300 SW 18500 20200 22100 25800 29600 33500 37500 37800 WSW 4060 4410 4790 5550 6340 7140 7940 8020 1990 2100 2220 2460 2700 2940 3180 3210 3640 3850 4070 4510 4950 5400 5840 5880 2950 3120 3300 3660 4020 4380 4750 4780 26500 29600 33200 40200 47200 54300 61400 62100 TOTAL 208170 231910 258350 311720 366560 422550 478140 484480

2. 1.2-16 NSndment No. j.

SHNPP ER TABLE 2.1.2-3 (continued)

POPULATION ESTIMATES FOR 1980 AND POPULATION PROJECTIONS FOR THE YEARS 1985 TO 2031 BETWEEN ZERO AND FIFTY MILES OF THE SHNPP 20 TO 30 MILES DIRECTION 1980 1985 1990 2000 2010 2020 2030 2031 N 92500 99000 106000 120000 133000 147000 160000 162000 NNE 42000 44800 47800 53600 59500 65400 71300 71900 NE 57600 65300 73900 91600 110000 129000 147000 149000 ENE 79900 90600 103000 127000 153000 178000 205000 207000 E 14700 16000 17500 20400 23400 26400 29500 29800 ESE 5810 6170 6550 7300 8050 8810 9560 9630 SE 23300 25200 27200 31200 35200 39300 43300 43700 SSE 9370 10100 10800 12300 13700 15100 16600 16700 S 8950 9670 10400 11900 13500 15000 16500 16700 SSW 4780 5200 5670 6610 7570 8530 9500 9600 SW 5680 6290 6980 8390'280 9850 11300 12900 13000 WSW 3120 3380 3680 4890 5520 6140 6200 4700 4970 5250 5820 6390 6960 7530 7580 3440 3620 3810 4200 4580 4960 5350 5380 5100 5300 5530 5930 6330 6720 7110 7150 17000 19100 21500 26200 30900 35600 40400 40800 TOTAL 377950 414700 455570 536730 619860 703600 787690 796140

2. 1. 2-17 Amendment No. 1

SHNPP ER TABLE 2.1.2-3 (continued)

POPULATION ESTIMATES FOR 1980 AND POPULATION PROJECTIONS FOR THE YEARS 1985 TO 2031 BETWEEN ZERO AND FIFTY MILES OF THE SHNPP 30 TO 40 MILES DIRECTION 1980 1985 1990 2000 2010 2020 2030 2031 N 16900 18200 19700 22500 25400 28200 31100 31400 NNE 14500 15000 15600 16600 17600 18600 19600 19700 NE 13700 15300 17100 20700 24400 28200 32100 32400 ENE 18700 21100 23800 29300 35000 40900 46700 47300 E 11400 12100 12900 14300 15800 17300 18800 18900 ESE 19000 20200 21500 23900 26400 28800 3)300 31600 SE 12300 13200 14100 15900 17800 19600 21500 21700 SSE 14900 15800 16800 18500 20200 21900 23500 23700 S 114000 121000 128000 141000 154000 166000 179000 180000 SSW 3860 4230 4650 5490 6350 7220 8090 8170 SW 12800 14500 16500 20600 24900 29300 33800 34200 WSW 7090 8020 9060 11200 13500 15800 18200 18400 8830 9480 10200 11500 12900 14300 15700 15900 11000 11700 12400 13900 15400 16800 18300 18500 34100 34200 34300 34100 33800 33400 32900 32800 21800 23400 25100 28500 31800 35100 38400 38700 TOTAL 334880 357430 381710 427990 475250 521420 568990 573370 2'. 1.2-18 Amendment No. 1.

SHNPP ER TABLE 2.1.'2-3 (continued)

POPULATION ESTIMATES FOR 1980 AND POPULATION PROJECTIONS FOR THE YEARS 1985 TO 2031 BETWEEN ZERO AND FIFTY MILES OF THE SHNPP 40 TO 50 MILES DIRECTION 1980 1985 1990 2000 2010 2020 2030 2031 N 8410 8910 9440 10500 11500 12600 13700 13800 NNE 8070 8190 8310 8490 8660 8810 8950 8970 NE 13900 14700 15400 16900 18400 19900 21400 21500 ENE 10000 10600 11300 12600 13900 15200 16500 16700 14200 15100 15900 17600 19300 21000 22600 22800 ESE 10200 10800 11500 12800 14000 15300 16600 16700 SE 7070 7410 7760 8460 9170 9870 10600 10600 SSE 12500 13200 13900 15300 16600 17900 19200 19300 S 101000 108000 114000 126000 138000 149000 160000 161000 SSW 12700 14100 15500 18600 21800 25000 28200 28500 SW 20400 23200 26300 32800 39600 46600 53700 54400 WSW 8770 9740 10800 13100 15400 17800 20200 20500 34400 37400 40600 47000 53600 60200 66800 67400 24200 25800 27500 30800 34100 37500 40900 41200 64300 64900 65600 66200 66600 66800 67000 67000 9380 9650 9950 10500 11000 11500 12000 12000 TOTAL 359500 381700 403760 447650 491630 534980 578350 582370

2. 1.2-19 Amendment No. 1

SHNPP ER TABLE 2e1.2-4 CUMULATIVE POPULATION ESTIMATES AND PROJECTIONS BETWEEN ZERO AND FIFTY MILES OF THE SHNPP YEAR 0-1 0-2 0-3 0-4 0-5 0-10 1-20 0-30 0-40 0-50 1980 0 25 321 967 1800 17200 225000 603000 938000 1300000 1985 0 28 355 1070 1990 19200 251000 666000 1020000 1400000 1990 0 32 394 1190 2210 21300 280000 735000 1120000 1520000 2000 0 40 472 1420 2630 25700 337000 873000 1300000 1750000 2010 0 48 552 1660 3070 30200 397000 1020000 1500000 1990000 2020 0 56 634 1910 3520 34800 457000 1160000 1680000 2210000 2030 0 64 716 2150 3970 39400 518000 1310000 1880000 2460000 2031 0 65 724 2170 4000 39900 524000 1320000 1890000 2470000

2. 1.2-20 Amendment No. 1

SHNPP ER TABLE 2.1 2-5 AGE DISTRIBUTION FOR THE YEAR 2008 FOR THE AREA BETWEEN ZERO AND FIFTY MILES OF THE SHNPP 0 TO 10 MILES AGE AGE AGE DIRECTION 0-13 14-18 OVER 18 N 204 54 607 NNE 435 116 1290 NE )690 451 5030 ENE 443 118 1320 E 721 192 2140 ESE l)90 317 3530 SE 363 96 1080 SSE 242 64 719 S 200 53 592 SSW 180 48 533 SW 238 64 708 WSW 268 72 796 222 59 657 194 51 577 141 38 417 172 46 511 TOTAL 6903 1839 20507 2.1.2>>21 Amendment No..l

SHNPP ER TABLE 2.1.2-5 (continued)

AGE DISTRIBUTION FOR THE YEAR 2008 FOR THE AREA BETWEEN ZERO AND FIFTY MILES OF THE SHNPP 10 TO 20 MILES AGE AGE AGE DIRECTION 0-13 14-18 OVER 18 N 6020 1610 17900 NNE 2030 542 6030 NE 21700 5810 64600 ENE 18900 5040 56000 E 3660 976 10900 ESE 2900 774 8610 SE 2020 540 6010 SSE 1860 496 5520 S 1050 280 3120 SSW 1860 495 5510 SW 6810 1820 20200 WSW 1460 389 4330 625 167 1860 1150 306 3410 932 249 2770 10800 2880 32000 TOTAL 83777 22374 248770

2. 1.2-22 Amendment No. 1 '

SHNPP ER TABLE 2.1.2-5 (continued)

AGE DISTRIBUTION FOR THE YEAR 2008 FOR THE AREA BETWEEN ZERO AND FIFTY MILES OF THE SHNPP 20 TO 30 MILES AGE AGE AGE DIRECTION 0-13 14-18 OVER 18 30700 '210 91300 13800 3670 40900 25000 6680 74300 34700 9260 103000 5370 1430 16000 ESE 1860 497 5530 SE 8110 2170 24100 SSE 3160 844 9390 S 3100 828 9220 SSW 1740 464 5160 SW 2250 601 6690 WSW 1120 300 3340 1480 395 4390 1060 283 3150 1470 393 4380 7050 1880 20900 TOTAL 141970 37905 421750

2. 1.2-23 Amendment No. 1

SHNPP ER TABLE 2.1.2-5 (continued)

AGE DISTRIBUTION FOR THE YEAR 2008 FOR THE AREA BETWEEN ZERO AND FIFTY MILES OF THE SHNPP 30 To 40 MILES AGE AGE AGE DIRECTION 0-13 14-18 OVER 18 N 5850 1560 17400 NNE 4110 1100 12200 NE 5580 1490 16600 ENE 7970 2130 23700 E 3660 977 10900 ESE 6100 1630 18100 SE 4110 1100 12200 SSE 4690 1250 13900 S 35700 9540 106000 SSW 1450 388 4320 SW 5660 1510 16800 WSW 3070 820 9130 W 2980 796 8860 WNW 3550 948 10600 NW 7990 2130 23700 NNW 7330 1960 21800 TOTAL 109800 29329 326210

2. 1. 2-24. Amendment No. 1

SHNPP ER TABLE 2.1.2-5 (continued)

AGE DISTRIBUTION FOR THE YEAR 2008 FOR THE AREA BETWEEN ZERO AND FIFTY MILES OF THE SHNPP 40 TO 50 MILES AGE AGE AGE DIRECTION 0-13 14-18 OVER 18 N 2670 713 7940 NNE 2040 543 6050 NE 4270 1140 12700 ENE 3220 859 9560 E 4470 1190 13300 ESE 3250 868 9660 SE 2130 568 6320 SSE 3850 1030 11400 S 31900 8520 94800 SSW 4980 1330 14800 SW 9000 2400 26700 WSW 3520 940 10500 W 12300 3290 36600 WNW 7890 2110 23400 NW 15700 4190 46600 NNW 2570 686 7630 TOTAL 113760 30377 337960

2. 1.2-25 Amendment No. 1

SHNPP ER 2.1.3 USES OF ADJACENT LANDS AND WATERS Figure 2.1.3-1 includes land contours, site boundary, exclusion boundary, CP&L property, area properties, water bodies, and transportation links. There are no settlements, commercial areas, industrial plants, dedicated areas, or valued historic, scenic, cultural, or natural areas on CP&L property.

Total land area owned by CP&L in the plant vicinity is approximately 22,850 ac. Total required site area (station property) is approximately 10,800 ac. Approximately 4000 ac. are utilized by the Main Reservoir, and about 1217 ac. are used for plant related activities.

The Harris Energy & Environmental Center is located approximately 2.1 miles ENE of the plant. The facility houses various CP&L environmental testing and training laboratories and includes a visitors'enter. A Boy Scout camping area is located approximately 3.7 mi. SSE of the site, and a private nursing home is located approximately 2.2 mi. NE.

Table 2.1.3-1 indicates the distances from the center line of the first operational nuclear unit to the nearest milk cow, milk goat, residence, site boundary, vegetable garden and meat animal. Distances are indicated for each of the 16 sectors as described in Section 2.1.2 to a radial distance of 5 mi.

The majority of the 'land within the five-mile radial area is wooded, with a scattering of fields and residential properties (Figure 2.1.3-2). The reservoir l area is now cleared and filling with water. Much of the land is used for timber and pulpwood production. Agricultural development exists on a limited basis, and three dairy farms are in operation. Ma)or commercial and expanded residential development is not expected to occur due to the poor septic characteristics of the soils and the lack of adequate sewage and water systems.

Due to CP&L's land and reservoir use policy, there will be some recreational usage of CP&L's property. Xt is the policy of 'CP&L to make available for the enjoyment of the general public the lands and waters of the SHNPP and reservoir consistent with their primary purpose the generation of electric power. Property in the flood control strip around the .reservoir and plant will not be sold or leased by CP&L for private development. Private construction of piers, docks, moors, boat houses, or similar facilities in or adjacent to the reservoir will not be permitted.

To permit the greatest use by the greatest number of people, the Company will cooperate with appropriate State agencies to provide public access for boating, fishing, hunting, and other uses which are not inconsistent with the primary purpose of the lands and waters. It is the desire of CP&L that the public benefits of the SHNPP reservoir and property shall contribute to the quality of life in the area, in addition to meeting the power needs of all its customers.

Consistent with the provisions of the SHNPP land policy, CP&L will permit the appropriate State agencies to establish wildlife refuge areas ad]acent to the reservoir and a wildlife management program for the Company-owned lands. "The development of a favorable sport fishery in the Main Reservoir is expected to

2. 1.3-1 Amendment No. l

SHNPP ER result from existing Whiteoak and Buckhorn creek populations with some seeding from Cape Pear River makeup water. Operational monitoring programs (Section 6.2) will be conducted.

A majority of the land within a 50-mile radial area of the plant is devoted to some form of agricultural activity. Ma)or crops include tobacco, soybeans, corn for grain and sweet potatoes. Secondary crops include corn for silage, other grain crops and hay. Livestock production includes hog, beef, poultry, and dairy products". Data on annual agricultural, livestock, and poultry production within a 50-mile radius of the plant for sectors as described in Section 2.1.2 are presented in Tables 2.1.3-2 and 2.1.3-3 (Reference 2.1 3-1) ~

Commercial fish and shellfish catch is negligible from waters within 50 mi.

of the station discharge. A small number of American shad, striped bass and blueback herring are harvested seasonally (spring) from the Cape Fear River below Lillington. This number is considered insignificant as compared to North Carolina's commercial fishing harvest. The nearest commercial fishery port is Wilmington, North Carolina, approximately 150 river miles downstream of the site. Commercial catches reported for Wilmington are principally salt water species harvested from the lower Cape Fear River estuary and from the Atlantic Ocean.

Recreational fishing catch within the 50-mile radial area is dominated by sunfish species, largemouth bass, and catfish (Reference 2.1.3-2). The limited number of lakes within the area and the fact that there are no estuarine or salt water bodies principally confines sport fishing to private ponds, impounded areas, and bridge crossings on rivers and streams. Data estimating catch for this type of recreational fishing in North Carolina are not available. However, the small catch which is associated with this fishing would probably not be a principal food source for residents within the 50-mile area.

In addition to the SHNPP reservoir, the development of the Pails of the Neuse Prospect and the New Hope Prospect will create two large reservoirs within 30 mi. of the SHNPP site. Pish species similar to those discussed in Section 5.1.3 are expected to develop in the reservoirs. Each reservoir will provide significant recreational fishing opportunities,-thus increasing the region's recreational fishery harvest.

The cooling tower blowdown pipeline discharges into the Main Reservoir gust north of the Main Dam. Discharges will enter the reservoir via a submerged discharge outfall, and the public will have access to the discharge area.

Although a reasonable sport fishery is expected .to develop in the reservoir, limited fishing success in the area affected by plant discharges is expected.

As discussed in Sections 5.1.3 and 5.3, the thermal and chemical effects of the cooling tower .blowdown are expected to be minimal and to be restricted to a small mixing zone (ranging from, 90 to 200 acres). Pishing success in the mixing zone area, which represents only two to five percent of the reservoir's surface area, is not expected to be as -good as in other parts of the reservoir. For the most part, the anticipated lower fishing success in the mixing zone area will result from the lack of favorable habitat for the expec'ted .important species largemouth 2.1.3-2 Amendment No. 1

SHNPP ER TABLE 2.1.3-2 1980 AGRICULTURAL PRODUCTION OF MAJOR CROPS BETWEEN ZERO AND FIFTY MILES OF THE SHNPP 0 TO 10 MILES SWEET CORN FOR DIRECTION SOYBEANS TOBACCO POTATOES GRAIN N 134000 286000 28600 316000 NNE 288000 708000 82800 316000 NE 288000 708000 82800 316000 ENE 288000 708000 82800 316000 E 288000 708000 82800 316000 ESE 288000 708000 82800 316000 SE 486000 775000 182000 767000 SSE 574000 748000 230000 1020000 S 388000 512000 144000 746000 SSW 181000 319000 24100 287000 SW 180000 306000 21600 284000 WSW 195000 344000 26200 276000 90100 143000 8220 310000 66500 99700 4720 317000 66500 99700 4720 317000 80900 135000 8870 332000 TOTAL 3882000 7307400 1097030 6552000 All data reported in kilograms Basis: Reference 2.1.3-1

2. l. 3-5 Amendment No. 1

SHNPP ER TABLE 2.1.3-2 (continued) 1980 AGRICULTURAL PRODUCTION OF MAJOR CROPS BETWEEN ZERO AND FIFTY MILES OF THE SHNPP 10 TO 20 MILES SWEET CORN FOR DIRECTION SOYBEANS TOBACCO POTATOES GRAIN N 273000 531000 24800 758000 NNE 686000 1690000 182000 771000 NE 837000 2060000 241000 918000 ENE 795000 .1950000 228000 871000 E 917000 2250000 274000 1010000 ESE 1220000 2370000 1290000 2030000 SE 2060000 2480000 856000 3710000 SSE 2140000 2560000 890000 3860000 S 2150000, 2570000 892000 3870000 SSW 1240000 1730000 371000 1850000 SW 770000 1310000 93000 790000 WSW 592000 986000 '6300 849000 173000 224000'" 4440 956000 175000 228000 4500 969000 172000 223000 4590 937000 316000 399000 14400 1200000 TOTAL 14516000 23561000 5436030 25349000 All data reported in kilograms Basis: Reference 2.1.3-1

2. l. 3-6 Amendment No. 1

SHNPP ER TABLE 2.1.3-2 (continued) 1980 AGRICULTURAL PRODUCTION OF MAJOR CROPS BETWEEN ZERO AND FIFTY MILES OF THE SHNPP 20 TO 30 MILES SWEET CORN FOR DIRECTION SOYBEANS TOBACCO POTATOES GRAIN N 636000 1180000 56300 1360000 NNE 654000 1610000 115000 806000 NE 1420000 3490000 408000 1560000 ENE 1440000 3550000 415000 1580000 E 2740000 4600000 5110000 5800000 ESE 3460000 5240000 7570000 8060000 SE 3560000 4410000 2310000 6670000 SSE 3280000 3630000 1280000 5840000 S 3530000 4070000 1420000 6330000 SSW 2900000 3630000 1120000 5050000 SW 823000 1610000 103000 1120000 WSW 540000 1070000 59900 1230000 W 319000 413000 8170 1760000 WNW 332000 437000 8430 1720000 NW 873000 1180000 27300 3100000 NNW 894000 1120000 49100 2670000 TOTAL 27401000 41240000 20060200 54656000 All data reported in kilograms Basis: Reference 2.1 ~ 3-1

2. 1.3-7 Amendment No. l

SHNPP ER TABLE 2.1.3-2 (continued) 1980 AGRICULTURAL PRODUCTION OF MAJOR CROPS BETWEEN ZERO AND FIFTY MILES OF THE SHNPP 30 TO 40 MILES SWEET CORN FOR DIRECTION SOYBEANS TOBACCO , POTATOES GRAIN N 1000000 1690000 79200 2380000 NNE 1190000 3530000 129000 1750000 2060000 4730000 463000 2420000 2380000 5270000 1720000 3300000 E 4720000 7170000 10400000 11000000 ESE 4670000 7090000 10300000 10900000 SE 4930000 5670000 6210000 13900000 SSE 4250000 2100000 1220000 8120000 S 4130000 1740000 805000 6710000 SSW 3660000 1650000 249000 3430000 SW 490000 1440000 70600 1300000 WSW 506000 1340000 63900 1540000 W 817000 602000 9750 4550000 WNW 925000 1040000 16900 4430000 NW 1390000 1960000 33700 5010000 NNW 1320000 1710000 60100 4200000 TOTAL 38438000 48732000 31830150 84940000 All data reported in kilograms Basis: Reference 2.1 ~ 3-1

2. 1.3-8 Amendment No. 1

0

~I

SHNPP ER TABLE 2.1.3-2 (continued) 1980 AGRICULTURAL PRODUCTION OF NAJOR CROPS BETWEEN ZERO AND FIFTY MILES OF THE SHNPP 40 TO 50 MILES SWEET CORN FOR DIRECTION SOYBEANS TOBACCO POTATOES GRAIN N 499000 5030000 31100 4410000 NNE 1450000 4920000 26500 2840000 NE 3100000 5880000 449000 4860000 ENE 3230000 6670000 3220000 6090000 5420000 10800000 10400000 18100000 ESE 7400000 9120000 9870000 22000000 SE 6210000 5200000 5200000 22900000 SSE 6030000 3830000 3280000 16600000 S 5970000 2320000 865000 8940000 SSW 7730000 1630000 99600 5190000 SW 642000 1750000 87400 1650000 WSW 607000 1490000 77400 1780000 W 1210000 778000 12200 6750000 WNW 1120000 1670000 21700 5980000 NW 1390000 2810000 40500 5620000 NNW 1160000 3520000 43800 4510000 TOTAL 53168000 67418000 33724200 138220000 All data reported in kilograms Basis: Reference 2.1.3-1

2. 1.3-9 Amendment No. 3,

SHNPP ER TABLE 2.1.3-2 (continued) 1980 AGRICULTURAL PRODUCTION OF MAJOR CROPS BETWEEN ZERO AND FIFTY MILES OF THE SHNPP CUMULATIVE TOTALS SWEET CORN FOR SECTOR SOYBEANS TOBACCO POTATOES GRAIN 00 TO 10 3882000 7307400 1097030 6552000 00 TO 20 18398000 30868400 6533060 31901000 00 TO 30 45799000 72108400 26593260 86557000 00 TO 40 84237000 120840400 58423410 171497000 00 TO 50 137405000 188258400 92146710 309717000 All data reported in kilograms Basis: Reference 2.1.3-1

2. 1.3-10 Amendment No. l

SHNPP ER 2.2.1 SITE TERRESTRIAL ECOLOGY 2.2 '.1 Site Terrestrial Flora The SHNPP site occupies approximately 10,800 acres of land within the Buckhorn-Whiteoak Creek watershed, a tributary system of the Cape Fear River.

Because the agricultural history of the Buckhorn-Whiteoak basin generally follows that of the Piedmont province, the entire project area is an aggregate of farmland, abandoned fields, and forests of various ages. While farming was once a major occupation on the SHNPP site, the primary land use at the time CP&L acquired the project land was the production of pulpwood and other wood products. The existing vegetation characteristics of the site were the outcome of disturbance through clearing, farming, and logging followed by the natural process of secondary succession. To identify the vegetation characteristics of the SHNPP site, baseline botanical investigations were designed to include qualitative and quantitative determinations of species and community types. +alitatively, 452 species of vascular plants (Table 2 in Reference 2 ~ 2 ~ 0-5) were identified within seven generalized vegetative communities (Table 2 '4 in Reference 2 ~ 2 ~ 0-4). These plants and communities were identified during field sampling throughout the project area with special emphasis within four terrestrial sample areas (Figure 2 in Reference 2.2.0-5).

Quantitative botanical evaluations included vegetation cover mapping of the project area (Figures 3.6-1 through 3.6-6 in SHNPP Construction Permit Environmental Report) with the resulting acreage estimates (Table 2.14 in Reference 2.2.0-4) and quarter method analyses of the two wooded sample areas.

Estimates based on the 1972 vegetation cover map indicated that 8% of the SHNPP project area was in field and 14% was cutover woodlands. The remaining 78% was covered by forests of various types.

Results of botanical studies of four terrestrial sample areas indicated that the vegetation of the SHNPP project area was typical of the eastern portion of the Piedmont province of North Carolina. The fields and cleared areas were undergoing changes described as secondary or "old field" succession. The areas covered with forests were also undergoing successional changes, although these changes were not as easily detectable.

The two old field sample areas were representative of the majority of the fields, throughout the project area. In 1972, these areas were dominated by various herbaceous plants such as grasses, (Poaceae), asters (Asteraceae), and other forbs. By 1978, the areas were being invaded by woody species including pines (Pinus spp.) river birch (Betula ~ni ra), black willow (galix ~ni ra), and oaks (~uereus spp). These changes in species dominance ware expected and predictable, and if allowed to continue, would reflect the development of these areas into hardwood forests.

The two wooded transects were representative of the majority of the vegetation of the SHNPP project area. This included forests in various stages of succession, from young pine stands to fairly mature hardwood stands. These forests represented the later stages of secondary succession, and reflected the ultimate fate of the abandoned fields and cutover areas. Eventually, if not disturbed, the majority" of the project area would become a forest 2.2.1-1

SHNPP ER dominated by various species of oaks, hickories (Carya spp.), sourwood (Oxydendrum arboreum), pines, and red maple (Acer rubrum) (Table 2.15 in Reference 2.2.0-4). Some variation in species composition would occur in areas along stream bottoms, where more water tolerant species such as river birch, sycamore (Platanus occidentalis), and yellow poplar (Liriodendron tulipifera) would predominate.

Because the, creeks within the SHNPP site were generally well shaded and highly variable in flow, few aquatic macrophytes existed there. However, aquatic vegetation was prevalent along the banks of the Cape Pear River, and growths were readily vis1ble among the exposed rocks and islands, especially during low flow conditions. The emergent water willow (Justica americana) was a macrophyte round in and aiong the river .Elodea ~Elodea canadensis),

)

ceratophyllum) comprised a ma)or portion of the aquatic river vegetation.

The results of construction phase monitoring at SHNPP are presented in the annual reports for 1978 and 1979 (References 2.2.0-7 and 2.2.0-8).

Construction effects are discussed in Section 4.1.3 of the document.

2.2.l.2 Site Terrestrial Fauna The available wildlife habitat 1n the Buckhorn-Wh1teoak watershed, although diverse, generally was conceded to be of below average quality. That evaluation was initially based on a U. S. Bureau of Sport Pisheries and Wildlife survey of the Buckhorn-Whiteoak basin. conducted in the fall of 1969 (Table 2.16 in Reference 2.2.0-4).

Generally, the 'wildlife hab1tat and the wildlife populations identified at the SHNPP site were characteristic of the Piedmont province of North Carolina.

More specifically, the habitat and associated wildlife were typical of a highly exploited, but relatively uninhabited area of the Piedmont. A var1ety of non-game wildlife species was observed in the various habitats of the project area. Although small game species were common in appropriate habitats, big game species were nearly non-existent.

~

The basel1ne inventory study 'of the amphib1ans and reptiles 'inhabiting the SHNPP site was conducted by recording observations during all phases of terrestrial vertebrate field studies. The primary source of data regarding bird species inhabiting the SHNPP site was periodic roadside surveys. In addition to the quantitative data provided by the roadside surveys, qualitative information was obtained by recording observations by species throughout the project area with emphasis on the four terrestrial sample areas. Information concerning'he game bird populations was obtained by conducting call count surveys along the avifauna routes during the spring and summer of 1976 and 1977. The mammal investigat1ons of the SHNPP site consisted of small mammal trapping at the terrestrial sample areas supplemented by observations of mammals or mammal sign throughout the prospect area. A leafnest survey of the site was conducted in mid-'winter of, four s

2.2. 1-2 Amendment No. l

SHNPP ER 2.3 METEOROLOGY 2~ 3~ 1 REGIONAL CLIMATOLOGY The SHNPP site lies in the transition zone delineating the Coastal Plain Region and the Piedmont Region of North Carolina. Climatology of North Carolina largely depends on elevation above sea level and distance from the Atlantic Ocean. At an elevation of about 260 ft. MSL and 115 mi. from the nearest Atlantic coastline, the site area has a temporate climatic regime.

Stations representing the regional climatology, their locations with respect to the site area, and their elevations are presented in Table 2.3.1-1.

The summer months of June, July, and August are characterized by a southwesterly air flow resulting from the extension of the Azores-Bermuda high pressure system. This Gulf of Mexico and occasionally Atlantic moisture laden air produces the bulk of precipitation for these months in the form of afternoon and evening thundershowers. During this three~onth period, an average of 39 days reach 90F or above as reported by the Raleigh-Durham Weather Service, the nearest first-order reporting station to the site area.

July is the hottest month at all stations within the site'rea. These months can be quite oppressive with dewpoints averaging between 66 and 67F (Reference 2.3.1-1).

The autumn months of September, October, and November show a gradual decrease of average temperature of about 10F per month. The combination of residual summer moisture and increased radiational cooling due to longer nights makes this the season of highest fog frequency. Although precipitation is distributed rather uniformly on an annual basis, the autumn months tend to be the driest. Daytime heating is not sufficiently intense to produce significant convective activity, and the general north-south temperature gradient has not substantially materialized to generate strong frontal precipitation. Winds tend to the northeast during the autumn reflecting a change in the pressure distribution The summer wind flow configuration of a high pressure system offshore, and a lower pressure system over the continent is replaced by the northerly wind flow configuration of a continental high pressure system with a lower pressure systems centered offshore. The land-sea temperature contrast favors higher pressure over the ocean in spring and summer, higher pressure over the continent in autumn and winter, thus providing the seasonal reversal of wind directions. The higher autumnal northeastern frequency when compared to the winter frequency is the result of slower moving autumnal synoptic systems.

The winter months of December, January, and February show a shift of the wind direction frequency into the westerly quadrants from the northeasterly fall season distribution responding to a strengthened westerly component added to the predominant southwest-northeast bimodal distribution. January is the coldest month, averaging 18 days with a minimum temperature below 32F at the Raleigh-Durham Weather Service (Reference 2.3.1-1). Cold air outbreaks are either blocked or significantly modified by the Appalachian Mountain chain located some 150 miles to the west and northwest of the site. Most sustained winter precipitation is the result of two storm tracks. One track originates in the warm waters of the western Gulf of Mexico, then crosses Florida skirting the Atlantic Coast northward. The second track is called the "Cape 2%3 1

SHNPP ER Hatteras Low", so named because the temperature contrast of the off-shore gulf stream and shape of the coastline gust south of Cape Hatteras, N. C. provide excellent breeding conditions for cyclonic circulations. These two storm tracks are responsible for virtually all of the snowfall in the site area, January accumulating the greatest average snowfall totals.

The spring months of March, April, and May are characterized by consistently rising temperatures on the order of 9F per month. Precipitation occurs in a mixed mode of frontal and convective forms. This transitional season generally possesses more winter than summer characteristics. The mean date of the last 32F temperature for the area is around the first week in April (Reference 2.3.1-1). Maximum average wind speeds are generally observed in this season due to the intensity of the general north-south temperature gradient.

2+3+2 ATMOSPHERIC CONDITIONS The extent of vertical mixing is a ma)or factor in determining atmospheric diffusion characteristics. As a rule, mixing depths are characterized by a diurnal cycle of a nighttime minimum and a daytime maximum. The nighttime minimum is the result of surface radiational cooling producing stable conditions, frequently coupled with a low level inversion or isothermal layer.

The mid-afternoon maximum is attributable to surface heating producing instability and convective overturning through a larger portion of the atmosphere. Mean mixing depths also show a seasonal cycle of a winter season minimum and a summer season maximum. Holzworth (Reference 2.3.2-1) has shown this by listing month1y mean maximum mixing depths. Table 2.3.2-1 lists these results for Greensboro (nearest data point to plant site). The lowest mean maximum mixing depth occurs in January (390m), and the greatest mean maximum depth in June (1790m).

Low level inversions inhibit vertical mixing of the atmosphere. Hosier (Reference 2.3.2-2) has compiled frequencies based on the percent of total hours of occurrence of an inversion or isothermal layer based below 500 ft.

The frequency of those low level inversions for Greensboro are presented in Table 2.3.2"2. The summer season averages inversions about 33 percent of all hours. Comparatively, inversions exist during approximately 43 percent of all hours during the winter season.

Cases of high air pollution potential occur during periods of stagnating anticyclones which exhibit low surface winds, no precipitation, and a shallow mixing depth resulting from a subsidence inversion. These conditions occur most frequently at the plant site during the fall months, particularly October. According to Korshover (Reference 2.3.2-3) about 32 cases of autumnal atmospheric stagnation, lasting four days or more, occurred during the period 1936-1970. A total of four cases lasting seven days or more were recorded during the same 35-year period.

2e 3o 3 TEMPERATURE Monthly and annual summaries of climatological normal maximum, minimum, and average temperatures for Raleigh-Durham (Reference 2.3.3-1), Greensboro (Reference 2.3.3-2), Charlotte (Reference 2.3.3-3), Moncure (Reference 203-2

SHNPP ER 2.3.3-4), Pinehurst (Reference 2.3.3-4), and Asheboro (Reference 2.3.3-4) are given in Table 2.3.3-1. Monthly and annual onsite mean temperature data for January 1976 through December 1978 is presented in Table 2.3.3-2. The mean maximum and minimum temperature data from the onsite meteorological station is shown in Table 2.3.3-3. The site area diurnal temperature range spans from about 20F in the winter and summer seasons to around 25F in the transitional autumn and spring months (Reference 2.3.1-1). Measured maximum and minimum temperature extremes for the offsite stations are summarized in Table 2.3.3-4.

The lowest temperature recorded was a -7F in January of 1940 in Greensboro, the highest recorded temperature being a 107F reading at Moncure in July of 1952 (References 2.3.3-1, 2.3.3-2, 2.3.3-3, 2.3.3-4).

2 '.4 WATER VAPOR Mean monthly and annual dewpoint temperatures and corresponding absolute humidity values for Raleigh-Durham, Charlotte, and Greensboro are given in Table 2.3.4-1 (Reference 2.3.1-1). Monthly and annual onsite dewpoint temperatures for the period January 1976 through December 1978 are given in Table 2.3.4-2. The onsite average dewpoint temperature of 47.4F compares very well to the 48F average dewpoint temperature observed at Raleigh-Durham, although winter dewpoint temperatures tend to be lower at the site and summer values a little higher.

A maximum persisting 12-hour surface dewpoint temperature of record for the site area is approximately 77F and would be expected to occur during a period of extended air flow trajectories from the Gulf of Mexico (Reference 2.3.1-1) ~

Diurnal variations of relative humidity for Charlotte, Greensboro, and Raleigh-Durham are given in Table 2.3.4-3 for the local standard times of 1:00 a.m., 7:00 a.m., 1:00 p.m., and 7:00 p.m. (Reference 2.3.3-1, 2.3.3-2, 2.3.3-3). The 7:00 a m. and 1:00 p.m. times correspond to the general maximum and minimum respective values of the diurnal relative humidity cycle, with 1:00 a.m. and 7:00 p.m. providing approximate midrange values. The late summer to early fall maximum of early morning (7:00 a.m.) relative humidity values results in a maximum of radiational fog frequency occurring at this time of year. See Section 5.1.4 for fogging and icing potentials.

2 '.5 PRECIPITATION Precipitation is rather uniformly distributed on an annual basis in the site region. Table 2.3.3-1 gives climatological normal monthly and annual precipitation amounts for nearby recording stations (Reference 2.3.3-1, 2.3.3-2, 2.3.3-3). Onsite precipitation totals are summarized in Table 2.3.5-1. Climatologically, July has a tendency to be the wettest month, October the driest; but, the variance is small such that the region does not possess a "wet" and "dry" season. Extreme precipitation amounts for nearby recording stations are listed in Table 2.3.3-4 (Reference 2.3.3-1, 2.3. 3-2, 2.3.3-3) ~ The extreme rainfall rates summary for the onsite facility for the January 1976 through December 1978 period is shown in Table 2.3.5-2. The onsite extreme rainfall rates for all time periods included by the table occurred on the same date, March 21, 1976, with a maximum 24-hour precipitation total of 4.41 in 2~3 3

SHNPP ER On an average the site area receives precipitation one day in three.

Table 2.3.5-3 displays precipitation statistics for the stations of Raleigh-Durham, Greensboro, and Charlotte (Reference 2.3.5-1). These statistics are presented for the months of January, April, June, and October which are considered representative of the four seasons. Table 2.3.5-3e indicates that precipitation intensities during July are about double those of January. Table 2.3.5-3f further characterizes the higher intensity, shorter duration July precipitation versus lower intensity, longer duration January precipitation. Generally, winter precipitation duration is about twice as long as that of July. However, daily rain totals are generally smaller. The transitional April and October months seem to fit the winter precipitation regime better, partly due to slower moving rain systems in the transitional seasons than in mid-winter. Onsite data showing the number of hours with measurable precipitation by month and year including the overall average for the January 1976 through December 1978 period is depicted in Table 2.3.5-4.

Seasonal and annual precipitation wind roses for Raleigh-Durham (Reference 2.3.5-2) are illustrated by Figures 2.3.5-1 and 2.3.5-2. Onsite precipitation wind roses for the period January 1976 through December 1978 are presented in Figure 2.3.5-3. A northeast-southwest wind frequency distribution is the dominate flow regime during precipitation periods for both stations. Extreme precipitation totals for representative offsite stations are shown by Table 2.3.3-4 along with measured extreme snowfall totals (References 2.3.3-1, 2.3.3-2, 2.3.3-3, 2.3.3-4) ~

2>>3 ' WIND DISTRIBUTIONS Wind direction and speed distributions are essential parameters for determining site characteristic diffusion climatology. Onsite joint frequency distributions of direction and speed by stability class and a summary of all winds as outlined by Regulatory Guide 1 23 (Reference 2.3.6-1) for the period January 1976 through December 1978 are given by Tables 2.3.6-1A through 2.3.6-1D. Annual and seasonal wind roses for Raleigh (Reference 2.3.5-2),

Greensboro (Reference 2.3.6-2), and Charlotte (Reference 2.3.6-3) are illustrated by Figures 2.3.6-1 through 2.3.6-6.

The Raleigh (1955-1964) )oint frequency distribution of wind direction and speed by Pasquill stability classes is given in Tables 2.3.6-2A through 2.3.6-2G. Pasquill stability classes were determined by the STAR method (Reference 2.3.5-2) ~ Stability classes F and G were combined into F stability.

Despite differing techniques used to determine atmospheric stability (delta temperature method for onsite data and the STAR method for Raleigh data), the onsite joint wind frequencies of Table 2.3.6-1 compare favorably to those compiled for Raleigh. Neutral (D) and slightly stable (E) stability classes occur most frequently at both stations. However, Stable (F) and extremely stable (G) stability classes are more frequent at the onsite meteorological station. This is due in part to some nighttime cold air drainage into the broad, shallow basin in which the site is located (See Section 2.3.8) ~

The characteristic northeast-southwest bimodal frequency distribution is evident at all locations and is depicted by the onsite wind rose given in 2.3-4

SHNPP ER Figure 2.3.6-7. Average annual wind, speeds from the area.offsite stations are rather uniform ranging from. 6..9 mph at. Charlotte to- 7. 9 mph at Raleigh-.Durham.

The onsite lower'evel (12.,5m) mean wind speed based on 1976-1978 data. is 4..6 mph. The onsite value is about 35 percent lower than the 7.1 mph value observed at the Raleigh-Durlim. Weather Service. Differing time periods, averaging methods, and instrumentation account, in part, for'he lower average onsite. wind speed'alue.,

It is, believed that topography probably is the single most influential factor resulting in the lower average onsite wind speed. The SHNPP site lies in a broad, shallow 200 ft. deep basin extending about, ten miles in directions west through south of the site (see Section 2.3.8). Cold air drainage into a basin during the night is a common, occurrence in some areas. This phenomena tends to reduce the vertical momentum flux having- a discoupling effect on. the wind flow in the site area and thereby contributing to light surface winds. This colder. air is denser than the surrounding environment, and therefore, difficult. to displace and, in fact,, quite often remains until dissipated soon after sunrise by the influx. of solar radiation. Although unconfirmed, this phenomena. is believed to be- the"major factor resulting in lower onsite wind speeds- compared to those. observed at the Raleigh-Durham Weather Service.

From- the seasonal wind roses, the southwesterly component is most evident in the spring, summer, and winter seasons., The higher frequency of. northeast wind directions in the fall, is the resul't of a trend towkrd continental high pressure systems introducing a northerly wind flow and the slower movement of systems due to weak upper level steering currents prevailing at this 'ynoptic time of year. Winds from the= southeastern quadrant are rare and for the most part preceed warm frontal passages, Wind, direction persistence for the on-site data is defined as the number of, consecutive hours during which the wind direction was from the same 22.5 degree direction sector-. Tatles 2.3.6-3A through 2.3.6-3P show the number of hours of persisting wind directions by stability class as recorded at the 12.5m and 61.4 onsite levels of operation for the SHNPP. The maximum period of persistent wind direction for the 60 meter level was from the south-southwest and lasted 37 hours4.282407e-4 days <br />0.0103 hours <br />6.117725e-5 weeks <br />1.40785e-5 months <br />. The same synoptic pattern produced the maximum period of persistent wind direction at the 125 meter level which lasted. 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />. Maximum persisting; winds at both levels were out of the south-southwest direciton and ended at the same time. Figure 2.,3.6-8 presents a graph of the number of persisting wind, direction probability of one-sector wind direction persistence occurrence . An estimate of the percent of the total time a given- number of wind persistence hours occurs can be taken directly from Figure 2.3. 6-8. For. example, a 10-hour- wind direction persistence from any one of the 16 compass directions occurred about 2 percent of the total hours.,

Sustained winds greater than 50 knots have occurred only twice in the past 24 years as recorded by the Raleigh-Durham Weather Service. A one~inute average 69 mph wind from the southwest was recorded during a thunderstorm on July 21, 1962. A maximum site area one~inute avexage wind of 73 mph from the westmorthwest was recorded during Hurricane Hazel on October 15, 1954.

2.3-5

SHNPP ER (Reference 2,3.3-1) A complete list of hurricanes affecting the site area, the amount of precipitation, and fastest~ile wind associated with each is given by Table 2.3.6-4. The intensities of wind and precipitation produced by hurricanes at the plant site are general'ly no greater than those produced by severe thunderstorms.

2~F 7 ATMOSPHERIC TRANSPORT'ROCESSES TO 50 MILES Meteorological data and analysis of the preceding sections have included onsite and representative offsite stations both within and outside a 50~le radius of the plant. Because of the- homogeneous nature of the topography and climatology of the paramet'ers that govern atmospheric transport processes, the analysis presented in the preceding sections is also sufficient to characterize transport processes to within a 50~ile radius.

2 3 8 TOPOGRAPHIC FEATURES The SHNPP site lies within a very shallow basin as depicted by Figures 2 ' '-1 through 2.3 '-4 which gives plots of elevation versus distance from the plant center by direction sectors. Generally, within 10 miles of the site, the elevation above mean sea level gradually increases from the plant grade level.

of 260 ft. to around 400 ft.. in all but the west-southwest, southwest and north-northwest sectors . 'I Topographic features within a S~ile radius as modified by the plant are shown in Figure 2.3 8-5 ' Filling of the main reservoir south and. southeast of the.

plant will add an additional heat and moisture source to the area. As a result, a, slight increase of wind speed is expected with possible changes in wind direction frequencies Additionally,, the reservoirs are expected to reduce the intensity of the nighttime surface inversion thereby reducing the frequency of Pasquill class G stability.

Topographic features within a 50~ile radius are shown in Figure 2.3.8-6 ~ In general, the terrain slopes upward northwest of the site area averaging about 10 ft. per mile to reach an elevation of about 800 ft. at 50 miles from the plant site., The terrain from the north through the west sectors is gently rolling, ranging only from about 100 ft to 500 ft. above mean sea level.

2. 3-6

ThRLE 2.3.6"ll JOINT 1'ERCENThGE FREIPENCIES OF MIIID DIRECTIOII hND SPEED FOR TNE PERIOD 4t00 Ptt 1/14/76 TO llt00 Ptt 12/31/78 LOMER LEVEL MIND SThRILITY ClhSS h SThSILITY ChLCULhTKD FRON DIFF+ TKNPERhTURE tthRRIS Otl&ITE NETEOROLOGIChL fhCILITY LOWER MltID SPEED ClhSS(kIPII) hVG0 UIRKPIUN Chltt 0. 75 - 3. 5 3. 5 - 7. 5 7.5 - 12. 5 12. 5 - 18. 5 18. 5 il

- 25.0 CREhTKR TNhN 25.0 TOThL MIIID SPEED tt U.U 0. 24U4E&1 0. 3727K%00 0.2404KROU U. 8014K&2 0.0 0.0 0.6452K%00 O. 7025EAOI NNE U.U 0. 40078-02 0.26858800 0.2164K%00 0.0 0.0 0.0 0.4889EAOO 0. 7267K%01 NY. U.U 0. 1603K%I 0.21648400 0. 1523K%00 0. 8014K&2 0.0 0.0 0.39278400 0. 7216K& I EtIY. U.O 0.4007K&2 0. 1643K%00 0.48098&1 0.0 0.0 0.0 0.2164Ei00 0. 63588401 U.O Oo 1202K&1 0. 76148&1 0. 1202K&1 0.0 0.0 0.0 0. 1002K%00 0. 562 IKIOl ESY U.U 0. 1202K &1 0. 601 1K&1 0. 8014K&2 0.0 0.0 0.0 O. 80148-01 0. 4889K%01 U.U U.2404K&I 0.6UIIK&I 0.40078&2 0.0 0.0 0.0 0. 8816K&1 0.4875K%01 SSE U.O 0, 8014K+2 0. 1042EIOO 0. 8014K&2 0. 4007K&2 0.0 0.0 0. 12428000 0. 5815K%01 0.0 0. 1603E& 1 0. 1162K%0 0.20048&1 0. 8014K&2 0.0 0.0 0. 1603KAOO 0. 62208401 SSM O,U 0. 2004K &1 0.2364K%00 0.2885K%00 0. 1603K&1 0.0 0.0 0. 56 I DEROG 0. 78308401 SM 0.0 0. 2404K&1 0,2765EROO 0.3807K%00 0. 1242K%00 0.0 0.0 0.8054K%00 0. 87738101 IISM O.U 0. 3606E&1 0.3086MJO 0.2605&00 0. 7213K& 1 0.1603K&I 0.0 0. 6983 F 100 0. 8303 Y.AOI lt 0.0 U. 2004K&1 0, 1964EHOO 0. 1202K%00 0. 2805K& 1 0.40078&2 0.0 0.3687ENOO 0. 743 I EiOI MIIM U.O 0. 1202K& 1 0. 17238400 0. 35668%0 0. 921 7E& 1 0. 8014K&2 0.0 0. 6412EIOO 0. 94618401 IIM O.U 0.4007K&2 0.2484EHOO 0.2805K%00 0, 5209K&1 0.0 0.0 U. 585IE100 0. 8164k:tOI NHM U.U 0. 1202E W 1 0.2284EHOO 0.3005EROO 0.3606K&I 0.0 0,0 0. 577UEWOO 0. 8134K%01 TUTh L U.U U. 2484EIOO 0. 3106KIUI 0. 2697K%01 0. 4488K%DU 0. 2805K-Ol 0.0 0. &5288401 U. 7086K%01 ttwtttER UF ChQIS - 1 tIUktttKII IIY UhD IIUUIIS 548

ThttlX 2+ 3+ 6-3h Mlt(U DIRECTIOt( YERSISTENCE DhTh +

NhRRIS ON-SITE NETEROLOCIChL FhCILITT JhNUhRX 14, l976 TO DECEHSER 3l 1978 SThUILITT CLhSS h lAt((LR NUt(UER OF OCCURREt(CES MIND DIRECTIO(l l'ERSISTKt(CE (I(OURS)

LKVY(. MIND 0 IRECT IUH 4 5-7 8-10 ll -13 l4 -l6 lg -l9 20-22 23-25 ) 25 t( 43 l8 ll 6 NNE 24 l3 4 7 NE 20 )0 8 2 Y.t(E l3 3 3 3 Y. 6 4 2 2 Y.SY ll l r SY. 13 I l SSY 9 7 S l9 2 SUM 29 l2 8 12 SM 32 26 l6 5 ltbM 33 14 14 6 M 29 ll 2 2 MNt 36 ll ll 4 t(M 21 8 6 t(t(M 3l 15 6 hVEI(hCE l.u 2au 3.0 5.6 8.5 0.0 0.0 0.0 0.0 0.0 UURhTIUt(

NOUNS lthX(t(UH UUURb N(k(t(ER UUUI(S UY t(ISbB(C MIND DIRECTIO((S: 49

• YE((SISTENCE 18 DEFINED hS h DELTh T EXISTINC MITHIH h DEFINED MIND l)IRECTIOtl SECTOR hNU IS NOT CONSIDERED TO UE INTER((UYTED IF IT DEPhRTS FROtl TNhT DEITh T VhLUE YOR UP TO 1 HOUR hND TNEt( RETURNS ~ OR Ik THERE IS Ot(E llUUR UY t(ISSINU DhTh FOLLOMED 8'I h CONTINUED DELTh T VhLUE. TMO OR NORE COt(SECUTIVE HOURS OF LOST DhTh hRE NOT lt(C(.UUEIJ It( TIIE YERSISTENCE DETERHIHhTIUH UUT hRE INUIChTED hS "NISSI((C MIND DIRECTIONS" ~

ThBLE 2+3~6-3B HIND DIRECTION PERSISTEIICE DhTh <<

NhRRIS ONWITE HETEROLOGIChL FhCILITY JhNUhRY 14, 1976 TO DECEHBER 3L> 1978 SThBILITY CLhSS B UNVIt NUNBER OP OCCURRENCES - ltIHD DIRECTIU( PERSISTEHCE (HOURS)

LEVVL IIIND B-10 )4-16 17-19 20-22 23-25 '

DIRVCTIUtt 1 2 4 5 7 11-13 25 N

tINV 45 ll 41 4 NY. 37 7 ENY. 2L 6 19 3 hkh'E 15 4 14 Skh' 1U 2 22 6 2 Stt 39 13 3 SM 56 16 6 IINI 16 3 M 31 7 2 lttht 53 16 4 IBI 4B 19 Ntnt 5U 1 hVhkhGE 1~ U  ?.U 3.0 4.0 5.L 0.0 0.0 0.0 0.0 0.0 0.0 0.0 UUkhT IUtt NIJURS tthX.I IIUII l UUUKS NUttUL'k IIUUI(S OF ttlSSING ItlttD DlkVCTIttttSt IB

<<PKIISISTEHCY IS DEFIHED hS h DBLTh T EXISTING HITNIN h DEFINED 'HLIID DlttECTIOtt SECTOR hHD IS NOT CONSIDERED TO BE I

INTERI(UPTVD IF IT DEPhIITS }ROIL TUhT DELYh T VhLUE OR UP TO 1 'HOUR hklt THEN RETURttS ~ OR IF THERE IS OtIE HOUR OY ttlbSING DhTh FOLLOMED BY h COHTItIUED DELTh 1 VhUIEo 1%0 OR LIORE CONSECUTIVE IIOURS OP LOST DhTh hRE HOT ltICLUIih;D IN TUE I'ERS1STYIICY. DVTEIUIINhTIOII BUT hRE IHDIChTED hS "NISSLNG HIND DIRECTIOHS" ~

ThBLE 2+3+6-3C MIND DIRECTION PERS'ISTENCE DhTh

• UhRRIS ON&ITE NETEROIACIChL FhCILITY JhNUhkY l4 ~ I 976 TO DECEHBER 3l ~ 978l SThBII.ITY CLhSS C IANEk HUIIBER OF OCCURREHCES - MltlD DIREL"CIOtt PERSISTENCE 0(OURS)

LEVEL MIND DIRECTION I 2 3 5 " 7 8 - lO II - l3 l4 - )6 l7 - l9 20 " 22 23 - 25 ) 25 N 67 l5 IINE 43 7 NE 39 L't(E 33 8 E 27 7 l4 2 l5 2 SSE 24 6 35 ll SSM 15 SM 80 l4 IIQI 72 9 46 10 llktl 67 7 tki 64 13 NIIM 66 8 hVEkhCE I,O 2,0 3.0 4.0 5.0 0,0 0.0 0,0 0.0 0.0 0.0 0.0 DUkhTIUN BOURS tthX INDI( I IIOOBS IIUIIBER UOUI(S OF IIISSING MIND DIRECTIUtiSI l7

• PERSISTENCE IS DEFINED hS h DELTh T EXISTIIIC MITNIN h DEFltlED MIND DIRECTION SECTOR hND IS NOT CONSIDERED TO BE INTEKRUPTED IF IT DEPhkTS PRO(I TUhT DELTh T VhLUE I'OR UP TO f HOUR hHD TUSH RETUBtiS, OR IF THERE IS ONE llOUR OF IIISSltlQ DhTh FOLLOMED BY h CON1'INUED DELTh T VhulE, TMO OR NORE CONSECUTIVE llOURS OF LOST DhTh hkE HOT INCLUDED Itl TIIE I'EBSISTENCE DETEIQIINhTIUH BUT hRE IHDIChTED hS "NISSINC 'MIND DIRECTIONS" ~

'TARLE 2+3+6-3D MltUI DIRECTION PERSISTENCE DATA ~

HARRIS Ott-SITY. tIETEROLOCICAL FACILITY JANUARY 14>> 1976 TO DECEIIRER 31 ~ 1978 STASILITY CLASS 0 LOllVk HUHIiER OF OCCURRENCYS MIND DIRECTIOH PEkslSTEIICE (HOURS)

LEVEL MIND D lkECT IUtt 5-7 8-10 11 -13 14 16 17-19 20-22 23-25 25 N 145 61 24 13 18 10 tttIV 134 54 21 11 23 4 3 NE 124 46 17 14 5 5 1 ENE 101 31 12 7 ll 2 1 83 34 ll 2 7 2 ESE es 20 ll 7 4 ek 28 ll 5 6 1 98 31 15 I! 10 2 132 48 15 5 7 SSM 2U3 65 26 ll . 14 2 219 71 33 14 16 5 MSM 160 61 QI 16 15 2 M 141 37 12 5 1 lrtht 138 44 15 ll 8 2 2 137 37 13 9 2 NNM 148 52 20 15 14 3 1 AVEkht'Y l. 0 2. 0 3. 0 4,0 5o 5 8. 8 11 ~ 6 14 ~ 7 17.5 20.0 24.0 28.0 UUkATIOtt NOUks tlhXINUII . I 10 13 16 18 24 ltOUkb tlettkkk NUURS OF NISSINC ltltID DIRECTIONSt 88

• I'EKSISTENCE IS UEI'INED AS h DYLTA T EXISTIHC MITHLH A DEFINED ltIND DIRECTION SECTOK AND IS IIOT. COHSIDERED TO RE INTYRRUPTED Il'T DEPARTS FROtl TIIAT DELTA T VALUEFOR UP TO 1 IIOUR AND THEtt RETURNS ~ OR IF TIIERE IS ONE IIOUR OF tllSSIHC DATA FOLLOMED DY h COHTIHUEU DELTA T VALUE+ TMO OR NORE CONSECUTIVE IIOURS OF LOST DATA ARE NOT INCLUUED Itt THE PVRSISTENCE DETEkHIHATIOtt RUT ARE ltIDICATED AS "HISSItIC MIND DIRECTIONS" ~

ThBLE 2.3.6-3E MIHD DIRECTION PERSISTEHCE DhTh +

IthRRIS ON&ITE )IETEkOLOCIChL FhCIl ITY JhNUhkY 14 ~ 1 976 TO DECQIBER 31 ~ 1 978 SThSILITY CLhSS E LUMEN HUt)SEK OF OCCURRENCES MIIID DIRECTION PERSISTENCE (I)OURS)

LEVEL MIND Dlt(ECTIUH 5 - 7 8 - 10 11 - 13 14 - 16 17 - 19 20 - 22 23 - 25 25 ti 153 35 20 10 14 IINE 127 51 24 13 HV. 124 31 17 5 10 VNV. 123 22 8 5 5 V 99 21 9 4 9 ESE 100 20 5 2 5 109 27 9 3 I SL'M 147 31 18 10 10 3 176 59 39 16 23 1 226 66 41 22 24 ll 235 41 22 ll 13 2 MSM 126 27 24 7 8 I M 116 25 10 3 3 Mtat 120 29 12 3 Nlt 117 34 10 8 ll4 NHII 127 33 16 5 6 hVEkhGE I.U 2.0 3.0 4,0 5.6 8.5 11.5 15,0 18.0 0.0 0.0 0.0 UURAT)UtI IIUUKS tthXIHW I 15 18 HOURS NUMBER I)OURS OV IIISSlttG MIND UIBVCTIUHSI 103

• PERSISTENCE IS DEFINED hS h DELTh T VXISTIHG I)IT))IN h DEFINED MIND DIRECTIU)I SECTOR hND IS HOT CONSIDERED TU SE INTEkkUPTL'U IV IT UEPhkTS FRO)I TtlhT DEI.Th T VhLUE l'Ok UP TO 1 IIOUR hND TIIE)I RETURNS ~ OR IF THERE IS ONE HOUR OF tIISSlttG IthTh FOLLOMED SY h COHTINUED DELTh T VhLUE, TMO OS )IOBE COIISECUTIVE IIOURS OF LOST DhTh hkE NOT INGLUDEII Itt TUE PERSISTEHCE DETEIUIINhTIUtt SUT hkE INDIChTED hS ")IISSINC Mlt)D DIBECTIOt)S" ~

ThRLE 2,3,6-3F ltINU DIRECTION PERSISTENCE DhTh >

HhRRIS ON-SI'fE HETEROLOCIChL FhCILITY JhkuhttY l4, 1976 TO DVCEHSER 31, 197e SThRILITY CLhSS F LUMEk NUIIRER OF OCCUkRENCES 'PIND DIRECTION PERSISTENCE (HOURS)

LEVE I MINU D1kkl'TIOtt 2 3 4 5-7 K-10 11-13 14-16 17-19 20-22 23 "25 25 N ltd 28 NNV 1 1 1 19 9 NE 99 20 5 ENE 6U 19 10 UZ 12 5 1 ESE 97 15 I U2 10 I 4 III 24 5 3 121 45 14 9 SSM 127 41 15 14 S'M 105 29 16 a MSlt 90 19 6 5 M 75 12 4 4 IINM 7U 14 3 NM U2 7 3 NNM 95 20 9 hVEkhGE 1.U 2mU 3,0 4.0 5.4 9.0 ll 0

~ 0.0 0.0 0+0 0.0 0.0 DUkhT ION llUURS klhXI HUH 10 HUURS NUklliEk HUUkS OF HISSING MltlD UIRECTIUIISl 51

• PERSISTENCE IS DEFINED hS h DELTh T EXISTING MITIIIN h DEFIIIED MIND DIRECTIOtl SECfOR hND IS NOT CONSIDERED TO RV IKfERkUPTLD IF IT UVPhkTS I ROII Tllhf DELTh T yhLUE )OR UP TO I HOUR hklt THEN RETURNS ~ OR IF THVkE IS ONE HOUR OF HISSING UhTh I'ULI.OMED KY h CONTINUVD DEI'fh T yhLUE. TMO OR NORE COIISECUTIVE HOURS OF LOST DhTh hkE NOT INCLUDED Itl THE PERSISTENCE DETERHlNhTION KUT hRE INDIChTED hS "HISSINC 'PING DIRECTIONS" ~

TABLE 2+3.6-3C IIIND DIRECTIOtl PERSISTENCE DATA +

ltARRIS ON&ITE NETEROMCICAL FACILITT JANUARY 14, )976 TO DECEHBER 3li 1978 STABILITT CIASS C LUMEk NUNBEk OF OCCURREIICES lllND DlltECTION PERSISTEtjCE (HOURS)

LEVEL MIND DIRYCTIUtt I 4 5-7 8-10 11-)3 14-16 17-19 20 "22 23 "25 25 tt 198 55 28 11 ll HHY. 206 44 37 17 4 IIE 218 53 16 15 3 VNE 200 35 27 6 2 190 31 18 5 1 VSE 165 27 8 3 2 SE 14u 17 10 3 SSV 128 20 6 2 150 30 12 3 3 SSM 1b3 27 15 7 2 Slt 135 31 19 6 3 MSM 161 15 6 4 6 M 131 12 6 1 1 utat 126 9 I 2 125 16 ll 3 1 6

tt HM 171 21 17 1 AVEkACV 1.0 2. 0 3. 0 4. 0 5. 7 8.6 11.0 0.0 0.0 0.0 0.0 0.0 DURAT IUN IIUUKS tIAX1NN'I 1 10 HOURS IIUttBER IIUUkS UY IILSSIHG MIND DIRECTIUttSt 67

• PERSISTENCE IS DYFItIEII AS h DELTA T EXISTINC MITNIN h DEFINED 'PIND DIRECTIOtl SVCTOR AHD IS ttOT CONSIDERED TU BE INTERRUPTED IF IT IIEPARTS FtIOtl TIIAT DEI.TA T VALUE FOR UP TO I HOUR AND THYN RETURNS, OR IF TIIEKE IS OtIV IIUUR UV ttlbSING DATA FOLLOMYD BT h COtITIHUED DELTA T VALUE. 'TMO OR NORE CNISECUTIVE I)OURS OF LOST DATA ARE NOT INCLUDVII IN TIIY PEkSISTEHCE DETYRNIIIATION BUT ARE INDICATED AS "IIISSIHC MIND DIRECTIONS" ~

v~

ThBLE 2.3,6-3tl MIND DIRECTION PERSISTENCE DhTh +

IlhRRIS ON<ITY. HETEROLOGIChL FhCILITY JhNUhkY 14>> )976 TO DkCEtIBER 31, 1978 S LaltthRY LOLAI k IIUHBER OP OCCURRENCYS MIND DIRECTION PERSISTENCK (HOURS)

LEVVI MINI)

DlkVCTIUN 4 5-7 8-10 Ii -$ 3 14-i6 17-19 20-22 23-25 25 tt 396 168 101 50 84 30 14 ttNE 440 153 95 66 62 20 7 HV 463 130 65 41. 47 19 7 EIIV 399 110 60 31 39 6 7 V 375 89 58 25 .22 11 1 kSV 36L 87 43 27 22 2 358 88 36 19 20 3 SSY 394 99 53 35 41 LO 434 149 86 54 62 13 451 182 94 74 93 31 SM 445 158 1 11 61 93 27 MSM 410 123 77 47 62 20 M 393 97 56 25 25 7 urat 369 83 61 30 38 17 366 90 68 43 54 8 H tat 421 107 84 45 55 16 hv ktthCK 1.0 2. 0 3.0 4. 0 5. 7 8. 8 1). 7 14. 9 17. 7 2U. 8 24. 0 29. 6 UURATIULI ILUULIS HhXIHUII I 10 13 16 19 22 24 30 HOURS NUILBVR IIUURS OF ttISSING IIINU DlkECTIOIISt 371

• YERSISTEIICE IS DEFINkD hS h DELTh T YXISTINU MITNIH h DEFINED IIIND DIRECTIOII SECTOR hHD IS IIOT CUNSIDERVD TO BE IIITKRRUYTED IF IT DEYhkTS FkOII TtlhT DELTh T VhLUE FOR UP TO I HOUR htID TIIEN RETURIIS>> OR IF THERE IS ONE IIOUR UF HISSltIG DhTh FOLLOMKD BY h COHTINUED DELTh T VhLUE. TMO OR HORE CONSECUTIVE tiOURS OP hOST DhTh hRE HOT INCLUUL'D Itt TIIV. PEkSISTEHCE DETERHIHhTION BUT hRE INDIChTELI hS "HISSItIG MIIID DIRECTIOIIS"~

TABLE 2,3,6-31 IIIND DIRECTION PERSISTENCE DATA +

HARRIS ON-SITE NETEROUIGICA! FACILITY JANUARY 14 ~ 1976 TO DECEHBER 31, )978 STABILITY CLASS h UPI'EK NUIIBER OF OCCURRENCES - QIND DIRECTION PERSISTENCE (IIOURS)

LEVEL QIHU DlRVCTION 2 3 5 7 8 10 ll 13 14 - 16 17 19 20 22 23 - 25 ( 25 N 3B 22 IINV 39 ll NV 15 10 ENY 12 6 Y -15 3 ESY 12 3 SV. 6 2 1 SSE 9 3 S 23 6 1 SSU 31 13 6 9 6 Slt 40 18 22 6,p 8 1 USU 4U 17 '7 6 lt 29 13 6 3 Ittht 37 16 9 7 8 HII 33 14 10 8 2 Ntttt 23 16 6 3 8 2 AVERhcV. l.u 2.0 3.0 4.0 5.4 82 00 00 00 0.0 0.0 0.0 DUIIATIUN HOURS IIAXINDI! I IIU URN ttINIBVit tiUUBS UF IIISSIIIG MINII DIRVCTIOtlSI 13

~1'EIISISTEHCE IS DEFINED AS h DELTA T EXISTING HITHIN h DEFINED HIND DIRECTION SECTOR AND IS NOT COtlSIDERED TO BE 1 UTER R OFTEN IP IT I I DEPARTS FROkl TIIAT DELTA T Vh WE FOR UP TO 1 llOUR AND TIIEH RETUI< tlS ~ OR P 1 IIEIIE S OHE IIOUR Oi'IISSING DATA FOLLOWED BY h CONTINUED DELTA T VALUk;, TIIO OR klORE CONSECUTIVE llOURS 01'OST DATA ARE NOT INCLUDED Itl THE PERSISTENCE DETERHIHATIUN BUT hltE INDICATED AS kllSSINC IIIND DIRECTIONS ~

ThBIZ 2+3.6-3J ltIHD DIKVCTIOtl I'ERSISTEIICE DhTh <<

IthkklS ON-SITE NETEROLOGIChL FhCILITY JhtluhkY 14, 1976 TO DECENSER 31, l978 SThklLITY ClhSS 8 UI'1'EK tlQIBER OF OCCURRENCES MltID DIRECTION PERSISTENCE (HOURS)

LEVEL MIHII U1kECTIUH I 2 5-7 8-10 ll -13 14 - i6 17-19 20-22 23-25 ( 25 tt 39 ll HNE 4U 6 HV 32 Ettk 21 5 20 15 4 SE 9 2 SSV, 20 2 18 7 SQI 41 ll SM 66 12 MSII 47 14 M 32 4 Mtht 49 18 HH 44 9 IUnt 42 hVEkhCE I.U 2.0 3.0 4.0 5.3 0.0 0.0 O.II 0.0 0.0 O.U 0.0 UUkATIUN IIUURS NhXIttUtt 1 IIOURS IISIIIEI( UUUIIS OF IIISSIHG MIND DlttECT1088t 4

<<FERSISTEIICE IS DEFINED hS h DELTh T VXISTIHG MITHIN h DEFIIIED MIND DIRECTION SECCOR hHD IS NOT CONSIDERED TO BE ltiTVkkUP'I'EU IF IT UVFhkTS FROII TtlhT DELTh T VhWE FOR UP TO 1 HOUR hHD TIIEN RETURNS, Ok IF TIIERE IS OtIE HOUk UF NISSIHG DhTh FOLLOMED BY h CONTINUED DELTh T VhLUE, TMO Ok tIORE CONSECUTIVE HOURS OF LOST DhTh hRE HOT INGLUUEU It( '1'HE VERSISTEIICE DETERHIHhTION BUT hRE INDIChTED hS "NISSltlG MIND DIRECTIOIIS"~

ThBLE 2+3+6-3K MIHD DIRECTION PERSISTENCE DhTh

• lthRkIS OH% ITS HETKROLOGIChl FhCILITY 4hNUhRY l4, l976 TO DECEHBEk 3l ~ I978 SThBILITY CLhSS C UPPKt( NUHBKR Of OCCUkRENCES - MIND DIRKCTIUtl PERSISTKHCF. (ItOURS)

LEVEL MIND UIRKCTIUtt l 2 3 4 5 - 7 B - lO ll l3 l4 - l6 l7 - l9 20 22 23 25 ( 25 tt 62 l5 Nttk 53 6 NK 42 6 ENF. 35 7 E 29 4 KSK l9 2 SL' ll 22 6 37 9 SSM e4 l2 Stt l5 ltSM 69 l4 5l l0 Mtht 55 6 ttM 62 l4 HNM 65 lo hVKkhGE l.U 2.0 3aO 4.0 5.0 0,0 ll,O 0.0 0.0 0~0 0.0 0.0 DURhTIUH IIUURS HhXIttUtl ttOURS NUHBElt IIOUttS Ot'tISSlttG MINU DlkKCTIOttSt 7

~PKRSISTKNCK IS DEFINED hS h DELTh T EXISTING MITtlltt h DEFINED MlttD DlkKCTIOtt SECTOR hND IS NOT CONSIDERED TO BE IHTEkkUPTKtt It'T DEPhkTS FROtt TtthT DELTh T Vhulf FOk UP TO l IlOIJR hHD THEN RETURNS, OR ff TttERE IS ONE ltOUR OF HISSIHG DhTh FULLOMED BY h CONTINUED DEITh T YhLUK TMO OR NORE COttSECUTIPE ttOURS OF LOST DhTh hRE NOT IttCLUUKU ltt T11E PERSISTENCE DKTERHItthTIOH BUT hRE INDIChTED hS "HISSINC MIND DIRECTIOttS" ~

Thklg 2.3.6-3L MIND DIRECTIOI) 1'ERSISTVNCE DhTh

• lihkRIS Ok(WITE NETEROLOCIChL FhCILITY JhHUhkY 1$ , 1976 TO DECEHBER 31 ~ 1978 SThBII.ITY CLhSS D UI'('hk HUHUER OF OCCURKEHCVS MIND DIRECTIO(i PERSISTENCE (((OURS)

LEVEL MIND UIKEGTIUtt 5"7 8-10 ll -13 14 -16 )7-19 20-22 23-25 25 N 126 51 18 14 24 NWY 119 54 31 )2 27 NE I It( 34 19 7 16 V.NY. 107 36 25 5 8 77 28 13 7 6 YSV, 79 25 12 3 3 89 28 6 7 5 SSE tik 34 15 7 14 122 49 19 11 4 SSI( 181 65 25 16 17 182 71 41 l9 23 MSM 161 60 22 18 12 It 139 31 19 4 4 Mt(M 128 15 5 6 t(M 126 33 ll 20 10 t(t(U 126 44 23 6 12 hVEkhGE i+0 2.0 3.0 4.0 5.5 86 11 3 14 5 17e7 0.0 24.0 34.0 DUkhTIOII I(UUkS 15 24 kihXlk(UH 1 I(UUkk t(Ut(krak HOURS OF HISSlt(G i(It(U DlkECTIONSt )Ot

• PERSISTENCE IS DEFlt(ED hS h DEI.Th T FXISTIHC WIT((ltt h DhFINED MIHD DIRECTION ShCTOR hND IS NOT COHSIDEItED TO UE INTVKRUPTYD IF IT DEPhkTS FROM Tith'T DELTh T '+IJIE VOR UP TO 1 HOUR hND Ti(EH RETURNS, OR IF TIIEI(E IS 0(IE I(OUR Ot'ISSINC DATh FULLOMYD RY h CONTI((UED DYLTh T VhLUE TMO OR NORE COHSECUTIVE I(OUI(S OF LOST DhTh hRE NOT INCLUDED IN TIIE PERSISTENCE DETEKHINhTIOII RUT hkE IHDIChTED hS "HISSIHG 'MII(D DIRECTIOt(S" ~

TASLE 2+3+6-3H IIIND DIRECTION PERSISTENCE DATA +

IIARRIS 0)LAITY HETEROLOCICAL FACILITY JANUARY 14, 1976 TO DKCEHBER 31 ~ 1978 STASIL/Tf CLASS E Ut'I'Ett NU)ISER OF OCCURRENCES - MIND DIRECTION PERS/STEHCE (I)OURS)

LEVYL MINI)

DIRVI:Tlutt I 4 5 7 8-10 11 -13 14-L6 17-19 20-22 23-25 25 tt 124 34 9 12 15 NNY. 97 36 16 13 16 IIE 110 34 19 ll ll ENY 74 20 13 10 9 E 90 26 9 9 V.SE 71 19 ll 7 5 26 5 3 SSE lu4 36 22 7 17 2 144 51 37 21 28 5 SSM 189 71 34 24 30 15 SM 201 44 21 16 13 3 MSII 131 43 21 5 13 M ill 27 6 6 5 Mtht 100 32 14 10 2

)IM 82 26 13 6 15 Ntht 118 28 16 5 6 AVE)(ACE 1 0 2.0 3.0 4~0 5.6 8.6 11 7 -15 3 0 0 0.0 0 0 0.0 DURATION NOUI(S HAXI)IUH I 10 13 IIOUIIS NU)iSEN HOURS Ui'IISSIHC HIND DIRECTIONS) 32

+PEIISLSTENCE IS DEFINED AS h DELTA T YXISTINC MITNIH h DEFlt)YD ltIND DIRECTION SECTO)t AHD IS HOT CONSIDERED TO BK INTERIIUPTVD IF IT DEPARTS FROH TIIAT DELTA T VAIAIE FOR UP TO 1 IIOUR AND THEN RETURIIS, OR IF THERE IS ONE HOUR OF HISSIHC DATA FOLLOMED SY h CONTINUED DELTA T VALUE. TMO OR HORK COIISECUTIVE IIOURS OF LOST DATA ARK NOT IHCLUUVI) Itt TILE PERSISTVNCE DETERHINATIOH BUT ARE INDICATED AS "HISSIHC MIND DIIIECTIONS"~

TARLE 2,3,6-3H WIND DIRECTIOII PERSISTEtICE DATA <<

IIARRIS OH-SITY HETEROLOCICAL FACILITY JANUARY 14, 1976 TO DECEHBER 31 ~ 1978 STASILIT'Y CLASS F UYYEIC NUHREk OF OCCUkICEHCES - MINII DIRECTIOtl FERSISTEtlCE (IIOURS)

LEVEL WLNIJ D 1kEC"I IOH I 4 5-7 8-10 11 -13 I

14 -16 17-19 20-22 23-25 25 tt 79 19 13 8 2 IINE 66 23 4 5 3 tIE 67 15 9 3 3 EIIE 5U 18 5 3 1 E

ESE 54 17 ll 2 ~ 2 64 15 7 3 53 15 1 1 2 SSE 73 23 8 1 S ee 36 ll ll 10 1' SSII 106 52 16 l3 16 Slt MSII 1U2 100 44 ll 18 7 34 10 6 7 M 73 18 7 4 5 MNM 68 9 9 3 1 NW 77 9 4 1 IUIM 7IJ 18 7 2 AVYICACY. 1.0 2.0 3.0 4.0 5.6 8.3 11.0 0.0 0.0 0.0 0.0 0.0 IJUkhTltttt II OURS tlhXIJIII I IIUUKS t<Ntekk NOUke OF ttISSING WINIJ UIRECTIOIISJ 16

<<PEICSISTENCE IS DEFltIED AS A DELTA T EXISTING MITIIIH h DEFIIIED MIND DIRECT10tl SECTOR AIID IS NOT COIISIDERED TO SE IIITEICRUPTED IF IT DYPhkTS FROII 'IIIAT DELTA T VALUE FOR UP TO 1 HOUR ANIJ TIIEH RETURNS ~ OR IF TIIERE IS OIIE IIOUR OF tIISSINC DATA FOLLOWED RY h COtITIHUED DELTA T VALUE. TMO OR NORE CONSECUTIVE IIOURS OF LOST DATA ARE HOT INCLUDL'IJ ltI TNL'ERSISTENCE DETERHINATIOH BUT ARE INIJICATYD AS HISSINC MItID DIRECTIOIIS ~

TABLE 2.3.6-30 MIND DIRECTIOtl PERSISTENCE DATA +

HARRIS ONWITK NETEROLOCICAL FACILITY JANUARY 14, 1976 TO DECEHBVR 31, 1978 STABILITY CLASS C UPPER NUNBFR OF OCCURREHCKS WIND DIRECTION PERSISTENCE (I!OURS)

I.EVEL MINU D I ltECTIUtl 4 5-7 8 - l0 ll 13 14 16 )7 - )9 20 - 22 23 25 25 N 65 19 18 7 6 HNK 68 26 ll 7 7 HE 56 26 . 12 5 7 KHE 68 22 13 4 9 44 28 ll 6 ESE 4l 25 15 6 6U 26 ll 5 2 SSE 56 32 16 IO 12 82 36 l7 16 l2 SSM 95 53 26 22 22 6 SM 113 56 26 18 16 3 MSM 69 50 37 28 27 9 M 97 29 22 ll 5 1 Mtht 92 31 16 8 9 1 ttM 90 32 15 II 3 I Hkll 7u 36 16 9 8 AVEkhCE I.U 2.0 3.0 4.0 5.6 8.5 I I~ 6 0.0 0.0 20.0 "

0.0 0.0 UUIIATIUtl IIOURS NAXltlUII I l2 20 IIOUKS tllltBER HOURS OF IIISSINC MltlD DIRECTIOttSc 38

~PERSISTEIICE IS DEFItlED AS h DELTA T EXISTIHC WITHIN h DEFINED MIND DIRECTION SECTOR htlD IS NOT COtlSIDERED TU BE INTEkkUPTED IF IT UEPhkTS PRON TIIAT DELTA T VALUE FOR UP TO I HOUR AND THEN kETURHS ~ OR IF TUEkE IS ONE HOUR OF IIISSINC UATA FOLIAIMEU BY h CONTItlUED DELTA T VAUIE. TMO OR MOkE CONSECUTIVE HOURS OF LOST DATA ARE NOT lltCLUDEU IN TUE I'ERSISTENCE DKTERHINATIOH BUT ARE INDICATED AS "HISSINC WIND DIRECTIOtlS"

ThRLE 2,3.6-31'I)iD DIRECTION 1'ERSISTEHCE DhTh <<

NhRRIS ON-SITE NETKROLOCIChL FhCILITY ahttuhRY 14, )976 TO DFCEHRFR 31, 1978 Stk)NhRY I

UP)'L'k NUttkER OF OCC)lRREHCES - MIND DIkECTION PKRSISTEHCK (t)OURS)

LEVEL MIND DlkKCTIUN 5-7 8 " 10 11 13 14 - )6 17 19 20 22 23 25 25 tt 197 113 67 50 79 24 15 HNE 199 123 69 36 76 37 8 HE 225 100 52 34 52 24 10 KNK 195 84 55 23 48 12 6 K 135 83 46 23 35 13 4 FSK 169 7& 55 29 33 3 184 83 30 28 27 6 1 181 97 60 34 73 13 4 231 137 85 60 93 15 13 SSW 252 149 94 72 137 44 17 ll SW 332 155 1 1 1 66 108 15 4 MSW 241 156 102 60 99 38 17 2 W 319 122 61 33 48 9 2 2 Mt)U 248 92 6& 38 52 23 10 2 NW 249 97 54 54 62 15 5 3 IItht 235 114 87 36 50 21 5 4 hVEkhCK l. 0 2. 0 3~0 4. 0 5. 7 8.7 11.6 14.8 17.7 20. 7 23. 5 32. 2 DUkhTIOtt I)OURS tthXINU)l 1 3 10 13 16 19 22 24 37 ttUUltS NUttkktt HUUt(S 0)'tISSIHG WIND DIRKCTIOttst 374

<<PERSISTENCE Is DK)'INED hS h DELTh T EXISTIHC MITtlIti h DEFINED MIND 1)IRECTIO)i SECTOR htiD IS HOT COtiSIDERED TO UE IHTEkkUPTED IF IT UEPhkTS FtlOtl TtthT DELTh T Vh!.UE FOR UP TO 1 llOUR hHD THEN RETURNS ~ OR IF THERE IS OHK llOUR DF I)ISSII)C DhTh FOLLOWED UY h COt)TINUED DKLTh T VhLUE TMO OR )lORE CONSECUTIVE IIO)IRS OF LOST DhTh hRE HOT INc).UDED IN TUE PERSISTEHOE DKTERHINhTIDH 8DT hRF 1NDIchTED hs "t)lssittc MIND DIREOTIO)ts".

SHNPP ER 2+4 HYDROLOGY 2o

4.1 INTRODUCTION

The Shearon Harris Nuclear Power Plant is located in the Buckhorn Creek basin, as shown on Figure 2.4.1-1. Buckhorn Creek is a tributary of the Cape Fear River, as shown on Figures 2.4.1-2 and 2.4.1-3. Buckhorn Creek and the Cape Fear River are the sources of surface water for the Main and Auxiliary Reservoirs for plant operation. Details of the Cape Fear River drainage basin and its relationship to Buckhorn Creek are shown on Figure 2.4.1-3.

The principal source of water for SHNPP is the Hain Reservoir, which is impounded by an earth dam located on Buckhorn Creek just below its confluence with White Oak Creek. In addition to natural runoff, the water inventory in the reservoir system is augumented by pumping from the Cape Fear River.

Preexisting ponds and impoundments (shown on Figure 2.4.1%), which were located within the boundary of the plant site, are not used for plant operation; none were located within"the boundary pf the plant island. Those which were located in the reservoir areas have been inundated by filling the reservoirs In addition to the Main Reservoir, an adjoining and independent Auxiliary Reservoir was constructed for emergency core cooling purposes. The Auxiliary Reservoir is on Tom Jack Creek near the plant. Buckhorn Creek's five tributaries (Tom Jack Creek, Thomas Creek, Little White Oak Creek, White Oak Creek, and Cary Creek) have been impounded by the Hain Dam. A nameless tributary of Little White Oak Creek is located on the western half of the plant island, where grading raised the plant elevation to 260 ft. msl. The plant will not be subjected to flooding, since the design grade is well above the maximum water levels caused by the Probable Maximum Flood on the streams and reservoirs.

An outline of the small watersheds near the plant site is presented on Figure 2.4.1%; this figure shows the small drainage areas and their divides before constxuctio'n of the project. Comparison of Figure 2.4.1% with Figure 2.4.1-5 shows that construction of the project has not materially changed the drainage pattern.

Rivers, creeks, lakes, reservoirs, and ponds existing within a 5~ile and 25~ile radius of the plant site are shown on Figures 2.4.1-6 and 2.4.1-7,

'respectively.

The plant site is located in an area that has'ery little groundwater; groundwater is discussed in Section 2.4.3. Radionuclide release from the plant and possible groundwater pathways are discussed in Section 2.4.4. Users of surface water and groundwater are discussed in Section 2.4. 5.

2.4.1-.1

0 1

t' J

)

SHNPP ER 2e4o2 SURFACE MATER HYDROLOGY 2.4.2. 1 Introduction Materways and bodies of water within a 50~ile radius of the plant site (Figure 2.4. 2-1) which could receive liquid releases from the SHNPP are only those downstream of the site, via Buckhorn Creek and the Cape Fear River. The Cape Fear 'River basin, for a distance of 50 mi. downstream from the site, is characterized by transition from the Piedmont area to the Coastal Plain. The low water profile of the Cape Fear River drops about 125 ft. from Buckhorn Dam at river mile 192 to Lock and Dam No. 3 at river mile 123, a gradient of 1.8 ft./mi. The terrain changes from rolling hills and a relatively narrow river valley near the site to nearly flat terrain below the confluence of Little River.

The Cape Fear River basin (Figure 2.4.1-3) is oblong in shape; its greatest width is about 60 mi. and its length is about 200 mi. The Cape Fear River is formed by the confluence of the Deep and Haw Rivers. It flows generally southeast about 19$ mi. and empties into the Atlantic Ocean at Cape Fear, approximately 28 mi. below Wilmington, North Carolina. The basin has a total area of 9,136 sq. mi., of which 3,127 sq. mi. are located above the confluence of the" Deep and Haw Rivers.

The lower Cape Fear River is an estuary; the tidal reach of the river extends to Lock and Dam No. 1 (at river mile 67), which is about 39 mi. above Wilmington. The river is navigable to Fayetteville, with a channel width of generally 400 ft. and depth ranging from 30 to 35 ft. from the Atlantic Ocean to Wilmington.

The average width of the Cape Fear River flood plain is approximately 2.2 mi.

The difference between high and low stages is 69 ft. at Fayetteville and 44 ft. at Lock No. 2. The maximum flood flow of 150,000 cfs occurred on September 19, 1945 at Lillington.

The monthly average flows of the Cape Fear River at Buckhorn Dam, shown in Table 2.4.2-1, were obtained from the records at Lillington by a drainage area ratio of 3,196 sq. mi. at Buckhorn Dam to 3,440 sq. mi. at Lillington.

Historical low flows were derived for the Cape Fear River at Buckhorn Dam from the Lillington data, and are presented in Table 2.4.2-2. Figure 2.4.2-2 shows the flow duration curve at Buckhorn Dam', and Figure 2.4.2-3 presents the low flow frequency analysis. The minimum daily flow of 10 cfs occurred on October 14, 1954; the seven consecutive day ten-year low flow is 72 c fs at Buckhorn Dam.

The flow duration curve shown on Figure 2.4.2-2 does not take into consideration the effect of the U. S. Army Corps of Engineers comprehensive plan of development of water resources for the Cape Fear River basin (keference 2.4.2-1). The completion of the proposed dams will furnish a minimum continuous flow of 600 cfs at Lillington; consequently the 600 cfs flow will be. equalled or exceeded 100 percent of the time (except in years of

2. 4. 2-1

SHNPP ER severe drought) ~ In addition, flood peaks will be substantially reduced because of the retention capacity of the reservoirs.

2. 4. 2. 2. 1 Tributaries The Cape Fear River has many tributary creeks, including approximately 30 that are more than three miles in length, in the area downstream of Buckhorn Dam.

There are three major tributaries (Upper Little River, Little River, and Rockfish Creek) which drain the western portion of the basin. Most of the eastern part is drained by tributaries of the Black River, which enters the Cape Fear River at river mile 44, and is not within the region of influence of the SHNPP. There is only one small impoundment of concern, formed by Buckhorn Dam just upstream from the mouth of Buckhorn Creek. The maximum storage is 1600 ac.-ft., and it was used for hydroelectric power generation from 1908 until 1962. This Cape Fear River impoundment is the source of make-up water for the SHNPP reservoir system. Any release from the SHNPP would affect only the Cape Fear River below Buckhorn Dam and the lower reaches of its tributaries. However, under flood conditions, backwater could extend further upstream. Table 2.4.2-3 lists the tributaries, the locations of their confluence with the Cape Fear River, and the estimated extent of backwater flooding during the flood of September 19, 1945, the largest one ever recorded (Reference 2.4.2-1).

Table 2.4.2% gives important flow characteristics for all of the USGS gaging stations within the area of interest (References 2.4.2-2 and 2.4.2-3).

The Cape Fear River has two major tributaries above Buckhorn Dam, the Haw and Deep Rivers, both of which originate in Forsyth County, North Carolina. The Deep River has a total length of 116 mi. and a drainage area of 1,422 sq. mi.

The Haw River is about 90 mi. in length and drains approximately 1,705 sq. mi.

Both rivers originate at elevations of about 1,000 ft. msl and have numerous falls and rapids; the Haw River has the steepest gradient. The elevation of the junction of the two rivers is about 158 ft. msl.

Buckhorn Creek is a tributary of the Cape Fear River; its confluence with the Cape Fear is gust downstream of Buckhorn Dam, as shown on Figure 2.4.1-1.

I 2.4.2.2.2 Dams, Reservoirs, and Locks on the Cape Fear River There are a number of regulating structures and reservoirs on the Cape Fear River. The locations of these structures and reservoirs are shown on Figure 2.4.1-3. Lock and Dam Nos. 1, 2, and 3 are located at river mile points 67, 99, and 123, respectively. Buckhorn 'Dam is at river mile 192, and its spillway crest is at Elevation 158.18 ft. msl.

In addition to the existing Lockvtlle Darn and'arbonton Dam.on the lower reach of the Dee'p River, the U. S. Army Corps of Engineers has proposed a comprehensive plan of development of water resources for the Cape Fear River basin; a summary of this plan is shown in Table 2.4.2-5.

2.4.2.2.3 Streamf low Analysis Since the Cape Fear River is a major source of makeup water for the Main Reservoir,,the record of flows of this river at Lillington were analyzed to 2.4. 2-.2

SHNPP ER

~ partial derivative with respect to X BX

~ partial derivative with respect to Y BY The wind stress is computed by the following formulae: (Reference 2.4.2-5)

Tsx/o 1'1 x 10-6 W2 cos. u Tsy/a = 1.1 x 10 W sin a where: W wind speed a ~ angle of wind direction The current velocity is coinputed from stream functions as follows:

X - component of current velocity U H BY Y component of current velocity V =

H BX

.The current speed and direction in terms of angle counterclockwise from the east direction are, respectively, W ~ U2+V2 and TAN-1 V U

Due to its small size, wind induced currents in the Auxiliary Reservoir will be insignificant.

2.4 ~ 2.3.2,4 Reservoir Temperatures Seasonal surface water temperature variation of the reservoirs was analyzed according to typical energy balance methods; the analysis used the meteorological data shown in Table 2.4.2-20. By taking into accoun the conservation of energy, the major heat transfer mechanisms between the reservoirs and the atmosphere were developed to calculate natural equilibrium temperatures. The major heating processes include solar and atmospheric radiation, and the significant cooling processes include reflected radiation, emitted radiation, conduotion, and evaporation. Streamf low through the reservoirs and Cape Fear River makeup water are not significant in the annual energy budget. Since cooling tower blowdown is from the cold water basin, it does not have a significant effect outside of the designated mixing zone.

2. 4. 2-11

SHNPP ER Calculated natural 'equilibrium temperatures for the reservoirs range from approximately 39 F in the winter to approximately 82 F in the summer. Monthly temperatures are shown in Table 2.4.2-20. Monthly cooling tower 'blowdown temperatures are shown in Table 5.1.2-1.

2.4.2.3. 2.5 Reservoir Morphometry The Main Reservoir has a surface area of approximately 6.5 sq. mi. and an overall shoreline length of about 40 miles at the normal operating level of Elevation 220 ft. msl. Since the reservoir is formed by backwater inundation into downstream reaches of several tributary streams, its overall shape is dendritic. The reservoir is generally narrow with a slightly wider region at the main trunk area. The width varies between approximately 1000 and 4000 ft.

There are seven ma5or branches with lengths ranging from 1 to 4 mi.

The reservoir bottom is relatively flat at the main trunk area with elevations varying from 175 ft. msl at the downstream (south shore) end to 195 ft. msl at the upstream (north shore) region. The northern portion of the main trunk has a nearly constant depth of about 35 ft. and a steep shoreline on the east side. The depth, however, becomes variable toward the west shore, where the bottom slope is approximately 1 in 40. The southern portion of the main trunk is flat, with an average depth of about 45 ft. Bottom contours as well as shoreline configuration are shown on Figure 2.4.2-24.

At the normal operation level of Elevation 252 ft. msl, the surface area of the Auxiliary Reservoir is approximately 0.55 sq mi. and the average depth is about 20 ft. There are about seven, miles of shoreline. The reservoir consists of three branches, each roughly one mile in length and 1000 ft. in width. The bottom cross sections are generally V.-shaped, sloping on the order of 1 in 15 toward the shores. Bottom contours and shoreline configuration are shown on Figure 2.4.2-24.

2. 4.2. 3.2. 6 Reservoir Sedimentation To estimate the effect of sedimentation on the Main Reservoir bottom and shoreline configuration, a conservative sediment rating- formula was deduced from sediment sampling data of Buckhorn Creek (Reference 2.4.2-6) by a regression analysis, using the equation:

SD 0.0163 ql'56 in which SD ~ daily sediment load, including suspended and bed materials, in Tons/Day and daily streamf low of Buckhorn Creek. at Corinth, N.C., in cfs ~

To estimate the total sediment load for the plant life of forty years, synthetic daily streamflows of Buckhorn Creek at Corinth, North Carolina, were generated for the same time period. The synthetic generation utilized five years (1972-1977) of daily streamf low records of Buckhorn Creek, and thirtymight years (1940-1977) of monthly streamf low records of the nearby Middle Creek (Section 2.4.2.3.1). Two models by HEC (U. S. Army Corps of 2.4. 2-12

ThBLE 2.4 ~ 2-21 hUXILIARY RESERVOIR OPERhTIUH LOSS OF hl.L OTHER MhTER SOURCES SINULThNEOUS hCCIDEHT CONDITION IH ONE UNIT hHD HORIlhL SHUTDONH OF THREE UHITS Morat Hater Levol Natural Total Sutuaation Residual In huxiliary Tine Inst. Forced Evap. Storage of Storago Pond at ht ter IIeat hvg For Effective Unit Evsp. Forced Evap. During Use ln Storage ht End of End of hcc Ment ke)ection Period Agee Load Rate During Period Period Period Use Period Period no IU Stu/Nr IU Btu/hr 10~ f ~Bt sE/hr tn/ o in ac. ft. in ac. ft. sc. ft. ac. ft, aci ft. fr.

U.U 1270 4400 250' 600 . 9,31 64. 5 . 5. 87 1.47 26 2. 3 58 84 84 U. 25 257 4316 249. 7 243 9. 15 '26. 6 2. 27 Uo 57 10 2. 3 58 68 152 UQ 25 257 4248 249. 4 223 8. 97 24. 9 2.04 0.51 9 2.3 58 67 219 U. 50 229 4181 249. 3 214 8. 92 24.0 2.04 0.51 9 2.3 58 67 286 U. 75 217 '05 4114 249. 0

8. 85 23. 2 2. 13 1.07 19 4. 25 106 125 411 DUO 21U 3989 248. 4 195 8. 72 22.4 1. 92 0. 96 17 4. 25 106 123 534

l. 5U 199 3866 249. I 187 8. 60 21 7 I 73 0.87 16 4.10 103 119 653 2+ UU 3747 247. 8 180 8. 50 21 ~ 2 I ~ 62 0. 81 14 4. 10 103 117 770 2 ~ 50 183 3630 24I7 ~ 2 175 8.29 21. I I ~ 56 O. 78 14 3. 89 97 III 881

3. UV 177 3519 246. 9 170 8.20 20.7 I ~ 62 0. 81 14 3. 89 97 111 992

3. 5U 173 3408 246. 5 4.00 167

SHNPP ER 2.4.3.2.1 Hydraulic Charac ter is ties a) Overburden The plant area is covered with residual soils. derived from the underlying rocks. The numerous soil borings drilled in the plant island area as well as in the Auxiliary Reservoir area, confirm the existance of up to about 15. ft.

of clayey soil and saprolite overlying the Triassic rocks. The excavation and mapping of trenches in the plant area, as well as the excavation and borings for the site fault investigation (Reference 2.4.3-2) also indicate the preponderance of clayey. and silty loam soils.

The U. S. Soil Conservation Service soil survey of Wake County, 1970, classified the site soils as the Creedmoor-White Store Association (Reference 2.4.3-3) ~ Some typical engineering properties of the Creedmoor&hite Store soil series, as mapped in the site area and taken from the U. S. Soil Conservation Service soil survey of Wake County, 1970, are listed below. They indicate that the Creedmoor-White Store soil conditions are relatively impervious. The surficial clay and saprolite zones prevent ready recharge to the rocks below them, as indicated by the general dry state of these rocks (Re fer ence 2. 4. 3-2) .

CREEDMOOR+fHITE STORE ASSOC IATION CREEDMOOR SOIL SERIES (T ical Profile)

PERCENTAGE PASSING SIEVE DEPTH No. 200 PERMEABILITY SHRINK-SWELL (in.) TEXTURE (0.074 mm) (in. er hr.) POTENTIAL 0-12 Sandy loam 30%5 2.0 6.3 12-29 Clay loam 35-85 0.63 - 2.0 Moderate 29-58 Clay 70-95 0.2 High 58-96 Clay 35-90 0.2 Moderate b) Triassic Rocks The plant site and peripheral lands are underlain by Newark Group rocks (Triassic) which are the only source of groundwater at the site. They consist of claystone, shale, siltstone, sandstone, conglomerate, and fanglomerate. An exception to this lithology is the intrusion of thin diabase dikes in the rock; these dikes were mapped in connection with the fault investigation in the plant and the Auxiliary Dam.areas (Reference 2.4.3-2 and 2.4.3A). The diabase'rock is weathered near the surface and is unweathered below depths of about 20 ft.

The primary permeability of Triassic rocks is very low and the rocks appear to be essentially dry. Some lenses of relatively higher permeability rock exist within the Triassic rocks; however, they are not extensive and are surrounded by materials of relatively lower permeability. The Triassic rocks have 2.4.3-3

SHNPP ER fractures that have resulted from stress releases. These fractures provide secondary permeability in the rocks and are filled with water below the water table. The fractures are common to depths of about 100 ft., but become less prevalent and tight below that depth. Below about 400 ft., the fractures are closed and sealed to water flow (as shown by tests and experience gained through private well drilling in the area). Recharge in the area occurs by percolation of precipitation through the overburden. Host of the precipitation, however, is either lost back to the atmosphere through=

evapo-transpiration or becomes surface runoff. The predominance of surface and near-surface deposits with extremely low permeabilities results in rapid runoff of precipitation. Therefore, natural recharge to the aquifer occurs at a very low rate.

The precipitation which percolates downward is confined laterally by the diabase dikes and vertically by the absence of open fractures or joints at depth in the Triassic rocks. Numerous attempts to develop groundwater supplies from the Triassic rocks have been unsuccessful since these rocks are tight and relatively dry. However," groundwater is developed in the Triassic basin from hornsfels zones adjacent to diabase dikes. The relationship of dikes and fractures to groundwater flow is illustrated diagrammatically on" Figure 2. 4.3-2.

Even though Triassic rocks constitute the major aquifer within the site environs, the aquifer exhibits very low permeability for groundwater storage and movement. Of the 57 wells with an average depth of 158 ft. constructed in the Triassic formation in western Wake County, 16 percent yield less than 1 gpm with the average production at 5 gpm. Such relatively low permeability indicates that the Triassic formation is the lowest productive aquifer in the region (Reference 2.4.3-4). Numerous borings carried out for soil and geologic information in the plant site and reservoir areas confirm the very low permeability of the Triassic formation.

Six site wells located in the proximity of the diabase dikes yielded specific capacity values from 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> driller's tests that ranged from 0.16 gpm/ft. to 0.59 gpm/ft. These specific capacity values correspond to transmissivity values of about 40 ft. /day to 130 ft. /day (Reference 2.4.3-5).

2.4.3.2.2 Onsite Use of Groundwater Seven wells were completed during 1973 and are being used during the construction phase. Additionally, eight new wells were developed in the proximity of diabase dikes during 1977-1979. Site wells are listed in Table 2.4.3H and are shown on Figure 2.4.3-5. Groundwater is being used at the site during the construction phase for (1) concrete batch plant and concrete placement, (2) office and plant use, and (3) grouting. Groundwater is not expected to be used for plant operation after the plant potable water system is installed. The estimated plant water requirements projected through the year 1982 are shown in Table 2.4.3-5.

Carolina Power 6 Light Company is the principal user of groundwater within two miles of the plant; there are only two domestic users within two miles of the plant, and both are up-gradient near the 7,000 ft. radius boundary.

2.4.3-.4

SHNPP ER TABLE 2.4.3-1 CAROLINA POWER & LIGHT COMPANY SHEARON HARRIS NUCLEAR POWER PLANT

SUMMARY

OF WATER-BEARING PROPERTIES OF MAPPED LITHOLOGIC UNITS IN DURHAM, N.CD AREA NUMBER AVERAGE RANGE YIELD (GALLONS PER MINUTE)

OF DEPTH IN DEPTH AVERAGE PER FOOT PER FOOT OF MAP UNIT WELLS (EEET) OF WELL UNCASED HOLE Metavolcanic Unit 317 94.8 0-600 9.6 0.10 0.15 Argillite-Graywacke Unit 77 102.4 0-283 7 3 0. 07 0.12 Triassic Unit 110 115.3 0-300 7.2 0.06 0.08 Granite Unit 61 82.5 0-400 8.2 0.10 0.18 Granodiorite Unit 22 86.7 0-400 10.0 0.12 0.20 Hornblende Gneiss Unit 11 60.7 4.0 0.07 Mica Gneiss and Schist Unit 4 134.0 8.8 0.07 NOTE: Data from Groundwater Bulletin Number 7; N. C. Department of Water Resources, May, 1966.

I' 2.4,3-7

ENVIRONMENTAL REPORT OPERATING LICENSE STAGE CHAPTER 3 LIST OF TABLES TABLE TITLE PAGE

3. 1-1 PLANT AIRBORNE EFFLUENT RELEASE POINTS 3. 1-2

3. 2-1 TURBINE HEAT RATES FOR VARIOUS STATION LOADS 3~2 2

3. 3-1 SHNPP STATION WATER USE UNDER VARIOUS STATION CONDITIONS 3~ 3 5 4

3.4. 2-1 DESIGN DATA FOR NATURAL DRAFT HYPEPJ30LIC COOLING TOWER 3. 4. 2-11

3. 4. 2-2 COOLING TOWER EVAPORATIVE WATER LOSSES (4 UNITS OPERATING) 3.4. 2-12 3.4. 2-3 BLOWDOWN FLOWS 3. 4. 2-13

3. 4. 3-1 SERVICE WATER REQUIREMENTS PER UNIT (gpm) 3. 4. 3-3 3.4. 3-2 t'JAXIMUM SERVICE WATER SYSTEM HEAT LOADS FOLLOWING SAFE SHUTDOWN 3.4.3H

3. 4. 3-3 MAXIMUM SERVICE WATER SYSTEM HEAT LOADS FOLLOWING LOCA 3.4. 3-7 3~ 5. 1-1 NORMAL OPERATIONAL PRIMARY AND SECONDARY COOLANT ACTIVITIES 3. 5. 1-7

3. 5. 1-2 PARAMETERS USED TO DESCRIBE THE REACTOR SYSTEM REALISTIC BASIS 3~ 5. 1-9

3. 5. 1-3 REACTOR COOLANT N-16 ACTIVITY 3o 5. 1-10

3. 5. 1% TRITIUM PRODUCTION 3o 5 ~ 1-11 3~ 5. 1-5 SPENT FUEL POOL SPECIFIC ACTIVITY (pCi/gm) 3. 5. 1-12

3. 5. 1-6 EQUIPMENT LEAKAGE ASSUMPTIONS 3. 5. 1-13

3. 5. 1-7 EXPECTED SPENT RESIN VOLUME 3. 5. 1-14

3. 5 ~ 2-1 LIQUID WASTE PROCESSING SYSTEM SCHEDULE OF INFLUENT WASTE STREAMS 3. 5. 2-16

ENVIRONMENTAL REPORT OPERATING LICENSE STAGE CHAPTER 3 LIST OF TABLES (Cont'd)

TITLE PAGE CHEMICAL 'WASTE DISCHARGE SQQiARY PER UNIT 3. 6-7 SQ1t1ARY OF CHEMICAL WASTE COMPLIANCE WITH APPLICABLE STANDARDS/PER UNIT 3. 6-9 C11EMICAL ADDITIVES AND THEIR ANNUAL CONSUMPTION/PER UNIT 3. 6-11

ENVIR0%1ENTAL REPORT OPERATING LICENSE STAGE CHAPTER 3 LIST OF FIGURES (Cont'd)

F IGURE TITLE

3. 4. 4-1 Emergency Service Water System Auxiliary Reservoir Screen Structure

3. 4 ~ 4-2 Emergency Service Water System Auxiliary Reservoir Screen Structure 3~ 5. 2-1 Flow Diagram Containment Building Waste Processing System Unit 1

3. 5. 2-2 Flow Diagram Waste Processing System, Waste Hold-Up and Evaporation Units 1 & 2 3 ~ 5. 2-3 Flow Diagram Waste Processing System Spent Resin Storage Units 1, 2, 3, & 4 3.5. 2-4 Flow Diagram - Waste Processing System, Floor Drain Storage and Treatment Units 1 & 2

3. 5.? -5 Flow Diagtam Waste Processing System Laundry and Hot Shower Storage and Treatment - Units 1, 2, 3, & 4 Sheet 1 3.5. 2-6 Flow Diagram Waste Processing System Laundry and Hot Shower Storage and Treatment - Units 1, 2, 3, & 4 Sheet 2 3.5.2-7 Flow Diagram Waste Processing System Laundry and Hot Shower Storage and Treatment Units 1, 2, 3, & 4 Sheet 3

3. 5. 2-8 Flow Diagram Secondary Waste Treatment System Units 1 & 2

3. 5. 3-1 Flow Diagram Waste Processing System Gas Decay Storage Units 1 & 2 3~ 5. 3-2 Flow Diagram Waste Processing System Waste Gas Compr. and Recombiner Units 1 & 2 3.5. 4-1 Flow Diagram - Waste Processing System Spent Resin Storage Units 1, 2, 3, & 4 3.5. 4-2 Flow Diagram Waste Processing System Radwaste Solidification Units 1, 2, 3, & 4

3. 5. 4-3 Flow Diagram Waste Processing System Concentrates Storage and Spent Resin Transfer Units 1, 2, 3, & 4

0 SHNPP FSAR 3.0 THE STATION 3.1 EXTERNAL APPEARANCE Ma)or plant island structures include four Containment Buildings; two Reactor Auxiliary Buildings, each serving two units; two Turbine Buildings, each housing two turbine-generators; one Waste Processing Building; a Service Building; one Fuel Handling Building; and four natural draft Cooling Towers.

Figure 3.1-1 shows the SHNPP site plan. A pictorial representation of the plant is provided by Figure 3.1-2 and the plant profile is illustrated by Figures 3.1-3 and 3.1-4.

The Containment and Reactor Auxiliary Buildings have an as-poured natural concrete exterior finish, while the Fuel Handling Building has siding with an exterior finish that is compatible with the environment. In addition, the exposed steel areas of the Turbine Building are painted gray to harmonize with the other buildings. The plant profile is dominated by the four natural draft Cooling Towers, each approximately 520 ft. high. The Cooling Towers have an as-poured natural concrete surface.

The site area is a rolling, wooded, rural area dissected by small streams in the Piedmont region of North Carolina. The SHNPP site is approximately 10,800 acres, of which about 4,000 acres are inundated to form the Main Reservoir. The plant area was graded to approximate Elevation 260 ft. MSL.

The surrounding terrain was undisturbed as far as possible. In general, the terrain rises to the north of the plant. The Main Reservoir is to the south, east, and west of the plant.

Appropriate planting and seeding will be used to integrate the plant components into the environmental setting. A number of intrinsic aesthetic impacts are associated with the reservoirs and the Cooling Tower complex, as discussed in Chapter 5~

The location and elevation of release points for gaseous wastes are identified in Table 3.1-1. Figure 3.1-5 shows the location of these release points relative to the site plan. The liquid release point (Cooling Tower blowdown line) is shown on Figure 2.4.1-1.

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SHNPP ER 3 2 REACTOR AND STEAM ELECTRIC SYSTEM Each of the four Shearon Harris Nuclear Power Plant units consists of one Westinghouse pressurized water reactor, three steam generators, one turbine generator, a heat dissipation system, and associated auxiliaries and engineered safeguards. The reactor, the steam generators, and the other components of the nuclear steam supply system (NSSS) are designed and supplied by Westinghouse Electric Corporation. Each NSSS will be designed for an initial licensed power output of 2,785 MWt, which includes 10 MWt from the reactor coolant pumps. The ultimate output from each NSSS is expected to be 2,910 MWt, including 10 MWt from the reactor coolant pumps. The turbine generator, a multiflow, 1,800 rpm tandem compound unit initially delivering approximately 951 Mwe, is also supplied by Westinghouse. The architect-engineer for the plant is Ebasco Services, Inc. The in-plant power consumption is approximately 83 Mwe resulting in an initial net rating for each unit of approximatately 868 Mwe.

The reactor is fueled with uranium dioxide sintered fuel pellets in sealed zircaloy-4 fuel rod tubes. There are 157 fuel assemblies, each with a 17 x 17 rod array consisting of 264 fuel rods, 24 guide thimbles, and one position for incore instrumentation. The initial core consists of three regions. Region 1 is 2.1 weight percent (U235/U238) enriched; Region 2 is 2.6 weight percent enriched; and Region 3, the outermost core region, is 3. 1 weight percent enriched. The core will be refueled at approximately annual intervals.

Turbine heat rates for various station loads are shown in Table 3.2-1. It should-be noted that a dual pressure condenser is being installed. These heat rates are based on 4.05 and 2. 83 in. HgA for the high pressure and low pressure zones, respectively. Operating back pressures are expected to range from highs of 4. 15/2. 95 in HgA to lows of 2. 45/1. 73 in. HgA.

The plant is designed for an operating life of 40 years.

3. 2-1

SHNPP ER Dam, and overflow from the Auxiliary Reservoir. An additional contribution to net volume derives from direct rainfall on the reservoir surface. As indicated previously, percolation, natural and forced evaporation, and pumped makeup water from the Main Reservoir to the Auxiliary Reservoir account for the primary losses from the Main Reservoir conservation storage.

To evaluate the fluctuation of inflow and outflow rates, as well as the net storage volume (or reservoir stage), a reservoir operation study was conducted for the Main Reservoir for.a four-year period from April 1973 through March, 1977. This study is discussed in Section 2.4 of this report.

Figures 2.4.2-9 through 2.4.2-11 show the duration curves for the Main Reservoir inflow rate, outflow rate, and stage. Rates of natural and forced evaporation, as well as the rate of percolation loss used in this study, are shown in Table 2.4.2-19 for various months of the year. They are derived based on data shown in Table 2.4.2-20 and the reservoir water surface areas.

On-site gaging records have been utilized for direct rainfall data.

In computing the volume of makeup water from the Cape Fear River, the withdrawal restrictions previously described in Section 2.4 are considered.

The computed range of fluctuation of the Main Reservoir levels is only 7.3 ft., with minimum and maximum levels respectively at Elevations 214.7 ft.

msl and 222 ft. msl for the four-year study. The mean inflow and outflow rates are 120 and 35 cfs, respectively.

A similar study was carried out for the Auxiliary Reservoir. Here the inflow involves only streamflow from the upstream drainage area of the Auxiliary Reservoir and make-up water from the Main Reservoir. There is no forced evaporation during normal operation. The results of this study are shown in Figures 2.4.2-12 through 2.4.2-14. Rates of evaporation and percolation losses are listed in Table 2.4.2-19. Due to a large surface area, which is about 20 percent of the tributary watershed area, and a relatively long discharge spillway crest (170 ft.) which passes floods quickly with only slight damping, the reservoir level generally stays between Elevations 250 ft.

msl and 252.5 ft. msl, with 2.5 ft. of expected range of fluctuation during normal operation. The mean inflow and outflow rates are 2 and 1 cfs, respectively. The starting water level is assumed to be at the normal operating level of Elevation 252 ft. msl.

A schematic indicating the elements and their directions involved in the computation of inflows and outflows for the Main and the Auxiliary Reservoirs is shown on Figure 2.4.2-15.

The stage-duration curve for the Main Reservoir is shown on Figure 2.4.2-11.

The Main Reservoir level for a typical year will have approximately a 1.5-foot drawdown. This potential drawdown probably would occur in October and November and is not expected to have any effect on the aquatic communities in the reservoir.

The ten-year frequency drought drawdown of approximately 4 to 5 ft. would occur in the months of October through December. A drawdown of this extent would uncover approximately 750 to 800 acres of the reservoir. Such 'a drawdown should have little or no detrimental effects on fish populations.

3+3 3

SHNPP ER As for the benthic population, there may be a numerical and diversity loss of some of the representatives of the Ephemeroptera, Plecoptera, Trichoptera, Amphipoda, and Gastropoda due to a drawdown associated with the ten-year frequency drought. However, representatives of several species of aquatic flies (larval stage) and worms may burrow in the exposed substrate, survive for several months, and recolonize littoral areas when the reservoir returns to normal pool.

Radwaste Systems are discussed in Section 3.5 and the effects of the discharge are described in Section 5.2.

1 The chemical waste system effluents are described in Section 3.6, and the evaluation of the effects of the discharge are discussed in Section 5.3. The flow between the chemical systems is shown on Figure 3.3-1 and the quantities are in Table 3.3-1.

The sanitary wastewater will be treated by two 25,000 gpd package treatment plants. The plants are described in Section 3.7 and the evaluation of the effects of the discharge are discussed in Section 5.4. NPDES effluent limits are contained in Appendix B. Potable water for plant use will be withdrawn from the Main Reservoir.

3. 3-4

SHNPP ER 3.4.2 CIRCULATING WATER SYSTEM The closed loop Circulating Water System for each unit shown in Figures 3.4.2-1 and 3.4.2-2 provides the main condenser with a continuous supply of cooling water for removing the heat rejected by the Turbines. The system is designed to operate continuously throughout the year under various ambient weather conditions. The CWS for each unit utilizes the following major components in its cycle:

a) Main condenser b) Natural draft hyperbolic Cooling Tower to serve as the heat sink c) Cooling tower basin d) Three 33 1/3 percent capacity circulating water pumps e) Chlorination system for circulating water treatment f) Cooling tower makeup and blowdown water system The total circulating water requirements are 483,000 gpm (1076 cfs) for each unit or a total of 1,932,000 gpm (4300 cfs) for the entire plant.

3.4.2.1 S stem Descri tion.

The three 33 1 /3 percent capacity circulating water pumps each rated at 161,000 gpm and 68 ft. total dynamic head take suction from each cooling tower basin and deliver the water to the condenser water boxes through two 120 in.

diameter reinforced concrete pipes. After passing through the condenser tubes, the heated circulating water leaves the condenser outlet water boxes and return through two 120 in. diameter reinforced concrete pipes to the cooling tower hot water distribution system. From there, the water will cascade down the lattice of the water dissipating heat fill to material in the Cooling Tower. This cools the atmosphere by conduction and evaporation.

g by The cooled ~ater collects at the bottom of the Cooling Tower. The water then flows by gravity through the basin into the circulating water pump chamber.

Under conditions of full load, each unit transfers approximately 6.7 x 10 9 Btu/hr. of heat to the CWS, resulting in an approximate increase of 26F in the temperature of the water as it passes through the condenser. There is no physical contact between the condensing steam and the circulating water.

Furthermore, since the steam side of the condenser operates at a vacuum under normal conditions, the possibility of steam side materials leaking into the circulating water is remote.

Heat dissipated to the atmosphere in the Cooling Tower will vary with the plant load. The only heated water discharged to the Main Reservoir will be from blowdown of the Cooling Towers to control dissolved solids in the closed cycle system. The blowdown will be at a maximum rate of 60 MGD for 4-unit operation and is taken from the coolest water in the system. The comparative maximum blowdown rates are 15 MGD for one-unit operation, 30 MGD for two-unit operation, and 45 MGD for three-unit operation. This water will range from 3.4.2>>1

SHNPP ER approximately 7F above the ambient Miin Reservoir temperature in July, to approximately 28F above ambient in December.

3.4. 2. 2 Total Consum tive Mater Use The total consumptive water use in the operation of the Cooling Towers and other waste systems, varying throughout the year, are 106 cfs under average meteorological conditions and 125 cfs under extremely adverse meteorological conditions with the plant operating at 100 percent capacity.

3.4.2.3 Desi n, Size and Location of Coolin Towers The SHNPP has four natural draft hyperbolic Cooling Towers, one per unit.

Each Cooling Tower is approximately 410 ft. in diameter at the basin and about 520 ft. high. Other design parameters are given in Table 3.4.2-1.

3. 4. 2.4 Chemical Characteristics of Coolin Towers A chlorination system is utilized to control the growth of algae in the SHNPP units'ondensers and the circulating water pipes. The chlorine requirements are expected to be approximately 3-5 ppm. The system normally operates for only two 30-minute cycles per day. Chlorine residual in the water in the cooling tower basin is controlled so that its concentration does not exceed 0.5 ppm in the Cooling Tower blowdown. Residual chlorine in the blowdown water averages less than 0.2 ppm.

Consequently, the blowdown rate of 60 MGD will have minimal effects, if any, on aquatic populations from the standpoint of chlorine discharges.

The impacted area is estimated at 5 acres. Also, little, if any, fouling in the plant heat exchangers is expected. The pH of the circulating water is controlled by the addition of sulphuric acid or sodium hydroxide as needed.

3.4.2.5 Drift and Drizzle of Coolin Towers A very small fraction of the cooling water circulating through the Cooling Towers is carried as small droplets in the rising air which leaves the cooling tower top- This drift rate fraction (defined as kilograms (kg) of salt per second leaving the cooling tower top divided by the kg of salt per second circulation through the tower heat exchange section) will average about 2 x 10 5 (or 0.002 percent). The drift is dispersed at an elevated point and on most days of light wind, the moist plume will continue to rise so that little or no ground fogging or icing will occur. Total evaporation and drift rate from the cooling towers is estimated at 35,000 gpm for four units.

Expected evaporative water losses are shown in Table 3.4.2-2.

3.4.2.6 Reasons for Selectin Coolin Towers The original design of the cooling system for the SHNPP consisted of a 10,000 acre cooling lake. However, a regulatory decision by the State of North Carolina made this alternative unavailable. Therefore, Cooling Towers became 3.4. 2-2

SHNPP ER respectively. The normal water depth in the structure is 23 ft., and high and low depths are 38.5 ft. and 21.15 ft., respectively.

For screens serving the large pumps, the maximum flow through one screen, at normal water level, and assuming its redundant screen is blocked, is 114 cfs at 0.90 fps. Under low water level conditions the similar values are 114 cfs and 0.98 fps. For screens'erving the small pumps, the maximum flow at normal water level is 45 cfs and 0.35 fps and at low water level it is 45 cfs at 0.39 fps.

Large debris accumulated at the course screens is removed by a manually operated trash rake. The trash rake travels on rails across the intake structure above the trash racks and is lowered to remove debris from the water at the face of the trash racks as required. Trash is lifted to the top deck of the intake structure and is deposited in strainer baskets at either end of the structure.

The traveling screens are equipped with baskets fixed to the face of the screen that remove debris from the water as the screen revolves. The debris is automatically washed from the baskets as they pass above the top deck of the intake structure where troughs carry the debris and wash water to the strainer baskets at either side of the structure.

Water level controls on the reservoirs are minimal; only the low level release gates and valves have to be controlled initially. The Cape Fear River pumping station requires motor, valve, screen, and backwash controls. Instrumentation for the Main Reservoir consists of reservoir water level indicators, low level release indicators, valve and gate position indicators, and temperature sensors.

3.4.2.9 Coolin Tower Makeup System Due to the loss of water caused by natural evaporation, drift, and blowdown requirements, continuous makeup water is provided to the plant's cooling system by means of cooling tower makeup systems. The cooling tower makeup system consists of cooling tower makeup pumps, a common header, a dual strainer system, piping, and a Cooling Tower Make-up Water Intake Channel from the Main Reservoir.

There is one cooling tower makeup pump per unit with one spare for every two units. The six cooling tower makeup pumps are located in the Emergency Service Water and Cooling Tower Makeup Water Intake Structure. The total of six cooling tower makeup pumps are divided into two sets of three pumps each.

Each set is headed together to supply a pair of Cooling Towers. With four-units operating at maximum makeup rates, only two of the three pumps will be operating simultaneously; or, on a plant basis, four out of six. Any four of the six pumps will supply the amount of makeup water required for the Circulating Water System. Each pump is sized for 26,000 gpm and a total dynamic head of approximately 135 ft. The withdrawal requirements for one-,

two-, three-, and four-unit operation are about 46 cfs, 92 cfs, 138 cfs, 184 cfs, respectively.

3.4.2-7

SHNPP ER The cooling tower makeup pumps also supply makeup water to the plant water treatment facility at the rate of 1200 gpm (4 units) ~ This is included in the above rating of the pumps.

Each cooling tower makeup pump is located in a separate bay of the intake structure. Each bay is provided with, in the direction of water flow, a course screen, stop log guides, a traveling screen, and guides for two fine screens. Details of the structure can be seen on Figures 3.4.2-10 through

3. 4. 2-13.

Each course screen measures 10 ft. 2 in. wide and extends from the floor of the intake structure to the underside of the top deck, a distance of 70 ft.

The detailed dimensions of the course screens are the same as those at the Cape Fear River intake structure.

Each traveling screen measures 9 ft. wide and is similar in other dimensions and materials to those described above for the Cape Fear River makeup intake structure. The fine screens have overall dimensions of 10 ft. 2 in. by 70 ft., and are otherwise similar to the fine screens of the Cape in Fear River makeup intake structure, in both dimension and purpose. As the Cape Fear River makeup intake structure, stop logs serve to facilitate maintenance of equipment in the bays.

The intake structure is designed for a normal water level of Elevation 220 ft. HSL, and high and low levels of Elevation water 255 ft. HSL and 205.7 ft.

HSL, respectively. (Although designed for a high level of Elevation 255 ft. MSL, the maximum expected water level is approximately Elevation 240 ft. MSL.) The normal water depth in the structure is 30 ft., and high and low depths are 50 ft. and 15.7 ft., respectively. The maximum flow through a screen, at normal water level, is 67 cfs at 0.40 fps. Under low water level conditions the similar values are 63 cfs and 0.73 fps. Trash removal from the traveling screens is similar to that described for the Cape Fear River makeup intake structure.

Trash removed at both intake structures will be deposited in a landfill located on site.

Environmental Report Section 5.1.3.4 addresses the impact of the plant intake on the aquatic community. As stated in that section, the design criteria for the normally operating intake structures included a requirement that the intake velocities not exceed 0.5 fps at low water levels. This criteria is met for both intakes discussed above at the position of the stop log guides in the structures.

The location of the cooling tower makeup structure is shown in Figure 3.4.2-3.

Details of the Cooling Tower Hakeup Water Intake Channel and ESW and Cooling Tower Hake"Up Intake Structure are shown on Figures 3.4.2-10, 3.4.2>>11, 3.4.2-12, 3.4.2-13, and 3.4.2-14.

3.4.2. 10 Dams and Dikes There are three such structures: the Hain Dam, the Auxiliary Reservoir Dam and the Auxiliary Reservoir Separating Dike.

3.4. 2-S

SHNPP ER The Main Dam is an earth-rockfill structure and the Auxiliary Reservoir Dam and the Auxiliary Reservoir Separating Dike are earth-random rockfill structures all designed to use locally available materials. Each dam has a cross section consisting of a central impervious core flanked by transition filter zones and compacted rock or random rockfill shells. The Auxiliary Reservoir Separating Dike has a cross section consisting of a central impervious core flanked by a random rockfill shell, The slopes of the structures are protected with riprap placed on crushed rock bedding where necessary.

The Hain Dam has a maximum height above the stream bed of about 90 ft., and contains approximately 550,000 cu. yd. of compacted earth materials. The Auxiliary Reservoir Dam, which is a part of the Emergency Core Cooling System is an earth-fill structure about 3,700 ft. long including the spillway section. The dam has a maximum height of about 50 ft. above the stream bed and will contain approximately 600,000 yd.3 of compacted earth materials.

The foundation materials for the Hain Dam and Spillway and the Cape Fear River to Main Reservoir makeup system are granite. The Hain Dam core and shell and the Auxiliary Reservoir Dam core are founded on rock. A portion of the Auxiliary Reservoir Dam shell is founded on rock. The foundation materials of the Auxiliary Reservoir structures and the intake structure from the Main Reservoir are the Triassic claystones, sandstones, shales, and siltstone.

Both the Hain and Auxiliary Reservoir Dams are constructed to withstand the design basis earthquake.

3.4.2.11 Essential Features of Interior Flow Patterns in Re ard to the Cooling Reservoir The Auxiliary Reservoir performs its function as the ultimate heat sink in the event of a loss of service water from the Cooling Towers. During Emergency Service Water System Operation, service water is drawn from and discharged to the Auxiliary Reservoir. The emergency service water is carried to the Emergency Service Water and Cooling Tower Makeup Intake Structure by gravity through the Emergency Service Water Intake Channel and Emergency Service Water Intake Screening Structure. The thermal effluents released during the emergency operating mode are discharged into the Auxiliary Reservoir through the Emergency Service Water Discharge Channel. The intake and discharge channels are separated by the Auxiliary Reservoir Separating Dike in order to prevent the thermal effluents from being withdrawn immediately after being discharged. The thermal effluents will ultimately be returned to the Emergency Service Water Intake Channel via the Auxiliary Reservoir Channel.

As is seen from Figure 3.4.2-3, this arrangement provides for maximum recirculation of the thermal effluents within the Auxiliary Reservoir, and maximum efficiency of the heat sink.

The Hain Reservoir functions as the ultimate heat sink only in the unlikely event that the Auxiliary Reservoir is not available. Under this circumstance, emergency service water is carried to the Emergency Service Water and Cooling Tower Makeup Intake Structure through the Cooling Tower Makeup Water Intake Channel from the Main Reservoir. The thermal effluents released are discharged into the Auxiliary Reservoir and then over the Auxiliary Reservoir Dam Spillway into the Main Reservoir.

3.4.2-9

SHNPP ER The circulation path thus established is ion'ger than the corresponding path established when only the Auxiliary Reservoir is utilized and therefore it provides more than adequate cooling.

3.4.2-10

SHNPP ER 3.4 ~ 3 SERVICE WATER SYSTEM The Service Water System for each unit provides redundant cooling water to those components necessary for safety either during normal operation or under accident conditions. It also supplies cooling water to various other heat loads in the primary and, secondary portions of each unit including the Component Cooling Water System. There are two separate modes of operation of the Service Water System normal operation and emergency operation.

a) Normal Operation Normal operation consists of using the unit's circulating water when the Cooling Tower and all associated components are operative. Each pair of Cooling Towers (Units 1 & 2 and Units 3 6 4) are interconnected to provide backup shutdown cooling in the event that one Cooling Tower is not available to perform the heat transfer function.

b) Emergency Operation Emergency operation consists of using the Auxiliary Reservoir or Main Reservoir if the unit's Cooling Tower or designated backup Cooling Tower and their associated components are not available for service. The Auxiliary Reservoir is the preferred source of cooling water under these conditions.

The Main Reservoir serves as a backup source of water in the unlikely event of the loss of water from the Auxiliary Reservoir.

3.4.3.1 S stem Descri tion The Service Water System. for each unit shown on Figures 3.4.2-1 and 3.4.2-2 consists of two 100 percent normal service water pumps, two 100 percent emergency service water pumps, two 100 percent service water booster pumps, associated piping, valves, and instrumentation. The system is designed such that during unit start-up and normal operation, service water requirements are met by one of the normal service water pumps taking suction from either of the two adjacent Cooling Towers. Each pair of Cooling Towers are interconnected to provide this provision The pump furnishes all normal operating service water requirements for the unit through one single supply line. This supply line provides water to the component cooling heat exchangers, the containment fan coolers, and the HVAC equipment located in the Reactor Auxiliary and Waste Process Buildings and normal Turbine Building heat loads. The total service water requirements per unit are shown in Table 3.4.3-1.

During normal operation, the heated service water is discharged into the unit's circulating water downstream of the condenser. The normal operation of the Service Water System is designed to provide water at a temperature less than the maximum design temperature of 95F. The normal service water system heat load is 131.6 x 106 Btu/hr. Maximum service water system heat loads following a safe shutdown of one unit and during LOCA are shown in Tables 3.4.3-2 and 3.4.3-3, respectively.

Under emergency conditions when both Cooling Towers become inoperative, the supply is switched to the emergency service water pumps taking suction from the Emergency Service Water Intake Structure supplied by the Auxiliary 3.4.3-1

SHNPP ER Reservoir. Under this condition, the Turbine Building loads are isolated and the unit is maintained or brought to shutdown condition.

The Main Reservoir serves as a backup supply of water for the Auxiliary Reservoir if water from that source is not available. Valving is provided to switch suction from the Auxiliary to the Hain Reservoir. Water from the Main Reservoir is taken from the Main Reservoir via the Cooling Tower Makeup Water Intake Channel. Service water from the Hain Reservoir is returned to the Auxiliary Reservoir.

Water from both the Main and Auxiliary Reservoirs passes through the traveling screens. Concrete walls separate the intake into bays. Each emergency service water system pump is located in a separate bay with separate screens, and each pump discharges into a separate pipeline.

3.4.3-2

SHNPP ER spent fuel pool water via transfer tube and fuel transfer canal. After refueling, the spent fuel pool is isolated and the water in the refueling cavity is returned,to the refueling water storage tank. This series of events determines the total activity to the spent fuel pool. The specific activities of the radionuclides given in Table 3.5.1-5 are based upon a volume of 960,250 gallons. The initial radioactivity level will be reduced by decay during refueling and by operation of the Spent Pool Cooling and Cleanup System.

Based on a spent fuel pool volume of 398,000 gallons, a processing rate of 325 gallons per minute through the Spent Fuel Pool Cleanup System, and a combined decontamination factor of 2 for Cs, Rb, and 10 for all others for the filter and demineralizer, the cleanup rate for Cs, Rb and other particulate radionuclides is 0.59 and 1.06 cycles per day, respectively.

The fuel pool activities under normal operating conditions are also presented in Table 3.5.1-5. These values are obtained using the method described for design basis values with the exception that normal primary coolant activities presented in Table 3.5.1-1 are used instead of design basis primary coolant activities.

As discussed in Section 9.1 of the FSAR, the fuel storage pools will be used for storage of PWR and BWR spent fuel shipped from other nuclear plants on the CP6L system. Since this fuel will have been out of the reactor for a minimum of 90 days prior to being shipped to SHNPP, it will not contribute significantly to the fuel pool activities calculated above.

Systems containing radioactive liquids are potential sources of leakage to the environment. Table 3.5-1-6 provides a listing of assumed leakage values from valves and pumps. Leakage of primary coolant into the containment building atmosphere, which is ultimately exhausted to the environment at times of containment purge, is assumed to be one percent per day of the primary coolant noble gas activity and .001 percent per day of the iodine activity in the primary coolant. An additional potential source of gaseous discharge is coolant leakage {via the CVCS and BRS) into the Reactor Auxiliary Building.

A leakage rate for each unit of 160 lb./day of a mixture of hot and cold primary coolant leakage is assumed, with an iodine and noble gas partition factor of .0075 and 1.0 respectively. The liquid from these leakage sources is collected and processed in the Liquid Waste Management System which is described in Section 3.5.2.

Primary to secondary leakage can result in the buildup of radionuclides in the secondary coolant and Steam Generator Blowdown System (SGBS). Under normal operation a leakage rate of 100 lb./day is assumed. The activity can ultimately result in discharge of small amounts of liquid and gaseous wastes to the environment. The discharge of liquid waste can result from liquid leakage to the turbine building sump and the release of portions of processed blowdown. It is assumed that leakage to the turbine building sump is five gpm and that all of steam generator blowdown is processed and returned to the secondary coolant system.

3.5.1-5

SHNPP ER Gaseous releases from the secondary side can'result from main steam leakage, the gland seal system exhaust and the discharge of noncondensible gases from the SGBS flash tank. Overall main steam leakage is assumed to be approximately 1700 lb./hr. and originates from many sources, each too small to identify. Turbine gland seal steam flow is sent to a gland steam condenser resulting in negligible discharges. Since all noncondensible gases from the SGBS flash. tank are vented to the condenser, these releases are also negligible.

The above leakage rates and partition coefficients are based on the recommendations and experience presented in NUREG&017.

Releases inside the plant are handled by the appropriate ventilation system.

Containment air purification and cleanup systems are described in Section 9.4.5 of the FSAR. Reactor Auxiliary Building and Turbine Building Area Ventilation Systems are discussed in Section 9.4 of the FSAR and continuous radiation monitors are discussed in Section 12.3.4 of the FSAR.

3.5.1 ~ 8 S ent Resin Volumes

'The spent demineralizer resin supplied to the Solid Waste Management System from demineralizers in the Nuclear Steam Supply System is presented in Table 3.5.1-7. The information is based on plant experience as further outlined in Reference 3. 5. 1-3.

3.5.1. 9 Source Term Data Data needed for radioactive source term calculations required by Regulatory Guide 4.2 are contained in Appendix A of this report.

3.5,1 6

SHNPP ER TABLE 3.5.1-1 (Cont'd)

NORMAL OPERATIONAL PRIMARY AND SECONDARY COOLANT ACTIVITIES (pCi gm)

Primary Secondary ,Coolant Nuclide Coolant Water S team Y-91m 4. 29 x 10~ 1.38 x 10-8 1.38 x 10-11 Y-91 6. 72 x 10 5 1.86 x 10 9 1.86 x 10 12 Y-93 3. 83 x 10 5 7.88 x 10-10 7.88 x 10 13 Zr-95 6. 31 x 10 5 2.47 x 10 9 2.47 x 10-12 Nb-95 5. 26 x 10 5 2.48 x 10 9 2.48 x 10-12 Mo-99 8. 99 x10 2 2.60 x 10 6 2.60 x 10 9 To-99m 5. 50 x 10 2 2.63 x 10 2.63 x 10 9 Ru-103 4. 73 x 10 5 1.24 x 10 9 1.24 x 10-12 Ru-106 1. 05 x 1'0 5 2.47 x 10-10 2.47 x 10 13 Rh-103m 5 35 x 10 5 2 70 x'10 9 2.70 x 10 12 Rh-106 "1. 20 x 10 5 7.12 x 10 10 7.12 x 10 13 Te-125m 3 05 x 10 5 6.19 x 10-10 6.19 x 10 13 Te-127m 2. 94 x 10~ 6.18 x 10 9 6.18 x 10 12 Te-127 9. 59 x 10 4 2.40 x 10-8 2.40 x 10-11 Te-129m 1 47 x 10 3 3.72 x 10 8 3.72 x 10-11 Te-129 l. 90 x 10 3 3

7 77 K 10-8 10",8 7.77 x 10-11 10-11 Te-131m 2 72 x 10 6.85 x 6.85 x Te-131 l. 32 x 10 10-2 3 3 08 x 10-8 3.08 x 10 11 10-10 Te-132 2. 88 x 6.45 x 10 7 6.45 x Ba-137m l. 92 x 10 2 1 ~ 58 x 10~ 1.58 x 10 9 10"12 Ba-140 2. 32 x 10~ 6.24 x 10 9 6.24 x La-140 1 62 x 10~ 4.68 x 10 9 4.68 x 10-12 Ce-141 7. 37 x 10 5 2.48 x 10 9 2.48 x 10 12 Ce-143 4. 34 xl055 6.79 x 10-10 6.79 x 10-13 10-12 Ce-144 3 47 x 10 1.23 x 10 9 1.23 x Pr-143 5 27 x 10 5 1.25 x 10 9 1.25 K 10-12 Pr-144 3. 96 x 10 5 3.21 x 10 9 3 21x 1012 Np-239 l. 29 x 10 3 3.93 x 10 8 3 93 x ]0-11 3,5. 1-8

SHNPP ER 3.5.2 LIQUID RADWASTE SYSTE'AS The Liquid Waste Processing System (LWPS) provides for the collection, storing, processing, and controlled release of radioactive and potentially radioactive liquids associated with the operation of the nuclear power plant.

The discharge of treated wastes is controlled and monitored to ensure that any discharges are as low as are reasonably achievable (ALARA) and that they are in conformance with the requirements specified in 10CFR20 and 10CFR50.

3.5.2.1.1 Design Objectives and Criteria The LWPS is designed to collect all primary plant radioactive waste water and by processing, reduce the radionuclide concentration and upgrade its quality to permit reuse or discharge to the environs. In addition, the LWPS is designed to treat occasional batches of secondary liquids should leakage or other occurrences produce radioactive liquids in the secondary system.

Differences in primary"and secondary system water chemistry must be considered prior to reusing liquids from these sources.

The LWPS is divided into four subsystems; the Equipment Drain Treatment System, Floor Drain Treatment System, Laundry and Hot Shower Treatment System, and the Secondary Waste Treatment System. These subsystems segregate the various types of liquid radwaste based on their source because of their composition and process requirements. The segregation is used to provide the maximum water quality and radionuclide removal prior to release of treated water to the environs.

Each subsystem services two of the four Units, except the Laundry and Hot Shower Treatment System which services all four Units. Specifically, there are two Equipment Drain Treatment Systems, two Floor Drain Treatment Systems, two Secondary Waste Treatment Systems and one Laundry and Hot Shower Treatment System.

The LWPS is designed to recycle as much of the water entering the system as practicable. This is accomplished primarily by the segregation and appropriate treatment of the various waste streams.

The bulk of the radioactive liquids discharged from the Reactor Coolant System is processed and recycled by the Boron Recovery System. Aerated wastes and other liquids are treated in the Liquid Waste Processing System by an appropriate combination of filtration, ion exchange and evaporation Filtered particulate matter, spent ion exchange resin, and waste concentrates are collected and sent to the Solid Waste Processing System (Section 3.5.4) where they are solidified and shipped offsite for disposal. The Liquid Waste Processing System design is shown on Figures 3.5.2-1 through 3.5.2-8.

Liquid wastes from reactor coolant and its associated subsystems are separated into three main streams - 1) Recyclable Reactor Grade Stream, consisting of all tritiated effluents from equipment drains; 2) Nonrecyclable Stream, consisting of nonreactor grade water sources, collected and processed through either the Floor Drain Treatment Systems or the Laundry and Hot Shower 3.5.2-1

SHNPP ER Treatment System; 3) Secondary Waste Stream, consisting of potentially radioactive effluent from the condensate polisher regenerat1on.

Provisions have been made to sample and analyze processed liquids before they are recycled or discharged to the environment. Based on laboratory analysis and the limitations of 10CFR20'and 10CFR50, Append1x I, these fluids will be either released under controlled conditions via the cooling tower blowdown or retained for further processing. The system is capable of processing all wastes generated during operation of the Reactor Coolant System for all four Units. The annual input waste volumes for the systems and discharge quantities are shown in Table 3.5.2-1. The system has been designed to include excess capac1ty, redundant equipment, and system cross-ties to allow for abnormal liquid surges and equipment malfunction.

The Exhaust System for the waste processing areas is equipped with HEPA filters and charcoal adsorbers; thus, any liquids volatilized will be filtered prior to discharge. In the event of accidental releases of liquid waste due to operator error, automatic alarms and controls prevent excessive waste release. Liquid waste tanks that operate at atmospheric pressure vent to the Waste Processing Building Ventilation System. All tank overflow connections are equipped with water traps to prevent release of volatile species inside the WPB. All waste gases wh1ch are vented from the liquid waste tanks are monitored at the point of release to the environment.

The LWPS is monitored and controlled from a central Control Room in the Waste Processing Building. Local instrumentation and controls, where necessary, are located on auxiliary racks near the equipment. Operation is a batch process; that is, operator initiation with automatic termination. All releases to the environment require operator action to initiate.

Releases to unrestricted areas of liquid effluents containing or potentially containing radioactive materials are made only from the waste evaporator condensate tanks, waste monitor tanks, treated laundry water storage tanks, and secondary waste sample tanks. These releases are monitored before discharge to the cooling tower blowdown.

The discharge valve is interlocked with a process radiation monitor and will close automatically should the radioactivity concentration in the liquid discharge exceed a preset limit. The liquid waste d1scharge flow volume is recorded. In addition, an interlock system is provided to automatically isolate the liquid discharge in the event that dilution flow afforded by the cooling tower blowdown falls below a preset value The waste quantities that must be processed are shown in Table 3.5.2-1 This table indicates the source of the influent, the volume of flow (per day and per year) and the activity of each source. Table 3. 5.2-2 details the anticipated operational occurrences which were considered in the design of the LWPS for normal operation. Table 3.5.2>>3 shows the evaluation of the LWPS and indicates the capabilities of the LWPS to process the waste surge flows of anticipated operat1onal occurrences, and the redundant process equipment to handle equipment downtime. This evalulation shows that the LWPS has sufficient capability and redundancy to process surge waste flows associated with anticipated operational occurrences such as waste flows from back-to-back refuelings and equipment downtime.

3 5.2-2

SHNPP ER 3.5.2.2.2 Floor Drain Treatment System The Floor Drain Treatment System collects and processes water from the floor drains of the Reactor Auxiliary Building, Fuel Handling Building, Waste Processing Building, Tank Building and portions of the Hot Shop. This subsystem treats the collected water by removing chemical and radioactive impurities to the extent that safe discharge to the environment is permitted.

The Floor Drain Treatment'ystem consists of two independent streams, each serving two Units. The process subsystem is shown on Figure 3.5.2<.

Equipment for each stream serving two Units includes two floor drain tanks, two filters, a reverse osmosis unit, a waste monitor tank demineralizer, and two waste monitor tanks. The system is cross-tied to the waste evaporator in the Equipment Drain Treatment System to allow for treatment by evaporation if conditions require it.

Water is collected in one of two 25,000 gallon floor drain tanks. The two tanks have sufficient capacity to allow for surges and other abnormal inputs.

After mixing and sampling, normal treatment consists of filtration and reverse osmosis. If radioactivity levels are such that this treatment would

'be inadequate, the reverse osmosis unit will either be 'suppleme'nted by demineralization or be bypassed and the water routed to one of the waste evaporators before being returned to the waste monitor tank. Water in the waste monitor tank is sampled, routed to the condensate storage tank for reuse, discharged to the environment via the cooling tower blowdown or recycled for fur'ther treatment. All discharges to the environment will be in a controlled manner.

The Floor Drain Treatment System is isolated from drainage systems which do not carry radioactive waste. Radioactive floor drain wastes are collected separately in tanks or sumps, based upon the system classification to facilitate their treatment by the Liquid Waste Processing System.

Laboratory samples (spent and excess sample liquid) which are likely to be tritiated and/or which may contain chemicals required for analysis are not discharged or recycled but are solidified directly. These samples of relatively small volume are discarded in a separate sink which drain to the chemical drain tank. One chemical drain tank is provided for each twoWnit Liquid Waste Processing System. This tank and associated pump are shown on Figure 3. 5.2&. Low activity drains from the laboratory, such as rinse water, are routed to the floor drain tanks. The liquid wastes from the chemical drain tank which are not directly solidified are sent to the reverse osmosis concentrates evaporator.

3.5.2.2.3 Laundry and Hot Shower Treatment System Laundry and hot shower liquid wastes collected in, the Liquid Waste Processing System normally do not require treatment for removal of radioactivity. A sample will be taken and, after analysis, the results will be logged and the water discharged if the activity level is within acceptable limits.

Provisions have been made, however, to process these wastes normally by filtration and reverse osmosis and demineralization when required. One laundry and hot shower system is provided for all four Units. This subsystem 3.5. 2-7

SHNPP ER is shown on Figures 3.5.2-5 through 3.5.2-7 and the input volume shown in Table 3.5.2-1.

Equipment in this subsystem includes two laundry and hot shower tanks, two filters, a reverse osmosis unit, a demineralizer, two treated laundry and hot shower tanks, two reverse osmosis concentrates tanks, and two reverse osmosis concentrates evaporators When analysis of the water in the laundry and hot shower tank indicates treatment is required, it is then filtered and routed to a reverse osmosis unit. The permeate from the reverse osmosis unit is passed through a demineralizer and then routed to the treated laundr'y and hot shower tank.

After sampling, the water is either recycled for further treatment or discharged. The concentrates from each of the three reverse osmosis systems are sent to a reverse osmosis concentrates tank where they are further concentrated by an evaporator. Evaporator concentrates are routed to the solid ification sys tern.

3.5.2.2.4 Secondary Waste Treatment System The Secondary Waste Treatment System is designed to treat wastes generated from secondary or steam/condensate systems. This water will contain radioactivity only if steam generator leaks occur; however, all sources of secondary waste are considered potentially radioactive. One secondary waste treatment subsystem is designed to handle the waste from two Units. Each subsystem is divided into high conductivity and low conductivity streams. The design is shown on Figure 3.5.2-8 and the equipment is located in the south end of the Fuel Handling Building. Inputs are shown in Table 3.5.2-1.

Turbine building equipment drains, floor drains, and curbed area oil equipment and floor drains below the operating deck are collected by a common waste drainage system and directed to industrial waste sumps on the ground floor of the Turbine Building (two per unit) ~ Drains below ground elevation, including those in the heater drain pit area, are collected in a condensate pump area sump. Both the industrial waste sumps and condensate pump area sump discharge through a radiation monitor on a common discharge header.

In the event that a high radiation level is detected in the water being discharged, an alarm will be activated in the Control Room. This radiation level is equivalent to an average 0.06 Ci./yr. release rate at 2 gpm.

continuous flowrate. The sump pump discharge will then be automatically diverted through a filter and directed to the Secondary Waste Treatment System for processing and disposal.

The selection of treatments for this effluent stream is dependent upon the activity of the secondary system water. Under the postulated adverse conditions of one percent failed fuel and significant primary to secondary leakage, this source may require processing. However, under normal conditions, this potential source will'be small and will require little treatment.

3.5.2-8

SHNPP ER a trip valve in the discharge line will close automatically if there is a high activity level in the plant vent effluent.

3.5.3.1.3 Waste Gas Sources

3. 5.3. 1. 3. 1 Rad ioac tive Virtually all of the radioactive gas flowing into the system enters as t'race contamination in high purity streams of hydrogen. The primary source of radioactive gas is the volume control tank purge. Smaller quantities are received from the recycle evaporator, the waste evaporator, the reactor coolant drain tank, and the recycle holdup tanks. The, waste evaporator gas stripper is normally vented to the auxiliary building exhaust, but it will be vented to the gas system when it is used as a substitute for the recycle evaporator.

3. 5. 3. 1. 3. 2 Non-Rad ioac tive Care is taken to minimize the addition of all gases other than those which the system can process and remove. Seemingly insignificant quantities could, in time, overload the limited storage capability of the gas decay tanks. With the present design, virtually all sources of non-removable gas have been eliminated so that the accumulation is primarily composed of impurities in the influent streams. The largest contributor to the non-radioactive gas inventory is helium generated by a boron-10 (n,a) lithiun-7 reaction in the reactor core. The second largest contributor to the non-radioactive gas inventory is impurities in the bulk hydrogen and oxygen supplies. Stable and long lived isotopes of fission gases also contribute small quantities to the system gas accumulation.

Based on two Unit operation and assmning a 0. 7 scfm hydrogen purge for the volume control tank of each Unit, an 80 percent plant load factor for each Unit, and 99.95 percent pure hydrogen and 99.95 percent pure oxygen, the following accumulation rates should result (totals for two Units) ~

'Stable Fission Gases 25 scf./yr.

H2 and 02 Impurities 440 scf./yr.

Helium 512 scf./yr.

Total 977 scf./yr, At this rate of accumulation and assuming zero leakage from the GWPS, the eight normal operation gas decay tanks have a combined capacity sufficient to hold all the gaseous waste produced over more than 30 years 'with no releases.

This assumes that the waste gas holdup tanks are operated with an initial charge of 5 psig of nitrogen and the pressure in the tanks is allowd to accumulate to 100 psig. Thus, the GWPS allows discharges to be made under favorable environmental conditions.

3.5.3-3

SHNPP ER 3.5.3.2 Buildin HVAC S stems The BVAC systems for each building are discussed in detail in Section 9.4 of the SHNPP FSAR.

3.5.3.3 Gaseous Radioactive Releases Gaseous radioactive effluent will be released in accordance with the guidelines of 10CFR20 and 10CFR50, Appendix I. The GWPS is capable of monitoring radioactive gaseous discharge to the environment to ensure that activity concentrations do not exceed predetermined limits. If a limit is exceeded, discharge will be automatically terminated.

An estimate of the normal gaseous effluent from the facility, including anticipated operational occurrences, is presented in Table 3.5.3-3. The values were obtained using the guidance of ilUREG&017, "Calculation of Releases of Radioactive l&terials in Gaseous and Liquid Effluents from PWRs" (April, 1976) and the assumptions given in Table 3.5.3-3.

The tritium released through the ventilation exhaust systems during normal operation was also calculated. The exhaust quantity of tritium available for release was calculated using a functional relationship derived from measured liquid and vapor tritium releases at operating PWRs and the integrated thermal power output during the calendar year in which the release occurs. It is assumed that the tritium released through the ventilation exhaust systems is the total tritium available for release minus the tritium calculated to be released through the liquid pathway. The annual average concentrations of these normal operational effluents at the site boundary are given in Table 3.5.3&. The concentrations are based on the highest annual average atmospheric dispersion factor, including terrain and recirculation correction factors, at the site boundary.

The potential doses caused by the release of radioactivity in the gaseous effluent are given in Table 3. 5.3-5. These exposures were calculated using the guidance of Regulatory Guide 1. 109 and are well within the limits of 10CFR50 Appendix I. It should be noted that Table 3. 5. 3-5 also demonstrates compliance with the September 4, 1975 Annex to Appendix I.

Accordingly, a cost benefit analysis of compliance with Section II D of Appendix I is not provided.

Section 3.1 presents the location of all gaseous release points, and provides the height and inside dimensions of each release point along wi.th the effluent temperature and exit velocity.

3.5.3-4

SHNPP ER TABLE 3.5 '-1 (Two Units)

Page 1 of 3 SYSTEM AND COMPONENT CAPACITIES 1 ~ WASTE GAS COMPRESSOR PACKAGE Quantity Design Temperature, F 180 Design Pressure, psig 150 Operating Suction Pressure, psig 0.5-20 Design Flow (N2 at 140 F and 100 psi discharge), scfm 40 Material Carbon Steel Operating Temperature, F ~ 70-140 Operating Pressure, psig 25-100 2o CATALYTIC HYDROGEN RECOMBINER PACKAGE Quantity Design Temperature, F Note 1 Design Pressure, psig 150 Design Flow, scfm 50 Catalyst Bed Design Life, yrs. 40 Material Stainless Steel Operating Conditions, Inlet Temperature, F 70-140 Pressure, psig 25-100 Operating Conditions, Outlet Temperature, F 70-140 Pressure, psig 30 NOTE 1: Varies by component, but exceeds component operating temperature by 100 F.

3e503 5

SHNPP ER Table 3.5.3-1 Page 2 of 3 3~ WASTE GAS DECAY TANKS

3. 1 Normal Power Service Tanks Quantity Type Vertical Cylindrical Design Temperature, F 180 Design Pressure, psig 150 Volume, ft.3 600 Material CS 3.2 Shutdown/Startup Tanks Quantity Type Vertical Cylindrical Design Temperature, F 180 Design Pressure, psig 150 Volume, ft 3 600 Material CS 4>> GAS DECAY TANK DRAIN PUMP Quantity Type Canned Design Temperature, F 180 Design Pressure, psig 150 Design Flow, gmp 10 Total TDH at Design Flow, ft. 90 NPSH Required, ft. 10 Max Operating Temperature, F 140 Max Operating Suction Pressure, psig 30 Fluid Pumped Reactor Makeup Water terial 3.5 '-6 Stainless Steel

SHNPP ER TABLE 3 ' 3-1 Page 3 of 3 5~ WASTE GAS DRAIN FILTER Quantity Type Backflushable Design Temperature, F 200 Design Flow, psig 150 Design Flow, gpm 35 Pressure Loss at Design Flow Fouled, psig 20 Unfouled, psig Percent Retention for 25 Micron Particles 98 Material Stainless Steel 6~ GAS TRAPS Quantity Design Temperature, F 180 Design Pressure, psig 150, Operating Inlet Pressure, psig Maximum 100 Minimum Design Flow, gpm 30 Material Carbon Steel 3.5.3-7

Thule 3+5+3-2 I'RUCKUS VhkhttuaTEkS VUk CMVS 90 UAX LIOIJ)UV ANU RELEASE (NOTVb I & 2$

I'l<< (ttut 3)

ITEN UYSCRI V'VIOtt Uhb b"I'kt ht)S Ib TEIIV I'RVbS 10 VI@M SCI'N N2 2

ll2 2 KK85 Kltu5)l LSOTOVIC CUNCENTKATtott, uc/CC KIIU7 KR88

~

XE-133 XE-1330 Xl -135 I~ Vutaaaaa<<C<<aatcul 13U Iti I 4 0 IUU 2.07 x 10 2 3.10 x 10 1.08 x 10 . 4.94 x IU 1.44 r 10 3 ~ Ul x IU I U.99 x 10

'I'uuk Vuvua:

(Nut<< 5)

2. Uuu U<<cuy ANR 2U 40 99. 9 U. I I. 24 222x 101 2.14xlU 2~ 22xlu 883x10 254 1.27 Tuuk Ulscla.

3. Cu>>alar<<uuuc Atlu Uo5 4L ~ 4 96+6 3 4 I~ 2 2.25 r 10 I 2.43 r 10 2 2 ~ 31 x IU 8.5U x IU 2.46 l. 26 Saac t loll

4. Cuaata. Ul ua: Ia. 14U 3U 41.4 96.6 3.4 1.2 2.25 r 10"I 2.43 r 10 2 2.31 r 10-1 8.5U x 10 2.46 l. 26 5o k<<cuaata talus 14u 2O 40 99.9 O. I 1.25 2.33 r 10-1 2 ~ 52 x 10"2 2.39 x 10-1 u.uu x 101 2.55 1.3 Ul ukb.

b. Nl uc ~ V<<aata(- 14U Uo 5 IIEUo I) I UU 0 Ev utah. KCIA'.

k<<<<ye l<<uulalaala Tuuk V laacaa(uc (tlut<<$ )

7~ kua:<<a)bi aau a At I 8 5U 0. 7 t) 0 0 Oryua'll bulalat y ITEN OVS('R l)'TIU(t TVt)V I I(b'au I LW ISOTOI'I(.':UtiCENTkATION, uC/CC (Nut<<5)

LL(IULO bTKI'.A(IS VSLU Ct'U Klt850 Kk87 KK88 XE-133 XE-13'ltl XY-13'5 I'.

Nuxt<< (tuu 14u 4U U 2.94 x 10 5.49 x 10 2 5.94 x 10 5.64 x 10 I 73 x 101 4.96 x IU 2 ~ 53 x 10

(>>)al II a ~ ' ca a c UV<< Na

2. )(<<<<a>>ab lu<<V 14U 12 x 10-1 4.64 x 10 2 5.t)2 x IO 3 4.77 x IU 2 1.46 x 101 4.2 x 10 11 2. 14 r IU I Oru lu '.4u (luu U<<<<uy AI0( 2U 36 t. Lu x IU I 2. I x 10 2.02 x 10 2. I r 10 6. 9 I.uu x 101 9.9 x IO"-

Tualk UAI talu Syut<<as Uvaal>>u cu Vut. Cuntvul 14U 30-45 4u l. 5 x 10 I 2. 73 x 10-2 2. 77 x IU 3 2. 76 x 10 2 u. 03 2.53 x lu'.2u x LO Tuaak

SHNPP ER TABLE 3.5.3-2 (continued)

PROCESS PARAMETERS FOR GWPS 90 DAY HOLDUP AND RELEASE NOTES:

Basis: Type of Operation Periodic Release of Gases Power Level 2900 HWt Number of Units 2 Normal Operation Gas Decay Tanks in Rotational Use ~ 4 GDT Operating Interval 1 day Stripping Efficiency ~ 0 4 Accumulation Period ~ 90 Days

2. Concentrations based on stripping fractions from Table 11.1 ~ 1-1 and reactor coolant activities from Table 11 ~ 1~ 2-1.

3. Concentrations in pc per cc of gas at atmospheric pressure and 140 F.

4- Parameters reflect the combined gas streams from two operating reactors.

5. Concentrations in pc per cc at room temperature

6. NEG - Negligible

7. AMB - Ambient 3.5.3-10

SKIP ER 3.5.4 SOLID WASTE PROCESSING SYSTEM The Solid Waste Processing System (SWPS) collects, controls, processes, packages, handles, and temporarily stores radioactive waste generated as a result of normal operation of the plant, including anticipated operational occurrences. The SWPS prepares waste material for transportation to an off"site disposal facility. The SWPS is shared by all four units.

3.5.4.1 Desi n Ob'ectives The ob)ectives of the SWPS are to collect wastes sent to it from the waste evaporator concentrate tank, the secondary waste evaporator concentrate tank, the chemical drain tank, the spent resin storage tank, the filter backwash system, and the volume reduction subsystem. The SWPS provides a reliable means for handling radioactive wastes while maintaining radiation exposure levels to the public and plant personnel within the permissible limits of 10CFR20 and 10CFR50. The SWPS also collects, packages, stores, and prepares for transport to an off-site burial facility any disposable solid radwaste (e.g., contaminated clothing, rags, paper, lab equipment, and supply items) generated during operation of the plant.

In order to accomplish these design objectives, the following specific criteria are satisfied:

a) The SWPS is designed to provide for the collection, processing, packaging, and storage of solid wastes resulting frora plant operations without limiting the operation or availability of the plant. Types of wastes and quantities (maximum and expected volumes) given in Table 3.5.4-1 as inputs to the SWPS are accommodated in the system design.

b) The SWPS is designed to provide at least 60 days storage of spent resin in the spent resin tank during normal generation rates.

c) The SWPS storage area shall be capable of accommodating at least one full off-site waste shipment. It holds up to 1020 drums which provides 30

~

days of -storage time.

d) The SWPS is designed to provide at least one-day storage of evaporator bottoms production during normal generation rates.

e) The SWPS is designed to provide a reliable means of remotely handling spent resins and evaporator bottoms. A reliable means is provided to remotely handle filter particulates as required. The handling of this solid radwaste will be done while maintaining the exposure levels to plant personnel within the permissible limits of 10CFR20.

f) The SWPS is designed to prevent the release of significant quantities of radioactive materials to the environs in order to keep the exposure to the public and operating personnel within the requirements of 10CFR20 and 10CFR50.

3.5.4-1

SHNPP ER g) All radioactive waste is packaged (including the shipping container) in a manner which will allow shipment and burial in accordance with 49CFR170<<179, 10CFR20, and 10CFR71.

h) The SWPS is designed to provide remote handling of 55-gallon drums.

These containers are used in packaging of spent resins, filter particulates, and evaporatoz bottoms.

i) The SWPS is designed in accordance with seismic and quality assuzance requirements of ETSB 11-1 (Rev. 1). Design of the structure housing the SWPS to Seismic Category I requirements prevents uncontrolled releases of radioactivity due to anticipated operational occurrences. Foundations and adjacent walls are designed to the Seismic Category I criteria to a height sufficient to contain the liquid inventory in the building. The SHNPP FSAR Section 3. 2 lis ts the seismic and quality group classif ications of the SWPS.

3.5.4.2 S stem Descri tion The SWPS consists of several subsystems: 1) waste collection and pretreatment subsystem; 2) waste solidification subsystem; 3) volume reduction subsystem; 4) dry waste compaction subsystem; and 5) drummed waste handling and storage subsystem. The SWPS converts liquid wastes generated during normal plant operation into solid wastes which are then suitable for off-site burial. The flow diagrams for the SWPS are on Figures 3.5.4-1 through 3.5.4-4.

The waste collection 'and pretreatment subsystem consists of two spent resin decanting tanks and two solidification pretreatment tanks. Liquid wastes, such as evaporator bottoms (concentrates) and chemical drains are processed in a solidification pretreatment tank. This tank is used primarily for pH adjustment and mixing. From the pretzeatment tank, the wastes can be pumped directly to one of the four drumming and solidification stations or to the volume reduction subsystem. it If is processed by the volume reduction subsystem, i't is pumped from it to one of two drumming stations where the free-flowing solids are added to the 55-gallon drums on top of the cement that was added to the empty drums at the cement fill station. The drums are then transported to one of the four drumming and solidification stations. At the four drumming stations, the waste is mixed and solidified. Waste from the two decant stations is added to the drums at one of the four mixing and solidification stations, unlike the volume reduction subsystem, where no liquid is added.

The dry waste compaction subsystem compresses contaminated waste such as gloves, rags, paper, etc. These wastes are collected from various areas of the plant and manually placed in 55-gallon drums. This waste is compressed to approximately one-fourth the original volume by a hydraulic compactor. No cement is added to these wastes.

At the cement filling station, the drums have the correct amount of cement added in a nonradioactive area. The drum with cement is remotely transferred to one of four drumming stations in the shielded area or to one of two volume reduction subsystem drum fill stations. At the drumming station, the drum is positioned under a drum filling nozzle. Waste is metered into the drum from'.5

'-2

SHNPP ER exhausted, it is packaged in drums for disposal as a radioactive solid waste.

The handling of radioactive wastes is described in detail in Section 3.5.

Approximately 9 kilograms of lithium (Li7) will be used per year.

d) Sodium Chromate and Sodium Phosphate In the closed cooling systems, a mixture of sodium chromate and sodium phosphate is used to inhibit corrosion.

A concentration of about 500 ppm is maintained in these systems.

Since the systems utilizing these chemicals are closed systems, there is normally no release of these chemicals to the environment. However, during equipment maintenance, the water drained from the Closed Cooling Water Systems flows to tanks for later treatment in the Waste Mangement System, for later return to these systems for reuse or for discharge. Table 3.6.2-3 lists these and other chemicals indicating their use, frequency of use and their annual consumption.

3.6.2.3 Release of Chemicals from the Control Laborator SHNPP has a chemistry and radiation measurement laboratory equipped with all the chemicals and instrumentation needed for water and wastewater analyses.

Some typical determinations done at the SHNPP laboratory are: alkalinity, ammonia, boron, calcium, conductance, fluoride, hydrogen, hardness, hydrazine, nitrogen, iodine, iron, lithium, oxygen, pH, silica, strontium, sulfate, temperature, color, and turbidity. CP&L may contract with an outside laboratory or use the lab at the Shearon Harris Energy and Environmental Center to measure parameters such as biochemical oxygen demand (BOD), chemical oxygen demand (COD), total solids, oil and grease, fecal coliform, and copper.

The drainage from the radio-chemical sinks and the water and wastewater analyses sinks is collected in the drain tank and treated in the Waste Management System.

3~6~3 CHEMICALS RELEASED FROM THE BIOCIDE CONTROL SYSTEM Each unit is served by a single-shell 'divided water box condenser and uses the Cooling Tower to supply circulating water. Three circulating pumps are interconnected by a common discharge header serving the condenser. The effluent from the condenser is returned to the Cooling Tower.

Chlorine in the form of a chlorine solution generated from liquid chlorine in a chlorinator is applied periodically to the Cooling Tower Intake Structure and the Emergency Service Water and Cooling Tower Make-up Intake Structure to control slime growth in the condenser tubes and in the circulating water lines. Shock treating is performed two times a day using approximate 3~inute chlorination periods.

The chlorine dosage is sub)ect to seasonal variation. During the summer months, with the increased chlorine demand, the maximum dosage of chlorine may be required whereas in the cooler winter months, a lesser dosage may suffice.

The actual operating chlorine dosage is determined by a residual chlorine test in the condenser's effluent header. The chlorine feed rate and treatment time

3. 6-.3

SHNPP ER are established to deliver up to 0.5 ppm free chlorine residual in the condenser effluent. Since only one is unit chlorinated at one time, the concentration in the cooling tower blowdown will not exceed 0.2 ppm chlorine residual when all units are operating.

3 ~ 6o 4 MISCELLANEOUS CHEMICAL WASTES a) Non-Radioactive Oil Waste In the Turbine Building, the floor drains, curbed oil area drains, and equipment drains are combined into a common Industrial Waste System. Liquid from this system is directed to two internal industrial waste sumps, where it is pumped to the yard oil separator. In all other buildings, the equipment drains from equipment using oil as part of its function or process, as well as the floor drains in curbed oil areas, are routed to that building' oil sump. Sump pumps in all buildings in the nuclear island transport the oil waste to the turbine building industrial waste discharge header, where it combines and passes through a radiation monitor. If the waste is not radioactive, it flows to the yard oil separator.

The effluent from the oil separator is released to the Storm Water Drainage System, which discharges to the Main Reservoir. Removed oil is collected in tanks for offsite treatment and disposal.

If the radiation monitor indicates radioactivity is present, the oil waste is routed to the Waste management system. the treatment of radioactive wastes is described in Section 3.5.

In the Service Building, the liquid drainage from equipment using oil is routed through equipment drains and floor drains to the internal oil separator in this building. The clear effluent is released to the Storm Water Drainage System and is subsequently discharged to the Main Reservoir. The removed oil is collected in tanks for offsite treatment and disposal.

b) Floor Drains The Floor Drain System includes the floor drains in the Waste Processing Building, the Reactor Auxiliary Building, and the Fuel Handling Building.

Non-radioactive floor drainage is collected from the floor drain in the battery rooms and the electrical penetration and cable vault areas in the Reactor Auxiliary Building, standby diesel generator rooms, and the Turbine Building.

The floor drains in the battery rooms discharge to the local neutralizing tanks for neutralization. The waste then flows to the sanitary sewers for further disposal.

The standby diesel generator rooms are provided with floor drains which discharge into an oil sump. Two gpm sump pumps discharge the sump content to the yard oil separator which discharges oil free'water to the Cooling Tower Blowdown System.

The Turbine Building is provided with floor drains'o accept normal maintenance washdown wastewater, as well as any potential discharges from a piping rupture. Like other turbine building drainage wastes under normal conditions, the floor drain discharges are routed to the turbine building industrial waste sumps for discharge to the yard oil separator.

3.6-4

SHNPP ER c) Preoperational Systems Hydrostatic Testing and Flushing Wastewater-Since it is not anticipated that the preoperational cleaning of systems at SHNPP will require the use of acid or caustic reagents, there will not be any metal cleaning wastes. However, during the preoperational phase, systems conveying fluids will undergo flushing and/or hydrostatic testing. Flushing consists of the high velocity flow, of potable or demineralized water through these systems for the purpose of removing construction debris, dirt, etc.

which might have accumulated during construction. Hydrostatic testing is a procedure used to test for leaks. An EPA approved dye will be used during the condenser hydrostatic testing procedure.

Hydrazine and ammonia are expected to be added to the flush and hydrostatic testing water. In addition, some systems might require the use of a wetting agent to complete these procedures.

The hydrostatic testing and flushing wastes for each unit are expected to be produced on a one time basis and are anticipated to produce a combined total volume of from 15 to 20 million gallons of wastewater. These wastewaters will be collected, sampled, treated as necessary to meet discharge requirements, and released to the Hain Reservoir.

d) Periodic Discharge (1) Steam Generator Blowdown Under normal operating conditions, the steam generator blowdown is treated in the Steam Generator Blowdown System and reused by returning the water to the condenser. If under certain circumstances the steam generator blowdown is not returned to the condenser, the blowdown, if found to be non-radioactive, is conveyed to the SHNPP chemical treatment systems for treatment and disposal.

3.6-5

SHNPP ER 3 ' TRANSMISSION FACILITIES The transmission facilities description as presented in Section 3.11 of the SHNPP Construction Permit Environmental Report requires no updating except for the Harris-Harnett (Erwin) 500 kV Line and the Harris-Method 230 kV Line.

The Harris-Method Line now terminates at the Cary Switching Station instead of the Method Substation as indicated in Section 3.11.8.2 of the SHNPP Construction Permit Environmental Report. This termination point is the same location as illustrated in Figure 3.11-6 of the SHNPP Construction Permit Environmental Report, and is approximately five miles shorter than the

'originally-proposed line. The location of this line is identified in Figure 3.9.0-1.

The Harris-Harnett Line was located after receipt of the Construction Permit for SHNPP. A complete description of this line, as required by Regulatory Guide 4.2, is contained in the following subsections.

3.F 1 GENERAL DESCRIPTION The Harris-Harnett 500 kV Line has three 1590 MCM ACSR conductors per phase which yields a normal and emergency load capacity of 4025 MVA. The typical span length is 1,200 feet with a minimum ground clearance of 36 ft. The typical structure is a rusted brown steel tower (Cor-ten or equivalent) as illustrated in Figure 3.9.1-1.

3 '.2 TRANSMISSION RIGHTS-OF-WAY

3. 9.2. 1 General Description The Harris-Harnett 500 kV Line extends from the SHNPP 500 kV switchyard to the Harnett 500 kV Substation, a distance of 27.8 mi. (Figure 3.9.2-1) ~ The line is constructed on a 180-ft. wide corridor and requires 607 ac. of right-of-way.

3. 9.2. 2 Land Adjacent to Right-of-Way The terrain through which the Harris-Harnett Line passes is gently sloping to flat. The present land use is primarily agricultural with some timber production and surface mining interspersed between small rural communities.

The land use is expected to change very little in the foreseeable future.

However, some population growth is expected around the towns of Lillington, Fuquay-Varina, and Buies Creek.

The major vegetation along the proposed route is a mosaic of agricultural fields, cutover forests, pine plantations, and various pine-hardwood and hardwood forests, all typical of the upper Coastal Plain and lower Piedmont physiographic provinces. The northern one-quarter of the route (Piedmont) is dominated by second and third growth pine and pine-hardwood forests. The southern three-quarters of the route (Coastal Plain) is dominated by agricultural fields interspersed between small bands of bottomland forests associated with streams of the Cape Fear River drainage system. Only 150 ft.

of the 180-ft. right-of-way was totally cleared. This accounts for the 3.9-1

SHNPP ER clearing of 103 ac. in the Piedmont and 213 ac. in the Coastal Pla1n Physiographic Region- Therefore, there was approximately 316 ac. of total clea ring.

The Harris-Harnett Line crosses 5 primary and 23 secondary roads. The primary roads crossed are U.S. 401, N.C. 42, N.C. 55, N.C. 27, and N.C. 210. Where natural vegetation exists, a vista screen will be maintained on these primary roads-The Harris-Harnett Line also crosses three railroads. Prior to construction, crossing permits were obtained, and line clearance meets or exceeds National Electrical Safety Code requirements The Harris-Harnett Line crosses s1x minor streams and eight farm ponds. A buffer zone of natural vegetation will be retained, where feasible, that will prevent erosion of the stream or pond bank. There are no navigable stream or river crossings.

The Harris-Harnett Line crosses no,known archeological, historical, or recreational sites.

The Harris-Harnett Line presents no hazard to aer1al nav1gation. All structures were designed well within the 200-foot vertical regulation of the Federal Aviation Administration guidelines Also, the proposed line is not located near any approach zones to the area's airports.

3.9.3 ELECTRICAL EFFECTS The electrical effects of high voltage transmission lines can be divided into two categories: (1) those resulting from corona, and (2) those resulting from the electric field.

Corona on high voltage transmission lines can cause television and radio interference, production of ozone (03), and acoustical noise. These effects can be minimized or eliminated by controlling corona on the line. The 500 kV lines associated with the SHNPP are designed to be generally corona free.

Since the lines are essentially corona free, no significant television or interference, ozone production, or acoustical noise is expected. 'ad1o Strong electric fields from high voltage transmission lines can induce measurable voltages in metal objects located near the transmission line. The electric field cannot be eliminated, but its effects can be minimized by physically separating the high voltage conductors from large metal objects.

The line design and right-of-way width associated with the Harris-Harnett Line generally prevent induction into adjacent metal objects Should any unanticipated problems occur, CPEL is committed to cooperating with property owners and the general public to resolve such situations.

3i9 ~ 4 ALTERNATIVE RIGHTS-OF-WAY Alternative routes considered for the Harris-Harnett Line are discussed in Section 10,9.

3.9"2

SHNPP ER 4 ' ENVIRONMENTAL EFFECTS OF SITE PREPARATION, STATION CONSTRUCTION) AND TRANSMISSION- FACILITIES,CONSTRUCTION, II I 4.1 'SITE PREPARATION AND STATION CONSTRUCTION The intent of this section is to discuss potential areas of impact associated with site construction activities at the Shearon 1larris Nuclear Power Plant.

Section 4.5 identifies mitigative measures and assesses the type and extent of

, the resulting. impact Land area requirements (Table 4 1-1) and estimated construction work force (Table 4.1-2) are also tabulated in this section.

Construction activities commenced on January 14, 1974, following issuance of the Limited Work Authorization and on Janua ry 27, 1978, following "issuance .

of the Construction Permit. Construction 'activities will be continuous until',

commercial operation of the 'fourth unit is achieved.

4.1.1 LAND RESOURCES Land resources affected by construction activities were the 5,338 acres of the approximately 10,800 acre site area. The following serves as a to facili,tate identification of potential areas of general'checklist These, areas are discussed in detail in Section 4.5.

construction'impact.

a) Runoff and erosion b) Vehicle washdown c) Solid and liquid waste disposition d) Dust e) Noise f), Fuel and oil storage g) Landscape restoration h) Explosives i) Smoke g) Excavation r k) Agricultural productivity I) Trans po rta tion 4~ 1 ~ 2 CULTURAL RESOURCES" There were no areas of historical, archaeological, or natural significance that were affected by construction (see Section 2.6) ~ However, two benchmarks used by the U. S. Geodetic Survey were located within the area affected by project construction. The North Carolina Geodetic Survey 4.1-1

SHNPP ER

'I requested that CP&L destroy each of these markers, and the U. S. Geodetic Survey was informed oE their destruction.

4.1.3 - TERRHSTRXAL COMHUNXTXRS The most signif1cant unavoidable'impact on the terrestrial ecosystem resultinp from site preparation and construction of SHNPP was the con'version of the previously exist1ng terrestrial wildlife habitat oE the Hain and Auxiliary Reservoir areas to aquatic ecosystems. Other terrestrial habitat losses or modifi.cations have resulted from construction of various facilities such as the transmission corridors, makeup water pipeline, access roads, and pump station at the Cape Fear River. (Table 4.1-1).

1 .As discussed in Section 2.2.1. I, the native flora'f the site had been previo<<sly d5sturbetl by agric<<] t<<ral and timber production acti.vities and was typical of the vepetation found throuphout the P1edmont of North Carolina.

Thus, the development of the SHNPP site involved only a smal1 part of'a larpe area of similar habitat. The area cleared for the rest rvoirs and plant facilit;ies was composed primar1ly of second growth pine and pine-hardwood communities common to this area oE the Piedmont. These pine communities and several other plant communities once located in the area cleared for the reservoirs (Section 2.2.1.1) will be partially replaced by aquatic communities as the reservoirs are'illed and 'natural succession'ccurs.

Aquatic vegetation will develop mainly in the shallow areas oE the "

reservoirs.

Present. yepetation alonp the marpin of .the reservoirs may gradually shift in compositio'n to species characteristic of wetter habitats. Natural vegetation in the areas used for plant site facilities will be replaced by ornamental plants, lawns, and various other cover species.

Where the cleared areas are inu>>dated,"the overall lonp-term efEect is the loss of that land's terrestrial productivt.ty for as long as the reservoir.

exists. Xn other areas where cleared land is revegetated naturally or by means.oE artificial seedinp or plantinp, the habitat alteration resulting from construction will cause, only temporary changes in the species diversity and population levels. As such areas propress-'through the stages of secondary succession, wildlife will 'repopulate the available habitat.

l The most obvious and important unavoidable effect of construction on wildlife was the displacement or loss of the 1ndivt.dual animals occupyinp the areas which were, cleared. The larger, more mobile animals were able to avoid immediate destruction by moving into adjacent areas. However, intraspecific and interspecific competition for food and space probably increased, especially where existing wildlife populat1ons were at or near the capacity. Ultimately, it can be expected that the animal populations habitat's'carryinp in these areas will reach an equilibrium with each other and the available habitat, reflecting an overall loss approximately equal to the number of animals oripinally displaced from'he areas cleared. Hany of the smaller, less mobile animals were not capable of escaping the'learing process and probably were el1minated immediately.

4. 1-2 Amendment No. l

SHNPP ER Movement of workers and equipment during peak periods of site preparation and construction will temporarily disrupt normal behavior patterns of some local fauna. Movement patterns, antipredatory behavior~ reproductive behavior, and general intraspecific .audigory communication between some species may be affected by noise,,traffic, and dust resulting from construction activitie's. Such effects will be short-term and will not,have serious long-term consequences. In areas where animals are driven out or disturbed during construction, the return or recovery of those animal populations 1s expected to be quite rapid.

Once construction activities are completed, some areas of land previously committed to construction activities or other land use will be reforested or revegetated. As 'these areas progress through natural successioral stages, both food and,cover will be provided for many w1ldlife .species.

The reservoirs constructed for the operation of the SHNPP will, significantly increase the value of the site as waterfowl and furbearer habitat. The aquatic environment will enhance local populations of certain species of waterfowl by providing food, resting places, and in some cases, nesting sites.

Furbearing species which characteristically inhabit aquatic communities will benefit by the increase in shoreline habitat. Many woodland, marsh, and wading species of birds will utilize the shoreline habitat around the reservoirs. The reservoirs and the margins of the reservoirs also provide suitable habitat for many amphibian,and aquatic reptile species.

Of the threatened and endangered, terrestrial vertebrate and plant species identified on or near the SHNPP site, none are expected to be a'dversely affcted .by site preparation or const'ruction activities. A discussion of these species and their status at .the SHNPP site is in Section 2.2.2.3.

4.1.4 AQUATIC COMMUNITIES The local flora and fauna inhabiting the various creeks comprising the Whiteoak-Buckhorn drainage basin are discussed in Section 2.2.0. These local communities will exhibit alterations of species composition and relative abundance as the present system of free flowing streams is impounded for the Main and Auxiliary Reservoirs. Alterations in species composition 'and relative abundance will occur as organisms well adapted for stream (lotic) habitat are replaced by plants and animals which are blotter adapted for lake (lentic),habitats.

erosion control measures designed to minimize siltatinn and

'lthough sedimentation effects were initiated after approval by appropriate'-

regulat'ory agencies, construction activities for reservoir basin clearing and site preparation, as expected, have'esulted in some impacts to the per1phytic, benthic and fish communit1es. Changes in these communities that occurred during the initial stage of construction activity included decreased abundance and diversity of aquatic communities,, reduction. of silt intolerant organisms, limitation of food and habitats, interference with filter feeding activities, and. scouring. 'Because all these effects are associated with siltation and sedimentation resulting from land clearing and

4. 1-3 Amendment No. l

SHNPP 'ER other initial construction activities, it is expected that the stream communities will temporarily recove'r prior to filling of the reservoirs.

wi.th the completion of the Main and Auxiliary Reservoir Dams and the -'owever, filling of the reseqvoirs, the following changes in algal, benthic macroinvertebrate, and fish communities vill occur:

a) Algal Community The periphytic algae present in the SHNPP stream system are predominantly rheophilic (those found mainly in flowing .

waters); however, some are also common in the littoral zones of lakes. The benthic algal forms present in the streams will be replaced by planktonic forms as'he reservoirs are filled. Consequently, the plankton assemblage .

will be more important to pr'oductivity than periphytic species.

A species shift is expected from the dominant stream benthic diatom population to 'small green algae with true planktonic diatoms predominating in the reservoirs. Some blue-green algae will also exist in the reservoirs.

Achnanthes, Cocconeis, Gomphonema, Navicula, and Nitzschia are some of the common benthic genera presently found in the streams which will not be as

, abundant in the reservoirs. Asterionella, Cyclotella, Melosira, and

,~Snedri; common planktonic dd'atoms, are.present Xn the SHNPP streams and csn be expected to be found in abundance when the reservoirs are filled.'i There is'a possibility, depending on the flushing rate, of eutrophication occurring in some of the shall,ow arms of the reservoir due to high nutrl.ent loadings from the creeks, feeding the arms. With a slow flushing rate, a potentia'1 for excessive blue-green', algae populations'nd eutrophi'cation could occur in the shallow areas.

,Zooplankton expected to be found in the reservoirs should'be similar to genera found in lakes of the Piedmont of North Carolina. Genera that may be.

present include the rotifers (Keratella, Polyarthra, and Synchaeta); the Y.

'haoborus. A .stable zooplankton population will not be achieved until .

to 4 years after the reservoirs are filled, and so considerable fluctuation in densities and species may be expected during this period.

b) -

Benthic Macroinve'rtebrate Community As the reservoirs begin filling, a succession of benthic macroinvertebrate communities will occur.. This succession'may follow a pattern similar to that reported by Weiss et al.,

for Belews Lake, North Carolina (Reference 4.1.4-1). According to Weiss et al.,

the succession of the benthic community began as water filled Belews Lake. The Belews Lake data indicated a- decline in the number of taxa collected due to a loss of rheophilic organisms inhabiting lotic environments. The initial stage of lake colonization was marked by high local densities of many, different kinds of organisms distributed in highly mosaic patterns. This initial stage was overlapped by a second stage of colonization when benthic species favored by water level fluctuations and high debris levels bec'arne dominant. A third stage of colonization, characterized by organisms adapted to lower water level fluctuations and lower. debris concentrations, was observed, when Belews Lake reached normal pool.'

4".1.4 Amendment No. 1

SHNPP ER TABLE 4. 1-1 LAND AREA REQUIREMENTS AFFECTED BY STATION AND STATION RELATED FACILITIES The total site is approximately 10,800 acres (See Figure 2. 1.1-1); the following acreage was required for actual construction work:

Facilities Acres Main Reservoir 4, 121 Main Dam 40 Main Dam Access Road Main Reservoir Makeup System 57 Auxiliary Reservoir 335 Auxiliary Dam Spillway Auxiliary Dam 138 Auxiliary Separating Dike 12 Auxiliary Reservoir Channel Borrow Areas for Main and Auxiliary Reservoir Dams 76 Main Plant 437 Aggregate Rescreen Main Access Road 17 Cooling Tower Blowdown Line 13 Construction Access Road Emergency Service Water Channels Southwest Spoil Area for Main Plant 23 Plant Access Railroad Spur Spoil Areas for Railroad Relocations 30 Total 5, 338

4. 1-6

SHNPP ER TABLE 4- 1-1 (Continued)

LAND AREA REQUIREMENTS AFFECTED BY STATION AND STATION RELATED"FACILITIES Facilities Acres Onsite and Offsite Transmission Line-Corridors (pre-existing rights-of-way not included; onsite rights-of-way acreage not additive to the 5,338 acres required for onsite constiuction) 2, 560

4. 1-7

SHNPP ER TABLF. 4.1-2 ANNUAL SCHEDULE OF ESTIMATED WORK,.FORCF.

Year Average - Yearly Manpower 1'982 3,864 1983 3,914 1984 4,026 1985 3%.176 1986 2,814 3,384

'987 1988. 3,480 1989 3,639

~

1990 2,916 1991 2,095 1992 1,197 1993 1994 247

'ote: The above totals include constructor, contractors, site nuclear plant construction, and site quality assurance personnel for Units 1, 2,' and 4, based on an.in-service date of March, 1988 for Unit No. -2'.

4. 1-8 Amendment No. l

SHNPP ER 4+2 TRAilSMISSION FACILITIES CONSTRUCTION The purpose of this section is to describe the effects of transmission facilities construction on plant, wildlife, and human populations.

Information presented in Sections 3.11.5 and 3.11.9 of the SHNPP Construction Permit Environmental Report requires no updating except as discussed below for the Harris-Harnett 500 kV Transmission Line. Section 3.9 of this report provides a general description of the Harris-Harnett 500 kV Transmission Line.

4.2.1 EFFECTS OF RIGHT-OF-WAY CLEARING ON PLANT AN) ANIMAL LIFE Clearing the right-of-way displaces some existing plant and animal communities for the life of the transmission lines. However, this displacement introduces new and more varied communities which, in many cases, benefits existing ecosystems. Environmentally sensitive areas, such as Raven Rock State Park and the Cape Fear River, were avoided during the location process. However, the presence of a limited impact along the corridor must be acknowledged.

4.2.1.1 Clearin Techni ues In the right-of-way portion totally cleared, all woody vegetation was cut within four in. of the ground. All cut debris was windrowed on each side and completely within the right-of-way boundaries, leaving an unobstructed construction strip. A vista screen was left and maintained at major road crossings, where existing vegetation permitted. At major stream crossings, a buffer zone not less than 10 ft. each side of the stream was maintained.

Typical clearing was performed with a bulldozer utilizing a K/G blade, and manual clearing was done on all steep slopes to prevent soil erosion. Outside the right-of-way, all trees that would fall within 10 ft. of the nearest conductor were considered "danger trees" and were cut to fall parallel with

'he corridor. The right-of-way will be maintained in accordance with the above specifications that accomodate a danger tree cutting and mowing cycle approximately every three-to-five years.

4.2.1.2 Effects on Flora As a result of clearing the corridors, plant communities adapted to the open field environment replace shade-tolerant species. During the transmission line's life, this open field environment will be maintained by mowing the corridor every three-to-five years. Carolina Power & Light currently uses no herbicides to clear or maintain the right-of-way. Should the transmission lines no longer be needed, the climax plant communities would become reestablished through secondary succession.

The major vegetation types of mixed hardwoods and pines found along the corridor is identified in Table 2.14 of the SHNPP Construction Permit Environmental Report. After the corridors were cleared, secondary succession permitted various grasses, sedges, and asters, and some pine saplings to become established.

4. 2-1

SHNPP ER Clearing the corridor is not expected to promote changes to the existing aquatic communities. Other than the selective danger tree cutting, a natural vegetation buffer zone was maintained at major stream crossings.

Minimal erosion occurred along the corridors as a result of topographic relief. Where steep slopes occurred, the area was seeded based on USDA Soil Conservation Service recommendations. Once the surface revegatated, the open field communities became established and further stabilized the steep slopes.

4.2.1.3 Effects on Fauna Clearing the corridors in wooded areas created an "edge effect" or ecotone.

This transition zone is favorable to some wildlife species while unfavorable to others but minimal effects were expected to adjacent undisturbed communities. As a result of clearing through a typical woodland, the following three ecological effects occurred: 1) exclusion of pre-existing species, 2) enhancement for pre-existing species, and 3) encouragement for previously absent species.

Species excluded from the corridors were those which were restricted to the adjacent woodland environments. Such bird species probably include but are not restricted to the wood warblers (Parulidae), woodpeckers (Picidae),

Carolina chickadee (Parus carolinensis), tufted titmouse (Parus bicolor),

flycatchers (Emphidonax), nuthatches (Sittidae), thrushes (Turdidae), and the vireos (Vireonidae). Examples of mammals that were probably excluded were the white-footed mouse (~perom acus ~leuco us) and the golden mouse (Peromyscus nuttalli).

Species which were present but have derived benefit from the corridor include the bobwhite (Colinus virginianus), vultures (Cathartidae), falcons (Falconidae), hawks (Accipitridae) foxes (Carnidae) and possibly other predators. These species were attracted to corridors where an abundant food supply existed.

Species previously absent but attracted to the corridors were typically associated with open spaces or brushy habitats. Such bird species probably include but are not restricted to various sparrows (Spizallidae and Melospizidae) eastern meadowlark (gturnella ~ma na), red-winged blackbird

(~delaius ~hoeniceus), blue grosbe~ak Guiraca caerulea), prairie warbler (Dendroica discolor), common yellowthroat (Geothlveis trichas),

yellow-breasted chat (Icteria virens) and indigo bunting (Passerina cyanea) among others. Invading mammals probably included the rice rat (Oryzomys

~alustr1s), hispid cotton rat (~Si meden ~his idus), meadow vole (Microtus addition to these species, there were numerous other species attracted to the edge areas along streams and adjacent to the corridor (Reference 4.2.1-1).

4.2e2 ENVIRONMENTAL EFFECTS OF ERECTING STRUCTURES AND STRINGING CONDUCTORS 4.2.2.1 Construction Techni ues Structure foundations were dug by either a truck or track~ounted auger. Some blasting was required when rock was encountered while digging the foundations.

4. 2-2

SHNPP ER Areas where a high water table existed were pumped to keep the hole dry.

After the foundation holes were dug, the conc'rete was poured. In some cases, the structure site required minor grading.

Lattice steel was hauled to each structure site where the tower was partially assembled. Once the structure was erected and completely assembled, rubber-tired and track equipment was used to string the conductor. Carolina Power & Light Company specified conductor sag clearances which met or exceeded National Electrical Safety Code requirements.

4. 2. 2. 2 Environmental Effects Erecting structures and stringing conductors had a minimal impact. The most notable effect was construction noise created during the construction phase.

However, the construction noise was generally confined to the right-of-way and caused only a temporary impact. Such an impact was not considered significant to wildlife or human populations.

4o 2o 3 CONSTRUCTION OF ACCESS ROADS Carolina Power & Light Company does not build access roads to the proposed corridors. Existing public and private roads provide the necessary access.

Concrete trucks used the corridor as access to structure locati.ons.

4. 2. 4 EROSION DIRECTLY TRACEABLE TO CONSTRUCTION ACTIVITIES Prior to construction, an Erosion Control Plan was filed with the State of North Carolina according to the rules and regulations of the Sedimentation Pollution Control Act of 1973. This plan specifies protective measures where the potential for significant soil erosion exists. Special emphasis is placed on steep slopes, severely erosive soils, and the crossings of all streams, rivers, ponds, and lakes.

The Universal Soil Loss Equation (Reference 4. 2. 4-1) shows that 3008 tons/year of soil would be lost along the corridor if the soil were left unreclaimed.

The following discussion explains the Universal Soil Loss Equation and the assumptions and rationale behind its utilization:

A ~ KRLSCP Where; A the average annual predicted soil loss in tons per acre K ~ the soil erodibility factor R the rainfall factor L slope length S percent slope C ~ the cropping-management factor [equals one (1) based on no cropping-management] and P the erosion control practice factor [equals one (1) based on no farming erosion contxol practices being undertaken]

4. 2-3

SHNPP ER Assumptions and rationale:

1) That the soil surface is bare and there are no erosion control practices. Rationale for this assumption is that no erosion control practices should be calculated to maintain a degree of relativity in showing the worst case.

2) That only slopes of 10 percent grade or more will be calculated. The rationale for this assumption is that only the potentially significant amounts of soil loss will be measured since comprehensive data would be too voluminous for this statement.

3) That the'ominant soils in the association are the only taxonomic units which occur along any portion of the proposed right-of-way as identified by the Soil Conservation Services general soil maps Rationale for this assumption is that since site specific information is not available, the chosen taxonomic unit represents all the soils in the association and its inclusions.

4+ 2+ 5 EFFECTS OF CONSTRUCTION ON AGRICULTURAL PRODUCTIVITY The construction of transmission lines had a minimal impact on agriculture productivity. Some cropland was temporarily disturbed during structure erection and conductor installation. However, once the line was constructed, only the area where the structures were located was lost to crop production.

The landowner can use all remaining land on the corridor at his discretion, providing he does not endanger the line's integrity.

The Harris-Harnett Line crosses approximately 10 4 miles of agricultural lands. This amounts to 37 percent of the total line length and equals 227 acres of right-of-way. The estimated loss of agriculture productivity where the towers are located is approximately 2.3 acres.

4~ 2 ~ 6 EFFECTS OF CONSTRUCTION ON ENDANGERED SPECIES The Harris-Harnett Line had no identifiable impact on any known endangered species.

4. 2-4

SHNPP ER 4.4 RADIOACTIVITY Since the SHNPP is a four-unit generating plant and the units will be brought on-line over a period of several years, there will be a considerable number of construction workers on site completing the remaining units while the completed units are operating. The estimated annual doses at various locations for these personnel are included in the SHNPP Final Safety Analysis Report Section 12.4.

4. 4-1

SHNPP ER EXPOSURE PATHWAYS 5.2.1 ~ 1 Or anisms Other Than Man Aquatic biota may be exposed to external radiation from radiation from radionuclides in the water and sediment and to internal radiation from the assimilation of these radionuclides. In addition to uptake via the ingestion of food'rganisms, fish and invertebrates can acquire radionuclides through direct absorption from the water and can at least partially assimilate radioactivity from ingested sediment. Figure 5.2.1-1 is a flow chart representing the transfer of radionuclides through the aquatic ecosystem. The flow chart is equally applicable to the Cape Fear River and the Main Reservoir.

The organisms which constitute the lower trophic levels of the aquatic food web (plankton and benthic invertebrates) in the Cape Fear River and the Buckhorn Creek system are described in Section 2.2.2. Dominant phytoplankton are the green algae (Chlorophyta), blue-green algae (Cyanophyta) and diatoms (Bacillariophyceae). Zooplankton expected to inhabit the reservoirs should be similar to genera found in other lakes of the Piedmont of North Carolina.

Genera that will predominate include the rotifers (Keratella, Polyarthra, and Synchaeta); the cladocerans (Bosmina, Ceriodaphnia, and Daphnia); the copepods (Diaptomus, Mesocyclops, and Cyclops); and the larvae of the dipteran, Chaoborus. Rotifers probably will be the dominant taxa in the reservoirs while the cladocerans and copepods will be secondarily dominant. A stable zooplankton population will not be achieved until 2 to 4 years after the reservoirs are filled, and so considerable fluctuation in densities and species may be expected during this period. Benthic macroinvertebrates typically play an important role in the aquatic food web, serving as a link between the detrital level and the higher trophic levels. Mayfly larvae, dipteran larvae, and molluscs are examples of the benthic macroinvertebrates that are found in the Cape Fear River and associated streams and creeks in the vicinity of SHNPP. Fish feeding upon the plankton, benthic macroinvertebrates, and other fish, constitute a higher trophic level of the aquatic food web. Fish found in the SHNPP site vicinity are listed in Table 2.2.2-2.

The terrestrial ecology of the SHNPP area is described in Section 2.2.1.

Terrestrial biota may be exposed to external radiation from immersion in the plant's gaseous effluents, from swimming in water containing the plant's liquid effluents, and from direct shine from radionuclides that have deposited on the ground and shoreline. Internal exposure of terrestrial organisms may result from the inhalation of radioactive materials from the plant's gaseous effluents and from the ingestion of foods that have assimilated radioactive materials from both gaseous and liquid plant effluents. Figure 5.2.1-2 presents the pathways by which terrestrial biota other than man are exposed to radioactive material released from the SHNPP.

The routes of internal exposure to terrestrial biota other than man are highly varied due to the diversified feeding habits of the animals living in the vicinity of the site. The vegetation in the region will'receive radionuclides from deposition onto the plant foliage and from the uptake of radioactivity

'initially deposited on the ground. Deer, rabbits, squirrels and other herbivorous animals could then be internally exposed from the ingestion of 5 2 1-1

SHNPP ER this vegetation. In turn, foxes, bobcats, and other predatory animals living in the vicinity may be internally exposed to radiation from feeding on those animals that have concentrated radionuclides in their flesh.

5.2.1o 2 Man I

As a result of the operation of the SHNPP there are several potential radiation exposure pathways to man. Figure 5.2.1-3,presents the various potential pathways. These potential pathways may be divided into two categories: those pathways resulting in a radiation dose via internal exposure, and those pathways resulting in a dose via external exposure.

External exposure to an individual may result from contact with radioactivity deposited on the ground, immersion of an individual in a cloud containing radioactive gaseous effluents, or direct contact with water containing radioactive liquid effluents while an individual is swimming or engaged in a similar activity. Internal exposures may result from the ingestion of various foods, and inhalation.

5. 2. 1. 2. 1 In ternal Expo sure Liquid effluents from SHNPP are combined with the cooling tower blowdown and discharged gnto the Main Reservoir via a submerged discharge line. The annual average flow from the reservoir into the Cape Fear River is 35 cfs. It anticipated that makeup water will be pumped from the Cape Fear River into the is Main Reservoir periodically during the SHNPP operating lifetime. This indicates that the internal exposure pathway via domestic potable water intake from the Cape Fear River (nearest approximately 12 miles downstream from the plant site, Section 2.4.4) and via commercial fish and shellfish consumption (only negligible fish and shellfish catch within 50 miles of the reservoir, Section 2.1.3) will be minimal. However, recreational use of the Main Reservoir can result in internal exposures through the aquatic food chain.

The aquatic food chains, including well water, will be monitored during preoperational and operational stages in order to accurately assess the radiological impact of the liquid effluents and to verify the accuracy of preoperational estimates.

Although the majority of the land within a five mile radius of the plant site is wooded, several dairy farms and residential vegetable gardens exist within this area; therefore there exist four additional potential routes of internal radiation exposure to man. These routes result from the deposition of radioactive wastes discharged into the atmosphere. The first route is air-grass~ilk~an; the second, the airmegetab'le~an route; the third, the air-grass~eat~an route; and the fourth, inhalation. The locations of the nearest milk cow, meat animal, residence garden and site boundary for SHNPP is presented in Table 2.1.3-1. Expanded development of this area is not anticipated due to the poor septic characteristics of the soils and lack of adequate sewage and water systems.

The majority of the land within a 50~ile radius of the plant is devoted to agricultural activity which includes the following crops: 'rain, cotton, tobacco, soybeans, hay, vegetables and peanuts; livestock includes hogs, 5.2.1-2

SHNPP ER 5.2. 2 RADIOACTIVITY IN THE ENVIRONMENT In Section 3.5, the radionuclides discharged in the liquid and gaseous effluents are provided. This section considers how these effluents are distributed in the environment surrounding the SHNPP site. Specifically, estimates have been made for the radionuclide concentration: a) in the water and sediment in the Main Reservoir; b) in the atmosphere around the site; and c) on land areas and vegetation surrounding the plant.

The models and assumptions used to determine annual average air concentration (X/Q), depleted concentration, and deposition (D/Q) are described in Section 6.1.3. The meteorological data used in these models is described in detail in Section 2.3.3. The concentrations were calculated at points within a radial grid of sixteen 22.5 degree sectors centered at true north and extending to a distance of 50 miles from the station. The data points are located in each sector 'at 0.5, 1.5, 2.5, 3 'y 'y 4 7 'p 15'5'5, miles. In addition, calculations were also made at the critical receptors in and 45 each sector within five miles of the site. These distances and directions are presented in Table 5.2.2-1 along with the y/Q, depleted )(/Q and D/Q.

The highest ground level airborne concentrations in the vicinity of the site due to gaseous releases have been calculated using these meteorological data and the source terms presented in Section 3.5. The concentrations are presented in Table 5.2.2-2. The concentrations of radionuclides on the gro Ulld and in vegetation're controlled by the deposition of gaseous effluents since irrigation of cropland with reservoir water is not anticipated. These concentrations are also presented in Table 5.2.2-2 at the same location as the maximum airborne concentration.

5.2.2.1 Surface Water Models A simplified approach has been used to predict the transport of liquid radioactive effluents. This approach is conservative in that it overestimates the radiological impact of the normal operation of SHNPP. Discussions of the basic hydrologic a'nd water use data of the area are provided in Section 2.1.3 and 2.4.

5.2.2. 1 ~ 1 Transport Models Liquid radioactive wastes are diluted by the cooling tower blowdown flow prior to being released to the Main Reservoir. Assuming 35 cfs flow out of the Main Reservoir, mixing in 80 percent of the Main Reservoir volume, and the release quantities from Section 3.5, the expected concentrations of radionuclides in the cooling tower blowdown and the Main Reservoir are presented in Table 5.2.2-3. The concentrations in the reservoir. were calculated using the completely mixed, closed loop dispersion model presented in NRC Regulatory Guide 1;113.

To calculate the maximum radiological impact, it was assumed that the critical biota, including man, are exposed to these reservoir concentrations.

5 2.2-1

SHNPP ER 5.2.2.1.2 , Sediment Uptake Models To calculate the exposure from shoreline activi'ties, an estimate of the

,concentrations of radionuclides in the reservoir sediment was made using the "effective" surface model presented in the Nuclear Regulatory Commissio'n

'egulatory \

Guide,1.109-

\

Although, radionuclide concentrations in the reservoir sediment have, been

'calculated, no credit has been claimed for concentration reductions of radionuclides in the surface water resulting from sediment uptake.

5.2.2.1.3 Water Use Models To calculate the radiological impact of liquid effluents from the normal operation of SHNPP, it has been assumed that the maximum exposed individual catches and consumes all of his fish from the reservoir. It has also been assumed that the quantity of water released from the reservoir is small. The calculated annual average release rate from the reservoir is 35 cfs.

5-2.2.2 Groundwater Models All plant liquid effluents are released to the Main Reservoir. In addition, because of'he low hydraulic gradient and permeability of the region described in Section 2.4, groundwater transport to surrounding private wells is extremely slow and hence, the radiological impact from the groundwater pathway is negligible. See Section 2.4.3 for additional information of groundwater.

5. 2. 2-2

SHNPP ER TABLE 5.2 '-2 SITE BOUNDARY* CONCENTRATIONS OF GASEOUS EFFLUENTS Airborne Air On Ground In Vegetation (uCi /cc) C/MPC (pCi /m2) ( Ci/k )

Kr 83M 1.71E-13 5.70E-08 ~

0 0 Kr 85M 2.91E-12 2.91E-05 0 0 Kr 85 3.76E-11 1.25E-04 0 0 Kr 87 5.13E-13 2.57E-05 0 0 Kr 88 4.10E-12 2.05E-04 0 0 Xe131M 2.22E-12 5.56E-06 0 0 Xe133M 7 '7E-12 2.62E-05 0 0 Xel33 4.62E-10 1.54E-03 0 0 Xe135 1.20E-11 1 ~ 20E-04 0 0 Xel38 1.71E-13 5.70E-08. 0 0 I131 7.87E-15 7.87E-05 l. 30E+01 1.99E+00 I133 1.03E-14 2.57E-05 1,85E+00 4 '9E-01 Mn 54 8.38E-16 8.38E-07 5 '2E+01 2.18E-01 Fe 59 2.74E-16 1.37E-07 2.53E+00 5 '8E-02 Co 60 2.74E-15 9.12E-06 9.30E+02 7 '1E-01 Co 60 1.30E-15 4.33E-06 4 '2E-02 3.57E-01 Sr 89 6.16E-17 2.05E-07 6 '8E-01 1.32E-02 Sr 90 1.11E-17 3.71E-07 7.26E+00 3.42E-03 Csl34 8.38E-16 2.09E-06 1 ~ 28E+02 2 '2E-01

'Cs137 1 ~ 40E-15 2.80E-06 9.26E+02 4 '6E-01 H 3 9.92E-11 4.96E-04 TOTAL C/MPC 2.70E-03 9.18E+07 4.70E+03

• Calculated at 2.14 kilometers in the NNE direction.

5. 2. 2-4

SHNPP ER TABLE 5.2.3-1 DOSES TO BIOTA OTHER THAN MAN FROM LIQUID EFFLUENTS DOSE (mred /yr. /unit)

INTERNAL EXTERNAL TOTAL Fish 2. 41 2. 35 4. 75 Invertebrate 1. 01 4. 69 5. 71 Algae l. 18 neg. l. 19 Muskrat 12. 6 1.57 14. 1 Raccoon 0. 68 l. 17 1. 86 Heron 72. 6 1. 56 74. 2 Duck 2. 35 13. 4 5.2.3-2

r SHNPP ER TABLE 5+2.5-1 ANNUAL POPULATION INTEGRATED DOSES Total Body Thyroid Immersion 0. 74 Direct from ground Inhalation 1.54 2. 51 Inges tion Milk 0. 52 2. 70 Heat 0. 09 0. 12 Total 5. 33 5.2.5-2

SHNPP ER TABLE 5.6 '-1 MAJOR NOISE SOURCES AT SHNPP Four cooling tower rims Four condensers Eight steam generator feed pump motors Four turbine generator assemblies Four cooling'ower stacks Twelve 336 MVA transformers Eight deaerator vents Eight steam generator feed pumps

5. 6-4

SHNPP ER TABLE 5. 8. 2-1 TOTAL ESTIMATED COSTS FOR POSSIBLE DECOMMISSIONING CHOICES Decom- Decommissionin Costs ($ millions)(a) missioning Number of Years After Reactor Shutdown Dismantlement is Deferred Mode 0 10 30 50 100 Immedia te 42. 1 Dismantlement Preparations for 12. 6 12. 6 12. 6 12. 6 Safe Storage Continuing Care 0.6 2. 2 3. 7 7.8 Deferred 37. 0 37. 0 30. 5(c) 30, 4(c)

Dismantlement Total 42. 1 50. 2 51. 8 46. 8 50. 8 Decommissioning Cost

( )Values include a 25% contingency..

( )Values are in constant 1978 dollars.

)These reduced values result from lesser amounts of contaminated materials for

.burial in a licensed disposal site.

5. 8-3

TABLE 5.8 '-1

SUMMARY

OF SAFETY ANALYSIS FOR DECOMMISSIONING THE REFERENCE PMR Safe Storage with Deferred Type of Source of Immediate Dismantlement After Safet Concern Safet Concern Units Dismantlement 10 Years 30 Years 50 Years 100 Years Public Safet (a)

Radiation Exposure Decommissioning Operations man-rem 0.0001 <0.0001 <0.0001 <0.0001 <0.0001 Transportation man-rem 22 (c) (c) (c) (c)

Safe Storage man-rem neg (b) neg.(b) neg.(b) neg.(b)

Occu ational Safet Serious Lost-time Decommissioning Injuries Operations total no. 4.0 4.9 4.9 4.9 4.9 Transportation total no. 1 ~ 2 1 ~ 2 1.2 1 ~ 2 Safe Storage total no. 0 96 1.2 1.4 1.9 Fatalities Decommissioning Operations total no. 0. 029 0. 029 0. 029 0. 029 0.029 Transportation total no. 0. 068 0. 075 0 075 0.075 0.075 Safe Storage total no. 0.00087 0.0026 0.0045 0.0087

ENVIRONMENTAL REPORT OPERATING LICENSE STAGE CHAPTER 6 LIST OF TABLES TABLE TITLE PAGE

6. l. 3-1 OPERATING CONDITIONS 6. 1. 3-10 6 ~ 1 ~ 3-2 MAJOR COMPONENTS 6. l. 3-11

6. le 3-3 COMPONENT ACCURACY 6. l. 3-12

6. l. 3H SHNPP OPERATIONAL SENSOR ELEVATIONS 6. l. 3-13

6. l. 3-5 SHNPP MODIFIED DATA COLLECTION SYSTEM ERRORS 6. l. 3-14

6. 1. 5-1 RADIOLOGICAL ENVIRONMENTAL MONITORING PROGRAM 6. 1 ~ 5-10

6. 1. 5-2 NATURAL BACKGROUND AND HA&iADE EXPOSURES 6. 1. 5-21

6. 1. 5-3 BETAW~fA ACTIVITY DURING AIRCRAFT ASCENT AND DESCENT MARCH 17, 1960 6. 1. 5-22

6. l. 5H JULY, 1978 THROUGH JUNE, 1979 AIRBORNE PARTICULATE GROSS BETA CONCENTRATION AND RAINFALL DATA COLUMBIA, SOUTH CAROLINA 6. 1~ 5-23

6. 1. 5-5 JULY$ 1978 THRU JUNE$ 1979 PASTEURIZED MILK-CHARLOTTE $ No C ~ 6. l. 5-24

6. 1. 5-6 PREOPERATIONAL SCHEDULE FOR THE ENVIRONMENTAL SURVEILLANCE PROGRAM 6. l. 5-25

6. l. 5-7 ANNUAL AVERAGE DILUTION FACTORS AT THE SHNPP MINIMUM EXCLUSION BOUNDARY (1/16/76 1/15/79] 6. 1 ~ 5-26

6. l. 5-8 DISTANCE WITHIN FIVE MILES OF CENTER POINT OF FOUR REACTORS TO NEAREST SITE BOUNDARY, RESIDENCE, GARDEN, MILK COW, MILK GOAT, AND MEAT ANIMAL AS OF AUGUST 20 28, 1979 (MILES) 6. l. 5-27

6. l. 5-9 DETECTION CAPABILITIES FOR ENVIRONMENTAL SAHPLE ANALYSIS 6. l. 5-28

,SHNPP ER n ~

Total number of hours having wind flow in the direction of interest S Total number of sectors (16).

For the realistic accident assessment X/Q determination as described in Section 2. 3. 4 of Regulatory Guide l. 70, P should be selected as 50 percent.

Note that Pe can exceed 100 percent if n is sufficiently small. In those directions, the selection of a X/Q value may be ignored unless the X/Q values for that sector are very high when compared with X/Q values of Pe in other direction sectors. For each assessment, the X/Q values that are selected, for the 16 directions are compared and the highest value is utilized.

Using the described procedure and the available onsite joint frequency data, X/Q values were calculated using the Exclusion Area for the appropriate time periods.

Results obtained from these calculations are presented in the SHNPP FSAR in Section 2. 3.4.

6. 1. 3. 2. 2 Long-Term (Routine Operation) Diffusion Model Estimates Onsite annual joint frequencies of wind direction, wind speed, and stability class for the lower level of wind sensors were determined from hourly averages of temperature differences between the two wind sensing levels. These parameters were used as input to a computerized Gaussian model which calculates annual average X/Q values for distances to 50 miles from the SHNPP. The basic equation used in the diffusion model is:

(3) z(x,k) 2.032 RFk(x) 2 DEPLL)k(x) DECL(x) 'f)k[uf (uz) (x) + Dz ) ~ ]

il 0 x (0) z(x,k) 2.032 RFk(x) x 2 DEPLL)k(x) DECL(x) 'f)k (W3 ufuz3(x))

0 where:

~(x k) average effluent concentration normalized by source strength at distance x and direction k; U] mid-point values of the ith wind speed class; z

<zj(x) vertical (x) spread of effluent at distance x for jth stability class;

~ joint probability of the ith wind speed class, jth stability class, and kth wind direction; downwind distance from release point or building;

6. 1. 3-7

SHNPP ER DECi(x) ~ reduction factor due to radioactive decay at distance x for the ith wind speed class; DEPLi~k(x) reduction factor due to plume depletion at distance x for the i wind speed class, j stability class, and k wind direction; RFk(x) correction factor for air'ecirculation and stagnation at distance x and kth wind direction; and Dz ~ the building height from which effluent is released which is'sed to describe the dilution due to the building wake, effect.

Equation 5 represents the maximum building wake dilution allowed; the computer code uses the higher value of (X/Q) calculated from Equation 5.

The computer code used to generate the annual long-tenn values is the NRC program "XOQDOQ" described in NUREG-0324. The recirculation factors for an inland location are specified as input along with the exclusion boundary distances and the special points of interest.

The results obtained from these calculations are presented in the SHNPP FSAR in Sec tion 2. 3. 5.

6. 1.3. 3 Operational Meteorolo ical Monitorin Pro ram The operational phase of the onsite meteorological monitoring program will be basically a continuation of the preoperational program with certain modifications. The instrument modifications were made in 1979 and described in Section 6. 1. 3. 1. Additionally, the meteorological information will be collected by the SHNPP Radiation Monitoring System (RMS) for display and utilization in the plant control room.

The RMS will be linked in parallel to the existing meteorological collection system and continuously transmit information on site weather conditions display and emergency response. The RMS system will store the onsite data for future reference, however it will not be used in report preparation, since the data will be unedited.

Meteorological data transmitted to CPGL's General Office in Raleigh will be periodically reviewed by the meteorological staff and posted to reflect deviations in instrumentation calibrations or other known anomalies. The edited meteorological data set will be transmitted to the RMS computer system onsite and used as the primary source of information in the generation of reports and analysis requiring onsite meteorological information.

The program will be continued during operation of the plant for the following reasons:

6.1.3-8

SHNPP ER

6. 1.4 LAND 6.1.4.1 Geolo and Soils Information on geology and soils was obtained from exploration programs which were designed primarily to provide data for site feasibility studies and for site safety analysis. Detailed discussions of these exploration programs are included in Sections 2.5.1 and 2.5.6 of the Final Safety Analysis Report for SHNPP. The following is a brief summary of the relevant programs:

6. 1. 4. 1. 1 Preliminary Field Investigations General - Preliminary field investigations were performed to evaluate the engineering geologic and seismologic characteristics of the site. The field exploration program consisted of:

a) an engineering geologic survey of the site and surrounding areas; b) a test boring program; c) a trench excavation program; and d) a seismic refraction survey.

En ineerin Geolo ic Survey - A comprehensive survey was conducted to identify the engineering geologic characteristics of the site and surrounding area.

This investigation included detailed inspections of: 1) rock cores from test borings; 2) surface features; 3) exposed road cuts, 4) excavated trenches, and

5) bedrock outcrops, and a Brunton Compass survey.

Geologic maps, literature, gravity survey data, aerial photographs, and topographic maps were examined. Representatives of local and state agencies, universities, and private organizations were interviewed to obtain engineering geologic data.

Geolo ic Borin s - Numerous geologic borings were drilled to investigate the bedrock composition, orientation, and quality across the site. The locations of the borings included the proposed plant area and the axis of the Auxiliary Reservoir Dam and spillway. The location of these borings is shown on

'I Figure 6.1.4-1.

Trench Excavation Pro ram - Twelve thousand one hundred and twenty feet of trenching was performed at the site to supplement the information obtained from the bedrock. The locations of these trenches are shown on Figure 6.1.4-1. Portions of Trenches 1 and 2 are adjacent to the plant site.

Trenches 3 and 4 are located on the reservoir dam alignment.

Seismic Refraction Surve s - The seismic refraction surveys were performed along six seismic lines for a total length of approximately 5,000 linear feet.

The purpose of these surveys was to determine the depth and configuration of the bedrock surface in the plant and Auxiliary Reservoir Dam areas. The

6. l. 4-1

SHNPP ER locations of the seismic lines are shown on Figures 6.1.4-2, 6.1.4-3, and

6. 1. 4H.

6. 1. 4. 1. 2 Design Subsur face Investigations An extensive program of design subsurface investigations was conducted in order to evaluate foundation conditions for the plant and other structures such as dans, dikes, channels, roads, and railways, and to explore and sample potential borrow areas.

Foundation Borin s and Excavations - Several hundred borings were drilled to evaluate foundation conditions for the power plant, the Main Reservoir Dam, the Auxiliary Reservoir Dam, the Auxiliary Reservoir Separating Dike, the Auxiliary Reservoir, the Emergency Service Water Intake and Discharge Channels, the Cooling Tower Make-up Water Intake Channel, other reservoir-related structures, and relocated highways and railroads. The locations of borings in the power plant vicinity are shown in Figures 6.1.4-1, 6.1.4-5, and 6.1.4-6. Locations of borings in the Main Reservoir Dam area are shown in Figures 6. 1.4-7 and 6. 1. 4-8, and borehole locations in the Auxiliary Reservoir Dam area are shown in Figures 6. 1.4-3 and 6. 1.4%.

Two test trenches were excavated in the foundation for the Auxiliary Reservoir Dam with a Case 580B backhoe for the purpose of obtaining undisturbed representative block samples of the dam' foundation soils. The location of the trenches, identified as TPA 1 and TPA2, are shown in Figure 6.1.4-3.

Borrow Area Borin s and Test Pits - Uncased auger borings were drilled in three potential borrow areas in order to obtain 25 lb. bag samples of soil for laboratory investigations. Test pits were also excavated in each borrow area to obtain 300 lb. representative soil samples containing the proper proportion of the different types of soil observed in the pit. The locations of boreholes and test pits in Borrow Area Y are shown in Figure 6.1.4-2; those in Borrow Area Z are shown in Figure 6.1.4-3; and those in Borrow Area M in Figure 6. 1.4-7. I Seismic Refraction Surve - A seismic refraction survey consisting of six survey lines was conducted along the Main Dam centerline and in the spillway area in order to determine depth to bedrock and general excavation conditions.

The locations of these survey lines are shown in Figures 6.1.4-7 and 6.1.4-8.

6. 1.4.2 Land Use and Demo ra hic Surve s The majority of the land use characteristics for the area immediately surrounding the plant (0 mi. to 5 mi.) were collected by actual on-site observations. Specific on-site surveys were documented as indicated by respective references throughout Section 2.1. Surveys were conducted as near to the tendering date of this report as was reasonably possible.

Where required, source literature and materials were, used, as indicated by text references. An attempt was made to use the most current literature available. On occasion, personal communications were necessary to document data.

6.l. 4-2

SHNPP ER TABLE 6 ' ~ 5-2 NATURAL BACKGROUND AND MANMADE EXPOSURES Dose Natural Back round ~(mrem/ r)

Internal Exposures K-40 19 H-3 0. 001 C-14 0.7 Rb-87 0.3 Total Average Internal Exposure 20. 0 External Exposures Cosmic Radiation Average 30 Variability 28-50 Terrestrial Radiation

,Average 44 Variability 20-100 Total Average Exposure 74 Manmade Ex osures Medical (gonad exposure) 300 mrem/x-ray Average 0-3000 mrem/x-ray Variability 4 mrem/yr Fallout (1969)

Sources:

1. National Council on Radiation Protection and Measurements, Natural Back round Radiation in the United States, NCRP Report No. 45, Washington, D. C. 1975.

2. United Nations Scientific Committee on the Effects of Atomic Radiation, Ionizin Radiation: Levels and Effects. 1972.

3. Advisory Committee on the Biological Effects of Ionizing Radiations, The Effects on Po ulations of Ex osure to Low Levels of Ionizin Radiation, U. S. National Academy of Sciences, National Research Council, Washington, D. C. 1972.

6.1.5-21

SFNPP ER TABLE 6.1 ~ 5-5 July, 1978 thru June, 1979 Pasteurized Milk - Charlotte, N. C.

Radionuclide 137Cs 148Ba 1311 Concentration pCi/l +e pCi/1 +e pCi/l +e Date July 78 18 + 15 -7 + 19 2+ 13 August 78 11 + 15 -5 + 19 -5 + 13 September 78 11 + 15 -4 + 19 -9 + 13 October 78 7+ 7 2+ 8 5+ 7 November 78 8+ 15 9+ 20 -1+ 13 December 78 6+ 15 9+ 20 6+ 13 1/2/79 3+ 15 -11 + 19 -10 + 13 1/8/79 6+ 7 -4+ 8 4+ 7 2/5/79 8+ 15 -2 + 20 4+ 13 3/5/79 8+ 15 1+ 20 <<6 + 13 4/2/79 -2 + 15 -3 + 20 1+ 13 5/7/79 16 + 15 2+ 20 1+ 13 6/4/79 5+ 15 -7 + 19 2+ 13 e 2 Sigma Counting Error Source: U. S. Environmental Protection Agency, Environmental Radiation Data, Reports: 15, 16, 17 & 18, Technical Services Branch, Eastern Environmental Radiation Facility, Montgomery, Alabama

6. l. 5-24

SHNPP ER

REFERENCES:

Sf'.CTION 6.1 (Continued) 6.1.4-2 Elect ric Power Research Tnstf tut:e prepared by Sipma Research, Inc.

Gufdrl,fnes For Est.fmat,lnp Present nnd Fnrecnstfnp F<<ture Population Distrib<<tinns Surroundfnp Power Reactor Sf tes, Specfal Repnrt E1'Rf EA-427-SR Palo Alto, Ca., 1976.

6.1.4-3 State oF. North CarolinaOffice of State Budget and Hanapement. ffp-date North Carolina Population Projections. Raleigh, North Carolina.

July 1981.

6.1.4-4 U., S. Department of Commerce, Bureau of the Census, Projections of the Population oF. the United States: 1977 to 2050, Series P-25,'o.

704, U. S. Government Printing Office, Washington D. C., 1977

1. 4-5 'United Stat'es Atomic Fnerpy Commission, Revised Final Environmental Statement Related to Construction of Shearon ffarris Nuclear Power

'Plant, Units l, 2, 3 and 4 Carolina Power h Light Company, 1974.

6.1.4-6 Carolina Power F Upht Company prepared by Aquatic Control, Inc.,

Baseline Biota of the Shearnn ffarris Nuclear power Plant Area, North Carolina. Raleiph, N.C., f1974).

6.1.4-7 ,'repared by Aquatic Control, Inc., Baseline Biota nF .the Situ<<ron lfnrrfs Nuclear 1'ower plant Stuily bren, J<<ne 1973 Hay 1974, Raleigh, N.C., 1975.

6.1.4-8 Shearon Harris Nuclear Power Plant Pre-Construction 1'fonitoring Report, Terrestrial Biology (June 1974-January 1978), Water (hemistry (1972 1977), Raleiph, N.C., 1978.

6. 1. 4-9 Shearon Harris Nuclear Power Plant, Annual Environmental Honltoring Report, Water &emistry, Aquatic Biolnpy, Terrestrial Biology, 1978 Raleigh, N.C., 1979.

6.1.4-10 Shearon Harris Nuclear Power Plant, Annual Fnvironmental Honitoring Report for 1979, Raleigh, N. C. 1981

6. 1. 5-1 (DraFt) Radiological FFQ uent Technf cal SpeciFlcatinns for PWR's NUREG-0472 Revision 3, March, 1979.

6.1.5-2 U. S. Nuclear Regulatory tommlssion, Repulatnry Guide 4.8 Environmental Technical Specifications for Nuclear Power Plants, December, 1975.

6. 1. 5-3 Natf.onal Council on Radiation Protection and Heasurements, Natural Background Radiation in the United States, NCRP Report No. 45, Washington, D. C., 1975.

6.1.5-4 United Nations Scientific Committee on the Effects of Atomic Radiation. Ionizing Radiation: Levels and Effects, 1972.

Amendment No. 1

f SHNPP ER 6.2 OPERATIONAL MONITORING PROGRAM 6.2 ' NON-RADIOLOGICAL (BIOLOGICAL) MONITORING PROGRAM The preoperational non-radiological (biological) monitoring program required in the Revised Final Environmental Statement (Reference 6.2.1-1) will be conducted until one year after all units are in commercial operation. This monitoring program will span the period of both operation and construction phases"of the four units. Future monitoring programs beyond that described above will be governed by the NPDES permit and/or the Operating License requirements 6 ' ' RADIOLOGICAL MONITORING PROGRAM The operational radiological monitoring program will be a continuation of the preoperational radiological monitoring program described in Section 6.1.5. In general, it is anticipated that this program will continue for the operating life of the station. Modifications may be proposed at any time with appropriate justification.

6 2 ' METEOROLOGICAL MONITORING PROGRAM The operational meteorological monitoring program will be a continuation of the preoperational monitoring program described in Section 6.1.3. The only anticipated change will be the inclusion of the Radiological Monitoring System computer (RMS-21) which will interrogate the meteorological station on a regular interval for the purpose of displaying the collected data in the reactor control room for emergency response purposes. No meteorological parameters currently being monitored (as per Section 6.1.3) are expected to be discontinued; however, additional parameters may be monitored with appropriate justification.

6. 2-1

SHNPP ER 8.0 BENEFITS'ND COSTS 8.1 BENEFITS This section describes the social and economic benefits associated with the construction and operation of SHNPP. The social and economic effects of plant construction, as well as the relative benefits and costs of alternative sites and plants are discussed in detail in the SHNPP Construction Permit Environmental Report.

As defined in NRC Regulatory Guide 4.2, Revision 2, the primary benefits are those inherent in the value of the generated electricity delivered to customers. These benefits include the value of the average annual kilowatt-hours of electrical energy generated, the importance of providing an adequate reserve margin for the CP&L system, and an avoidance in the increase in the possibility of power shortages with associated social and economic effects. Secondary benefits of the operation of SHNPP will include tax revenues generated, increased employment opportunities, increased regional product, and increased knowledge as a result of environmental studies

8. 1. 1 PRQ1ARY BENEFITS Each SHNPP Unit has a net generating capacity of 900 megawatts. The expected average annual generation per unit is 5.52 billion kilowatt-hours of electrical energy. Table 8.1.1-1 shows the pro)ected proportional distribution of this energy by user class The need for the power to be generated by SHNPP has been discussed in detail in Chapter 1. Briefly summarized, thi,s power is needed to maintain the reliability of CP&L's system and to provide an adequate supply of electrical energy to meet the needs of its customers.

Without the addition of the SHNPP Units, the reliability of the VACAR Subregion would be impaired. Sporadic interruptions or shortages in the availability of electricity to customers could occur. The social and economic consequences of interruptions and shortages would be likely to include impairment of commercial and industrial operations. Social costs to the citizens in the region would result from the decrease in employment opportunities as a consequence of reduced industrial productivity and potential for future growth.

8.1 ' SECONDARY BENEFITS The construction of SHNPP will have a beneficial effect on the regional economy. In order to quantitatively assess the effect on the regional economy, income and employment multipliers can be used. The income multipliers are 1.5 for income and 0.7 for employment. The income multiplier is applied against 75 percent of the direct salaries assuming that 20 percent for taxes and 5 percent for personal savings is not available to the regional economy (Reference 8.1.2-1).

8.1-1

SHNPP ER 8.1.2.1 Direct and Induced Income and Em lo ent Effects Payroll and employment data derived from CP&L records show that approximately

$ 859 million (in 1984 dollars) will be expended by CP&L for construction worker's salaries. Applying the regional income multipliers and adjustments for taxes and savings, this expenditure by CP&L can be anticipated to induce additional expenditures of about $ 966 mQ.lion in the regional economy.

Carolina Power & Light Company also created approximately 3700 job opportunities for construction workers during the year of peak construction activity. Using the regional employment mul tiplier, this can be anticipated to stimulate approximately 2590 additional job opportunities in the regional economy during construction.

During the operation of SHNPP, CP&L expects to spend $ 20.4 million (1984 dollars) annually as payroll for the operations staff. Assuming an increase in salary costs of 8 percent per year, this payroll would accumulate to approximately $ 653 million (1984 dollars) over the estimated 32 year life of the plant. This accumulated payroll can be expected to induce additional expenditures of about $ 735 million (1984 dollars) in the regional economy. In addition, the operations staff employed by CP&L is expected to be approximately 900 employees for all four units, which using the regional multiplier, can be anticipated to stimulate approximately 630 additional job opportunities in the regional economy.

In addition to the direct operations and construction force payroll, the expenditures made by CP&L for the goods and services required for the construction, operation, and maintenance of SHNPP will stimulate an incremental increase in production in the area(s) where they are purchased.

8. 1. 2. 2 Taxes and Tax Effects Estimated ad valorem taxes to be paid to government agencies are as shown in Table 8.1.2-1. The estimated tax was computed based on the 1979 Capital Budget projection, the 1978 ratio of assessed value to undepreciated original cost, and the 1979 Make County tax rate of $ 0. 83 per $ 100 valuation. The State of North Carolina's ratio of assessed value to undepreciated original cost has varied historically from one to three percent per year. The County tax rate is dependent on many factors including County services and tax base, but should decrease as expenditures on the SHNPP units increase the taxable base.

8.1.2.3 Environmental Research and Enhancement Environmental monitoring programs have been conducted by CP&L since 1972 and have been used to identify and evaluate the consequences of site developnent on the SHNPP area flora and fauna. Studies have included baseline, preconstruction, and construction monitoring as required by the NRC (Section 2.2). Environmental monitoring programs will continue at least until year after the last of the SHNPP units begins commercial operation

'ne (Section 6.2).

8.1-2

SHNPP ER All environmental programs have been and will be conducted by qualified professional scientists. Reports resulting from the monitoring programs are periodically prepared by CP&L and, upon submittal to regulatory agencies, would become a matter of public record.

The land and reservoirs associated with the SHNPP will provide valuable habitat for many wildlife species. The land policy stated in Section 2.1.3 effectively will protect the flood control area around the reservoirs and approximately 4,000 acres of surface water fr'om private development. Much of this land and water will remain available as fish and wildlife habitat throughout the operational life of the SHNPP station. Carolina Power & Light Company will permit the appropriate state agencies to establish wildlife refuge areas and a wildlife management program to benefit the native wildlife.

Important game species including whitetail deer, wild turkey, mourning dove, bobwhite, cottontail, and gray squirrel will continue to inhabit the woodlands and abandoned fields surrounding the reservoirs and plant site. In satisfying the conditions of the Erosion and Sedimentation Control Plan (Section 4.5),

revegetation of the immediate plant site, dam banks, borrow areas, and road cuts and fills have enhanced the availability of food and cover to many wildlife species.

The SHNPP Main Reservoir is expected to provide waterfowl with approximately 4,000 acres of open water and many miles of shoreline. Puddle ducks and diving ducks are expected to utilize the shallow coves, open water, and shoreline for resting and feeding during winter months and during spring and fall migration. Several species of furbearing animals also will benefit from the miles of undeveloped shoreline habitat.

The developnent of a favorable sport fishery in the Main Reservoir is expected to result from the existing Whiteoak Creek and Buckhorn Creek populations with seeding from Cape Fear River makeup water. Operational monitoring programs (Section 6.2) will be conducted.

8.1.2.4 Enhancement of Recreational Values Prior to the construction of the SHNPP and associated Main Reservoir, the available public recreational opportunity in the Buckhorn Creek watershed was limited to a relatively insignificant level of small game hunting and stream fishing. With the development of the watershed for the SHNPP, the recreational use of the area will be significantly enhanced. The CP&L land policy stated in Section 2.1.3 will ensure a much greater and more varied recreational opportunity to a greater nunber of people.

8.1.2. 5 Enhancement of Esthetic Values Development of the SHNPP site has converted a typical Piedmont stream system and its surrounding terrestrial areas into a water supply reservoir. The aesthetic value of the site area was not unique to the region as evidenced by the fact that none of the streams in the Buckhorn Creek basin were candidates to the State's proposed natural and scenic river system. The Main Reservoir has an aesthetic appeal of its own and provides a recreational value which would not exist without the project. Because the SHNPP land policy 8.1-3

SHNPP ER (Section 2.1.3) prohibits private developnent of the shoreline of the reservoir, the natural aesthetic appeal will be preserved.

8. 1. 2. 6 Public Educational Facilities The Visitor's Center at the Energy and Environmental Center, located a short distance from SHNPP, will assist in educating the general population in the availability of energy and the technology associated with the generation of electricity from various energy sources. The Visitor's Center also provides the general public with general information specific to SHNPP.

U.l.?.7 Annual Savin s in Imported Crude Oil The average annual savings in consumption of imported crude oil through the production of electrical energy at SHNPP from nuclear fuel versus an oil burning plant is approximately 35.3 million barrels.

8.1-4

SHNPP ER TABLE 8.1.1-1 ESTIMATED BENEFITS OF SHNPP DIRECT BENEFITS Number of Units Expected Average Annual Generation Per Unit 5.52 x 109 Kw-Hr Capacity Per Unit 900,000 kw Proportional Distribution of Electrical Energy Per Unit Industrial 2 '9 x 109 Kw-Hr Residential 1.22 x 109 Kw-Hr Commercial 0.86 x 109 Kw-Hr Public Street and Highway Lighting 0.01 x 109 Kw-Hr Other Sales to Public Authority 0.13 x 109 Kw-Hr Sales for Resale 1.21 x 109 Kw-Hr

• Annual Revenues from Delivered Benefits Per Unit Industrial $ 93,632,000 Residential 80,154,000 Commercial 51,772,000 Public Street and Highway Lighting 1,002,000 Other Sales to Public Authority 6,032,000 Sales for Resale 47,795 000 Total $ 280,387,000 INDIRECT BENEFITS Taxes See Table 8. 1. 2-1

• Regional Product Construction Payroll $ 859 Million Operations Payroll $ 653 Million Employment at SHNPP Construction 3700 personnel at peak Operation 900 personnel

• 1984 Dollars 8.1-5

REFERENCES:

SECTION 8. 1 8.1.2-1 Personal Communication, Hr. J. V. Cartwright, U. S. Department of Commerce, Bureau of Economic Analysis, Regional Economic Analysis Division, Washington D.C. January, 1980.

SHNPP ER 8.2 Cost 8.2. 1 Internal Cost The 1984 present worth cost of land and generating facilities for the SHNPP is currently estimated to be $ 3.321 billion, a breakdown of which is shown on Table 8.2.1-1 ~ The comparable cost of incremental transmission facilities is estimated to be about $ 70 million for switchyard facilities and $ 14 million for associated lines. Thus, the total estimated 1984 present worth capital investment is about $ 3.405 billion.

Capital cost estimates are based on a recent North Carolina law allowing inclusion by a utility in its retail rate base of expenditures incurred after July 1979 for construction work in progress (CWIP). The net effect of this provision is a reduction in the accrued allowance for funds used during construction (AFC) because AFC accrual is discontinued on CWIP included in the rate base. The cost estimates provided above have been adjusted to include the effect of this legislation.

Fuel costs over the life of the project are estimated to be $ 3.967 billion; other operating and maintenance costs, $ 1.360 billion (both in 1984 dollars).

Decommissioning costs are discussed in Section 5.8.

Levelized revenue requirements are shown in Table 8.2.1-2. Each Unit has a depreciable lifetime of 25 years. Since the first Unit starts commercial operation in 1984 and the last in 1991, the project lifetime is 32 years. All levelized revenue requirements are computed over this period.

8.2.1-l

SHNPP ER TABLE 8.2.1-1 (continued)

Cost Information for SHNPP Indirect Costs Unit 1 Unit 2 Unit 3 Unit 4

a. Construction 59>692 14$ 333 14,154 14,587 facility equipment and services

b. Engineering and 214, 395 74,479 72,696 60,734 Construction Management services

c. Other Costs 94, 288 60$ 576 50,099 59,475

d. Interest during 347,279 164, 949 118,506 140 $ 559 construction (8 8%/year)

Escalation incl. above incl. above incl. above incl. above Escalation during Construction 8 8%/year Total Cost 1$ 435$ 523 634,502 589,724 660,847 Total Station Cost, (~ Star t o f Commercial Operation Note: The total nominal dollars expended as of the in-service date were pres'ent worthed to 1984.

8. 2. 1-3

SHNPP ER TABLE 8.2.1-2 Estimated Costs of Electrical Energy Generation Fixed Charges2 Mills/Killowatthour1 Return on Investment (Cost of Money) 12. 8 Depreciation 7.8 Income Taxes 7.8 Property Insurance & Tax, A&G 4.5 Subtotal 32. 9 Fuel Cycle Costs3 Uranium/Conversion/Enrichment 10. 9 Fabrication 1.5 Spent Fuel Storage/Disposal 1.2 Carrying Charges 3.9 Sub to tal 17. 5 Operation & Maintenance Costs4 Fixed Component 6.8 Variable Component 0.9 Subtotal 7.7 Nuclear Liability Insurance Levelized 1984-2015; Escalation varies, approximately 9%

Using 70 percent capacity factor Using 10, 930 Btu/Kwh Escalation at 10 percent 8.2.1-4

SHNPP ER 8.2.2 EXTERNAL COSTS Beyond the primary internal costs of the SHNPP and'ts operation, there is a potential for many external economic and social" costs. The Following discussion of external'osts of. the SHNPP is subdivided into temporary costs and long-term costs. As much as possible, the probable niimber and location oF any population group affected, the estimated economic and social impact, and special measures taken to alleviate the impact are described for. each cos,'t:.

8.2.2.1 Temporary External, Costs

• Possible temporary external costs include: shortages of housing; inflationary rentals and prices; congestion of local streets and highways; noise and.*

temporary esthetic disturbances;" overloading of. 'water supply and sewage treatment facilities; crowding of local schools, hospitals, or other p'ublic;

~

facilities; overtaxing of community services;.and the disruption of people' lives'r the local community, caused by acquisition of land for the site.

a) . Shortages of Housing Because limited construction work was begun in 1974, and full scale construction was not begun until 1978, there was 'a period of. four Eull years of advanced notification of plant construction to the local'area. This notification lead time coupled with the dispersion of construction worker,.~ ,,

residences over a nearly 100 mile r'adius.accounted for the minimal housing, impact on the local. area. As of March, 1979, records indicate that 31 percent of the force live within 25 miles .of the project, 55 percent live within 50 miles, 77 percent live 'within 75 miles and 83 percent live within 100 miles. The remaining 17 percent of the work force live more .than 100 miles from the project site. Given the large number of *mobile home parks, apartment. complexes, duplexes and single Family housing units wwithin a "

100 mile radius of. the project site, the net efEect of the project work .force on local 'housing was not signiEicant.

b) InElationary Rentals and Prices K

The advance notice of the construction of the SHNPP and the dispersion of the work force minimized the potential of inflated r'enta'ls and prices. Inflated costs probably, were no greater in the SHNPP area than elsewhere in the greater Raleigh area.

c) Congestion of Local Streets and'ighways L

The only major highway in the vicinity of the site is H.S. I'. This highway, which passes approximately 7,000 ft. northwest of the SHNPP, ha'd a daily

vehicle use of approximately 3,000 prior to construction. Although'ehicular traffic increased due to construction activity, the highway itself was essentially unaffected by the site development. The only exception was t:,he installation oE logger culverts and building'he 'embankment for future 'I 8.2.2-l Amendment No. 1

SHNPP ER third and fourth lanes where the highway crosses tl>e upper fingers of tlie-,

Auxiliary Reservoir 'inor traffic delays resu1ted during installation of these culverts and embankments.

State'nroad I127, which was n paved road near the northeast'end of t <e reservoir, was partlaiiy r< located an<I" raised to cross one h'r<ll of the Plain Reservoir. Service was maintained during the relocation. Approximately 16 miles of unpaved State roads located in Wake and Chatham counties were abandone<l by the North Carolina State Department of Transportation. 'ihose which served as construction roads were closed when they were no longer needed Since these dirt roads only served the few families who were relocated from the site, their closing represented insignificant impact on the surrounding community. 's roads were closed; they were plowed and planted in pine se<.dlings. No private property. owners were denied access to their property by the closing of roads.

'd) Noise and Temporary Esthetic Disturbances The construction activities created some noise, but. because of the remote

-location of the site and'sparse population," the, impact on human environment was minimal. Since the nearest, resident to, the center line of the four reactors is 1.5 mil~s, normal construction noise was not audibl'e.. Occasional '

blasting could be heard by some area residents. The greatest noise 1'<npact on residents in the area was from construction trucks. Otlier construction equipment at tlute-'site was provided with'tandard mufflers to reduce noise from operation.

Smoke from burning debris during the site and reservoir, clearing produced n temporary esthetic disturbance to nearby residents. The only open 'inor burning .permitted by Stat<'<<gulation was for land clearing. Appr<>xisnately 5,800.acres were cleared'nd vegetation piled and burned.:Merchantable timber and pulpwood left by the original land owners was harvested by CP&l 's clearing contractor prior to machine clearing to eliminate its waste and to reduce the-volume to be burned.

Dust created by construction activities was another temporary esthetic disturbance in the immediate vicinity of the plant. Only several local residences along unpaved access roads to .the site were temporarily affected by this problem. Dust caused by the movement of construction vehicles was controlled, by periodically spraying unpaved areas with water obtained from runoff basins, excavation dewatering discharge, and washdown,wa. tewater. The

~

, frequencies of spraying and the quantity of water sprayed were determined by visual inspections and existing weather conditions. I."qu'l.pment which emits large quantities of du'st such as the concrete batch plant cement storage silos, were equipped with filter bag systems as required by applicable air .

quality permits.

Temporary visual disturbances caused by construction of 'the SIENPP are restricted to the project site and will be alleviated after coristruction Ls completed by landscape restoration. As construction activities are 'completed, facilities such as temporary parking lots, roads, and the land occupied by shops, offices, and the concrete batch plant, which were not incorpor'ated into the finished'"plant, are being relandscaped to conform to the. surroundings.

8.2'.2-2

SHNPP ER Building material used during the construction of the power block and related facilities, together with permanent plant equipment, required enclosed storage and a large open storage area. Upon completion of construction these areas will be cleaned up and relandscaped to conform to the surroundings. Cleanup and restoration of areas affected by construction activities are conducted as outlined in Soil Erosion and Sedimentation Control Plans approved by the North Carolina Department of Natural Resources and Community Development. The disturbed areas are being graded to the natural contour of the land or as shown on construction drawings. The entire area to be seeded is being cultivated to a depth of two to four inches parallel to the line of embanhnent or ditches to minimize erosion. Fertilizer is applied prior to preparation of the seedbed at rates and types recommended by the seeding specification.

Grass seed is distributed uniformly over moistened seedbeds and rolled or hydroseeded. Areas not showing sufficient growth to prevent erosion are be1ng reseeded. Additional inspections, reseeding, and fertilizing are being performed until good growth is attained. P1ne seedlings are planted in abandoned roads, fields, and other cleared areas not necessary for construction support.

e) Overloading of Mater Supply and Sewage Treatment Facilities Mater supply and sewage treatment facilities were provided at the SHNPP site.

Therefore, there were no effects on public systems. The advance notice of the construction of the SHNPP and the dispersed locations of the work force residences prevented the overloading of any nearby municipal water supply or sewage treatment facilities.

f) Crowding of Local Schools, Hospitals, or Other Public Facilities The availability of public education facilities for fam1lies of construction workers did not pose a problem because of the project's long lead time notification to public education planners. Also, the dispersion of construction worker residences over a 100 mile plus radius reduced the effect on any one local area school system. In addition to elementary and high school facilities, there were numerous technical schools, community colleges, and four-yea'r colleges within the area where construction work force members resided.

A fire protection system is established on site w1th a fire brigade designated on each shift. When necessary, volunteer fire departments from Apex, Holly Springs, and Fuquay-Varina are available to augment site resources. Adequate police protection is provided in the local area by the Wake County Sheriff's Department and the North Carolina Highway Patrol. On-site security 1s provided by contractual arrangement.

A medical facility is operated, on site to serve construction workers. This facility examines workers who become ill or are involved in accidents on the site. Individuals are treated and, if necessary, referred to community medical facilities in Apex or Raleigh. North Carolina Memorial Hospital in Chapel Hill is the primary medical facility for the SHNPP during operation.

8.2.2-3

SHNPP ER g) Disruption of People' Lives or Local Communities The disruption of people's lives or local communities caused by acquisition of Land for the site was minimized by the location of the plant in a rural environment, Population was concentrated in a relatively few dispersed areas nnd large concentration of industrial activity did not exist. About 25 families were relocated as a result of the SHNPP construction.

8.2.2.2 Lon -Term External Costs Possible long-terra external costs include impairment of recreational values, deterioration of esthetic and scenic values; restrictions on access to areas of scenic, historic, or cultural interest; degradation of areas having historic, cultural, natural, or archaeological, value; removal of land from present or contemplated alternative uses; creation of locally adverse meteorological conditions; creation of noise, reduction of regional px'oducts, Lost income from recreation or tourism; lost income of commercia1 fishermen; decrease in real estate values; and increased costs to local governments.

a) impairment of Recreational Values Although there was an altex'ation and/or loss of wildlife habitats and "some direct and indirect loss of flora and fauna associated with the constxuction of the SHNPP, these were considex'ed relatively small commitments of wildlife resources when compared to the availability of like or similax habitats and wildlife throughout the region.

Although some previous small game hunting and stream fishing was precluded, the overall recreational usage of the project area for boating, fishing, hunting, and other outdoor activities is much greater than prior to construction of the SHNPP. The Hain Reservoir and adjacent lands will provide a significant recreational resoux'ce available for public use, CP&L's land and reservoir use policy is presented in Section 2.1.3.

b) Deterioration of Esthetic and Scenic Values Because the site was not previously considered aesthetically unique (Section 2.6) the Hain Reservoir coupled with its accessiblity to the public for recreational use has enhanced the aesthetic value of the area. However, the SHNPP has some visual Snpact on the area. One major negative visual impact results from the presence of the S20 ft. natural draft cooling towers which are visible over long distances.

c) Restriction of Access and Degradation to Areas of Scenic, Historic or Cultural Interest The regional histoxic, arclmeological, architectural, scenic, cultural, and natural features are discussed in Section 2. 6. Recognized and maintained areas of scenic, historic, or cultural significance are not located in or near the project area. Therefore, operation of the plant will not restxict access or degrade any such area.

8.2. 2-4

SHNPP- ER- =

d) '

Removal of Land fr'om'resent or Contemplated Alternative Ilses The sl.te related removal of land'rom its preconstruction uses is <llscussed in Section 4.5.1.4 of this report and Section 5.1.-1 of the Revised. Final-Environmental, Statement. About two percent. of the approximately 10,800 acres of, land i.nclude<lin t;he plant st t<, wer< devote<l to crop. produ<'t;ion. Most; of.

the fie1ds in the pro)ecL werc nbah<lonc<l or,'outly1np I',rom smal.l '<Iairy operations. Any loss in regional farm production was not considered significant. T1mber and paper companies owned the ma]ority of the land which was in pine tree production, mostly on formerly cropped and abandoned fields.

IIecause of extensive .wooded areas nearby, the removal of land from timber

'producti'on at the SHNPP d1d not cause an important impact on the local forest industry. No 'contemplated alternative uses of the SHNPP site were known.

e) Creation of Locally Adverse Meteorological Conditions The possibility of the creation of adverse meteorolop1cal conditibns due to plant operation is outlined in Sections 5.1.2.1, 5.1.2.2 and 5.1.2.3 of the Revised Final Fnvi,ronmental Statement. Discussions oF. pJume, fopginp, icing,.

and drift are included. None of these factors are expect.ed to have a significant impact on the l'ocal meteorological conditions.

f) Creation of Noise The SHNPP produces noise <lurinp normal operation. However, the plant's predi'cted ehvironmental noise emission will have little impact on the residents living at or near the plant boundary. (Section 5.6) g) Reduction of Regional Products I

There was no significant reduction of repional products due to displacement oE persons from the land, developed Eor the SHNPP site.

t h) Lost Income from Recreation or 'Tourism There are no nearby recreational or tourist sites or facilities that are expected to be impaired by environmental disturbances caused by the SHNPP.

Therefore,'no loss of. income to such devel'opments is antic1pated ~

Lost Income pf Commercial, Fishermen As discussed in Section 2.1.3, commercial fish an<1 shellfish 'catch 'is negl1gible within 50 miles of the -SHNPP and was non-existent at the site.

ThereEore, no "loss of income to commercial Eishermen results from the SHNPP.

g) Decrease in Real Es.tate Values

'ecreases of real estate values in areas ad)acent to the facility are,not

,expected to occur. Present trends 1n real estate indicate an appreciation in ~

property values in areas near the plant site. If present trends continue, the establishment of the plant site will not adversely affect local real estate values.'..2.2-5 Amendment No. l

k) Increased Cost to Local Governments Increased costs to local governments for service required by the permanently employed workers and, their families are expected to be minimal. A stable work force o1.'bout 900 1s expected during operation of the SllHPP. This force wilL reside in various nearby communities and will exert no adverse impacts on pu611c facilities.

8. 2. 2-6

SHNPP ER 9 ' ALTERNATIVE ENERGY SOURCES AND SITES This section is written in accordance with the discussion in the Introduction (Part 6.b) to 'the Nuclear Regulatory Commission, Regulatory Guide 4.2, pertaining to the "Applicants Environmental Report - Operating License Stage."

This report is an updating of the previously completed "Applicants Environmental Report, Construction Permit Stage for Shearon Harris Nuclear Power Plant Unit Nos. 1, 2, 3, and 4" submitted by Carolina Power 6 Light Company on June 8, 1971. The Construction Permit Stage Fnvironmental Report and the "Revised Final Environmental Statement Related to the Construction of Shearon Harris Nuclear Power Plant Units 1, 2, 3, and 4" issued by the United States Atomic Energy Commission, Directorate of Licensing, in March 1974, as supplemented contain a complete description of the process utilized to select the energy source and site now represented by the Shearon Harris Nuclear Power Plant.

9. 0-1

SHNPP ER 11 '

SUMMARY

COST BENEFIT ANALYSIS BENEFITS The principal benefit of SHNPP is the distributed generation of approximately 22.08 billion Kwh of electrical energy annually. The SHNPP capacity will contribute to meeting the anticipated demand within the CP&L service area and ensure that there is sufficient reserve capacity to allow necessary maintenance to be performed on other generating units.

As described in Section 8.1.2.1, the payroll expended during the construction of SHNPP is anticipated to induce estimated expenditures of approximately

$ 966 million (in 1984 dollars) in the regional economy. The employment opportunities provided during peak construction are anticipated to stimulate the creation of approximately 2590 opportunities in the regional economy in addition to the direct peak construction force employment level of 3700 personnel. The expenditures by CP&L for payroll during the operation of SHNPP, accumulated over the 32-year life of the plant, will induce a total of approximately $ 735 million (discounted to 1984) in the regional economy. The jobs provided by CP&L's operations staff can also be expected to induce creation of about 630 employment opportunities in the regional economy in addition to the direct operational staff of approximately 900 personnel.

Therefore, the total combined construction and operations payroll and employment opportunities provided by CP&L are expected to stimulate both the creation of about 3220 job opportunities (in addition to the direct construction and operating staff) and the expenditure of approximately $ 1.7 billion in the regional economy over the life of the plant.

As explained by Table 8.1.2-1, local governments and citizens will receive an estimated $ 97.5 million in tax benefits from the construction of SHNPP during the period 1980 through 1990. Plant operation is anticipated to generate about $ 31 million in taxes annually when all four units are operational.

These taxes will be used to finance a variety of programs providing services to the community.

Carolina Power & Light Company will conduct an environmental program monitoring meteorological conditions, water quality, and aquatic and terrestrial biology. These programs will increase the knowledge and understanding of nuclear generating stations and their effects on the environment by providing information from which future advances in design and technology can evolve.

11.2 COST In accordance with Regulatory Guide 4.2, CP&L has calculated a 1984 (date of commercial operation of Unit 1) present worth cost of the four SHNPP units and the associated transmission and switchyard facilities of $ 3.405 billion. The cost for fuel, operations, and maintenance of SHNPP over the life of the project is expected to be approximately $ 5.327 billion (in 1984 dollars). In addition, there are other external costs (Section 8.2.2) due to the environmental impacts discussed in Chapters 4 and 5. These costs,'hile difficult to quantify, have been investigated, and are believed not to be significant when compared to the benefits derived from the project.

11.0-1

SHNPP ER Decommissioning costs for each unit in 1978 dollars will probably fall within the range of $ 42.1 million for immediate dismantlement to $ 51.8 million for safe storage with deferred dismantlement, depending on the method selected.

See Section 5.8 for further details.

11.3 CONCLUSION

S It is the judgment of CP&L that, giving due consideration to the anticipated demand for electricity within the CPBL service area, as well as the likely resultant environmental effects, SHNPP represents the optimum economic 'and environmental alternative available for producing the needed electricity.

11.0-.2

SHNPP ER le Environmental Management technical duties for the (DEM) was EMC-created to perform administrative and The construction of a well requires a permit from DEM as outlined in Title 15, Subchapter 2C of the North Carolina Administrative Code (NCAC). In a well construction permit application, DEM considers public health and possible groundwater contamination, impact to groundwater use, proximity to other wells, well yield, and impact to existing groundwater table.

The construction and operation of a wastewater treatment facility which does not discharge to the waters of the State require permits from DEM (see 15NCAC 2H .0200). In issuing these permits, DEM is responsible for determining the ability of the treatment system to prevent discharges to surface waters and adverse impact to groundwater resources-Permits are also required from DEM for emission of pollutants to the atmosphere as outlined in 15 NCAC 2H .0600. Factors considered in this regulatory review include public health, plant and animal life, impact to ambient air quality, available technology, and cost of proposed pro)ect.

As outlined in Section 401 of the Clean Water Act, any applicant for a federal license or permit to conduct any activity which may result in any discharge to navigable waters shall be required to obtain State certification that such discharge, would comply with the water quality standards as provided in Sections 301, 302, 303, 306, and 307 of the Act. DEM is responsible for this certif ication in North Carolina-A National Pollutant Discharge Elimination System (NPDES) permit is required for the discharge of pollutants into navigable waters as outlined in Section 402 of the Clean Water Act. This permitting authority has been delegated by EPA to DEM.

DEM has the authority to control the consumptive use of water in the State by the use of Special Orders and will do so when they deem it appropriate for the wise and fair use of the water resource.

12.2.2.3 North Carolina Division of Health Services The Division of Health Services requires a permit be obtained before constructing an impoundment (see 10 NCAC 10C 0400) so that the Division may ensure protection of public health and prevention of insect-borne diseases.

Particular attention is given to reservoir clearing specifications and mosquito control measures.

12.2.2.4 North Carolina Division of Earth Resources The N. C. Division of Earth Resources requires significant earth disturbing activities have approved erosion control plans pursuant to the Sedimentation Pollution Control Act of 1973. The Division conducts periodic inspections to determine the adequacy of installed control measures and the need for additional ones.

12.0-3

SHNPP ER

12. 2. 2. 5 North Carolina De artment of Trans ortation Permission to relocate or close existing bridges and roads to construct electric generating plants and supporting facilities must be obtained from the North Carolina Department of Transportation (DOT). The Department of Transportation as the regulatory agency considers factors such as current standards on road construction, volume and type of road use involved, public inconvenience created by the proposed relocation and public benefits of the proposed relocation outlined in the applicant's plans

12. 2. 3 COUNTY AGENCIES The following county agencies require issuance of permits and/or approvals.

12.2.3 1, Wake and Chatham Count Commissioners County Commissioners must approve the abandonment of roads in their respective counties. Once the Commissioners approve, they must petition the North Carolina Board of Transportation for State approval.

12. 2. 3. 2 Wake Count Plannin Board Through County zoning regulations, the Wake County Planning Board regulates the size of buildings and other structures, percentage of a lot that may be occupied, the size of open spaces and yards, density of population, and the location and use of buildings and land. Compliance with these regulations requires a Land Use Permit.

12. 0-4 ~

ENVIRONMENTAL REPORT - OPERATING LICENSE STAGE APPENDIX A LIST OF TABLES (Cont'd)

TABLE TITLE PAGE A. 6. 1-5 DESIGN DATA FOR TURBINE BUILDING CONDENSATE POLISHING DEMINERALIZER AREA VENTILATION SYSTEM A. 6-21 A. 6. 1-6 DESIGN DATA FOR TURBINE BUILDING CONDENSATE VACUUM PUMP EFFLUENT TREATMENT SYSTEM A. 6-25 A.6. 1-7 DESIGN DATA FOR REACTOR AUXILIARY BUILDING HVAC SYSTEM COMPONENTS A. 6<<27 A>> 6>> 1-8 DESIGN DATA FOR WASTE PROCESSING AREAS VENTILATION SYSTEM A>> 6-38 A.6.1-9 DESIGN DATA FOR WPB LABORATORY AREAS HVAC SYSTEM A. 6%3 A>> 6>> 1-10 DESIGN DATA FOR FUEL HANDLING BUILDING HEATING VENTILATING AND AIR CONDITIONING SYSTEM A. 6%8 A>> 6.3-1 GASEOUS RADIOACTIVE RELEASES ONE UNIT-NORMAL OPERATION (Curies/year) A. 6-55 A.6. 3-2 ASSUMPTIONS USED TO CALCULATE GASEOUS RADIOACTIVE RELEASES A. 6-57 A. 6. 4-1 ~

PLANT AIRBORNE EFFLUENT RELEASE POINTS A.6-58 A. 7. 1-1 SOLID PROCESSING SYSTEM INPUTS (FOUR UNITS) A>> 7-2 A. 7>> 1-2 NUCLIDE ACTIVITY INPUTS TO THE SOLID RADWASTE SYSTEM, EVAPORATOR CONCENTRATES (pCi/g), NORMAL OPERATIONS A>> 7-3 A. 7. 1-3 NUCLIDE ACTIVITY INPUTS TO THE SOLID RADWASTE SYSTEM, SPENT RESINS (pCi/Batch), N0191AL OPERATION A. 7-5 A. 7.1% NUCLIDE ACTIVITY INPUTS TO THE SOLID RADWASTE SYSTEM, FILTER SLUDGE (pCi/Batch), NORliAL OPERATION A. 7-7 A. 7. 2-1 OUTPUT FROM SOLID WASTE PROCESSING SYSTEM (FOUR UNITS) A. 7-9

I f

I

SHNPP ER The RAB Normal Exhaust System serves as containment pre-entry purge and normal containment purge during normal plant operation. Also, the Pre-Entry Purge System serves as a standby unit for the RAB Normal Exhaust System for both Units 1 and 2.

A similar arrangement exists for Units 3 and 4.

In the event of an accident or loss of offsite power, the RABNVS will shutdown. Air will be exhausted by an independent Emergency Exhaust System.

Air sampling systems in the normal exhaust ducts will detect the radioactivity level as described in FSAR Sections 11.5 and

12. 3.4.

RAB NNS Ventilation System Design data for principal system components are presented in Table A.6.1-7. The RAB NNS Ventilation System consists of an outside air intake plenum, medium efficiency filter, electric heating, coil, chilled water cooling coil and centrifugal supply and return fans. The system is capable of functioning as a once through or as a mixed (recirculation with makeup) system. The conditioned air is supplied to the H&V equipment rooms through a sheet metal ductwork distribution system.

RAB Emergency Exhaust System The RAB Emergency Exhaust System consists of redundant 100 percent capacity fan and filter subsystems. Design data for principal system components are presented in Table A.6.1-7.

Each of the two subsystem filter trains includes a motor operated butterfly valve, decay heat cooling air connection, demister, electric heating coil, medium efficiency filter, HEPA pre-filter, charcoal adsorber and HEPA after-filter. Connected to each filter train outlet is a centrifugal fan with a motor operated-butterfly valve on its inlet and a backdraft damper on its outlet to prevent reverse airflow through the inactive fan.

Upon receipt of a SIAS, air operated valves on the normal ventilation penetrations into the areas containing equipment essential for safe shutdown close and both RAB Emergency Exhaust Systems are automatically ener'gized. Either unit may then be manually deenergized from the Control Room, and placed on standby.

Access into the areas exhausted by the RAB Emergency Exhaust System from other parts of the RAB is through leaktight doors under administrative controls.

All penetrations into the enclosed area are provided with proper seals which limit the amount of inleakage. The seals permit differential movement between the penetration and the wall due to thermally or seismically induced motion.

A.6-5

SHNPP ER Negative pressure is established at 1/S.in. wg. by continuously exhausting air. Pressure is then controlled by the Airflow Control System which adjusts the variable inlet vane of the exhaust system. Decay heat cooling air is provided by a duct connection admitting cool air into the idle unit through a check valve and a two position motorized butterfly valve in series.

These duct connections are located between each train's inlet valve and the demister section.

Interconnecting ducts between the two a1r cleaning units are provided to allow one air cleaning unit to draw a small quantity of air flow through the second inactive filtration train for decay heat cooling. A manual locked open butterfly valve is provided in this cross connection.

Cooling for all areas exhausted by RAB Emergency Exhaust System is provided by the RAB ESF Equipment Cooling System.

4) Control Room Emergency Filtration System The Control Room Emergency Filtration System consists of two 100 percent capacity filtration systems. Each filtration system contains in the direction of airflow, the following components:

a) Two motorized valves arranged in parallel b) Two centrifugal fans arranged in parallel c) Two motorized valves arranged in parallel d) Two flow elements arranged in parallel e) Interconnecting ducts between stand-by fans and other filtration trains f) A Demister g) Two electric heating co1ls arranged in series (one operat1ng and one stand-by) h) HEPA pre-filter bank i) Charcoal adsorber bank j) HEPA after-filter bank k) One motorized isolation valve l) Connecting duct with isolation valve to other unit d1scharge m) Two interconnecting ducts between unit discharge with isolation valves A.6-6

SHNPP ER TABLE Ao 6o 1-7 Bi EMERGENCY EXHAUST SYSTEM

1. Exhaust Fans Quantity, Per System 1, 100% each, centrifugal with variable inlet vanes, single width, single inlet, belt driven Capacity, Per Fan acfm 6800 Static Pressure, in. wg. 20 1/2 Code Air Moving and Conditioning Association (AMCA),

Anti-Friction Bearing Manufacturer Association (AFBMA) 2.

Motors'uantity, Per Fan Type 40 HP, 460 V, 60 Hz 3 phase, horizontal induction type Insulation Class B Powerhouse Enclosure and Ventilation Drip-proof Code NEMA Class B, IEEE Class lE

3. Electric Heatin Coils Quantity, Per'ystem Type Electric Capacity (kW) Per Coil 50 (Sufficiently sized to reduce the relative humidity of the inlet air from 100% to 70%)

Code Underwriter Laboratories (UL),

National Electrical Manufacturers Association (NEMA), National Electric Code (NEC) IEEE Class 1E Material Galvanized steel E

A. 6-30

SHNPP ER TABLE A.6.4-1 (Continued)

PLANT AIRBORNE EFFLUENT RELEASE POINTS(

DISTANCE CFM(2)

RELEASE RELEASE TO NEAREST TOTAL POINT POINT EL RESTRICTED CFM APPROX RELEASE ELEV. ABOVE AREA UNIT PER PER SIZE 6 SHAPE VELOCITY POINT NO, (FTo MSL) GRADE(3) (FT. ) BOUNDARY (FT ) BUILDING NOi SYSTEM SYSTEM POINT OF ORIFICE (FPM) 3A 296 36 435 Turbine Bldg. 1 Combined Effluent from Condensate Polishers Cubicles and Mech.

Vac. Pumps Effluent Dia. ~ 44 in.

Treat. Sys. 22$ 650 22,650 Circular 2145 3B Combined Effluent from Condensate Polishers Cubicles and Mech. Vac.

Pumps Effluent Dia. 44 in.

Treat. System 22,650 22,650 Circular 2145 4A 296 36 435 Turbine Bldg. 3 Combined Effluent from Condensate Polishers Cubicles Dia. ~ 44 in.

• and Mech. Vac Pumps 22,650 22,650 Circular 2145 4B Combined Effluent from Condensate Polishers Cubicles and Mech. Vac. Pumps Dia. ~ 44 in.

Effluent Treat Sys. 22$ 650 22,650 Circular 2145 321 61 335 Waste 1-4 Office Area Exhaustion 2,700 Processing Gen. Area Exh. Fan 5,500 Bldg. Filter Exh. System 130$ 800 Office Area Econo- 16,000 mizer Fan

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CAROLIiNA POMER 6, LIGHT COMPANY

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iUAL VOLUME 6 PART 7 PROCEDURE INSERVICE INSPECT N PROGRAM (ISI)

NUMBER: , ISI "201 PROCEDURE TITLE: ~

ASME RESERVICE INSPECTION PROGRAA'i PLAN (E. CE 7 REACTOR VESSEL)

REV ION O APPROVED:

Signature Date

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' joQp~gi ISI-201 Rev. 0 Page 1 oi 74

APR008 r~ ~ 4l Table of Contents

~Pa e 1.0 Introduction 2.0 Requirements for Preservice Inspection 5 3.0 Exemptions 6 4.0 Exceptions 7 5.0 Quality Assurance 7 6.0 Examination Procedures 7 7.0 Ultrasonic Testing 8 8.0 Evaluation Criteria 11 9.0 Records and Reports 11 10.0 Personnel Qualification ll 11.0 Pre-examination Requirements 12 12 0~ Program Plan Notes 12 Table 13 1

1'igure Appendix A 14 Appendix B 45 Appendix C 60 Appendix D 67 Appendix E 73 ISI-201 Rev. 0 Page 3 of 74

APR008

~~ ~> ~

1.0 INTRODUCTION

This Program Plan has been prepared to fulfill the remaining Preser-vice Inspection (PSI) requirements for Shearon Harris Nuclear Power Plant. The reactor pressure vessel preservice program plan was previously submitted on March 14, 1983. This Program Plan has been written to meet the requirements specified by the Code of Federal Regulations 10 CFR 50.55a. The Program Plan has been expanded to include augmented inservice inspection requirements which comply with the following:

A. U.S. Nuclear Regulatory Commission Standards Review Plan, Section 3.6.1 "Plant Design for Protection Against Postulated Piping Failures in Fluid Systems Outside Containment" (NUREG 75/087 Updated to NUREG-0800, 1981).

B. U.S. Nuclear Regulatory Commission Standard Review Plan, Section 6.6 "Inservice Inspection of Class 2 & 3 Components" (NUREG-0800, 1981).

C. U.S. Nuclear Regulatory Commission Regulatory Guide 1.14 "Reactor Coolant Pump Flywheel Integrity."

D. Request for additional information from NRC to CPEL by letter dated October 11, 1983.

In addition to the above, the Program Plan also incorporates the SHNPP FSAR commitments on Preservice/Inservice Inspection.

The scope of examinations, procedures and acceptance criteria meet the requirements outlined in Section XZ of the ASME Boiler and Pressure Vessel Code, "Rules for Inservice Inspection of Nuclear Power Plant Components," 1980 Edition, with addenda through Winter 1981. Accordingly, all class 1, 2, and 3 pressure retaining compo-nents and their supports as defined by 10 CFR 50 and NRC Regulatory Guide 1.26, will be examined to comply with ASME Code Section XI requirements to the extent practicable within the limitations of the component, or system portion, design and geometry.

All water, steam, air and other fluid systems within the scope of ASME Section XI are shown in SHNPP Procedure 1-ISI-200. All refer-ences in Appendices A-D to flow diagrams and proper Quality Group refer to procedure l-ISI-200.

Several piping systems will receive augmented inspections for protection against postulated piping failures as outlined in Section 3.6.1 and 6.6 of the Standard Review Plan. The extent, of examina-tions to those piping systems is defined by, Shearon Harris Nuclear Power'lant FSAR Section 6.6.8. Augmented examinations will also be performed on the flywheel of the Reactor Coolant pumps in accordance with Regulatory Guide 1.14. Augmented components and examinations are listed in Appendix D.

ISI-201 Rev. 0 Page 4 of 74

APR008 List of Effective Pa es

~Paoe Revision 1-74 0 IS1-2001 Rev. 0 Page 2 of .74

APRO08

~ Fy ~+ ~

2.0 REQUIRElKNT FOR PRESERVICE INSPECTION 2.1 NRC Regulations The Preservice Inspection requirements stipulated by 10 CFR 50.55a(g)(3) establish the applicable Edition of Section XI of the ASME Code for the components of a facility whose construction permit was issued after July 1, 1974.

The quality group classification system for radioactive, water/steam-containing components important to the safety of water-cooled nuclear power plants is established by NRC Regulatory Guide 1.26, in conjunction with Section 50.55a of 10 CFR 50. Regulatory Guide 1.26 defines the Quality Group Classification System consisting of four Quality Groups, A through D. The definition of Quality Group A is provided by 10 CFR 50.2(v) under "Reactor Coolant Pressure Boundary."

The definitions of Groups B, C and D are provided by Regulatory Guide 1.26.

2.2'efinition of Owner Intent In accordance with the requirements set forth by 10 CFR 50.55a, the Shearon Harris Plant must comply with the requirements of the 1974 Edition of Section XI, with addenda through Summer 1975 as modified by Appendix III of Vjnter 1975 Addenda. However, in order to comply with" a more recent code and addenda, Carolina Power &, Light has elected ta comply with the 1980 Edition of Section XI, with addenda through Minter 1981 and Code Case N-335.

The extent of examination selection of Class 1 and Class 2 piping has been determined by the requirements of the 1974 Edition of Section XI with Addenda through Summer 1975 as allowed by 10 CFR 50.55a (b)(2).

In addition, this Program Plan includes Augmented Inspections from NUREG 75/087, "Plant Design for Protection Against Postulated Piping Failures in Fluid Systems Outside Containment" and Regulatory Guide 1.14, "Reactor Coolant Pump Flywheel Integrity." Additional in-spections will be performed on certain systems required to satisfy NRC questions submitted during the FSAR review.

3.0 E'.KHPTIOiVS The following exemptions from examination requirements are applica-ble to Quality Group A, B, and C piping, components and their supports'.1 Quality Group A Components except piping will be- exempted in accordance with IWB-1220 (1980 Edition thru and including Minter 1981 Addenda) from'the volumetric and surface examination requirements of

.ISI-201 Rev. 0 Page 5 of 74

APR008 3.0 EXEHPTIONS 3.1 Quality Group A (cont.)

IWB-2500. Category B-J components will be exempted in accordance with IWB-1220 (1974 Edition thru and including Summer 1975 Addenda) from the volumetric and surface examination requirements of IWB-2500.

In Quality Group A Code Cate'gories B-L-2 and B-2-2 a VT-3 ex-amination is required. It is CP&L's position that this is an Inservice requirement and does not apply to Preservice.

Quality Group A nonexempt components and examination requirements are listed in Appendix A.

3 ' Quality Group B Components except piping will be exempted in accordance with IWC-1220 (1980 Edition thru and including Winter 1981 Addenda) from the volumetric and surface examination requirements of IWC-2500.

'ategory C-F components will be exempted in accordance with IWC-1220 (1974 Edition thru and including Summer 1975 Addenda) from the volumetric and surface examination requirements of IWC-2500.

Within the scope of the PSI Program Plan there are no Code Category C-D or C-G components sub]ect to inspection requirements of,Table IWC-2500-1.

Quality Group B nonexempt components and examination requiremen-s are listed in Appendix B.

3.3 Quality Group C Integral attachments of supports and restraints to components will be exempted in accordance with IWD"1220 (1980 Edition thru and including Winter 1981 Addenda) from the visual examination VT-3, except, that all Auxiliary Feedwater integral attachments on piping greater than 1" nominal pipe size will receive a VT-3 visual ex-amination.

Quality Group C nonexempt components and examination requirements are listed in Appendix C.

3.4 Component Supports Component supports .selected for examination will be the supports 'of those components greater than one inch in diameter that are required to be examined under IWB, IWC, and IWD.. In addition, the examin-ation requirements shall apply to the component support types identified in IWF-1210..

ISI-201 Rev. 0 Page 6 of 74

i APROOS 3.0 EXEMPTIONS 3.4 Component Supports (cont.)

Preservice inspection shall be performed by the required examina-tions listed in Table IWF-2500-1. All required VT-3 examinations will commence upon completion of Final System Turnover on a system as described in the Harris Plant Start-up Manual.

All snubbers will receive a preservice inspection and functional test prior to the commencement of hot functional testing of complet-ed systems. lianufacturers test data may be used to sat'sfy the Preservice testing requirements.

3.5 Exempt Components All Quality Group A, B and C components exempted from Preservice examination requirements will have undergone the system hydrostat'c test when the system has been completed as required by ASNE Section III. Preservice hydrostatic testing is not required by Section XI, IWA-5215.

4.0 EXCEPTIONS Exceptions to Code required examinations may be authorized by the regulatory authority, as allowed by 10 CFR 50.55 a(a)(2), provided that design fabrication, installation, testing and inspection performed in compliance with Codes and Section XI requirements would resu't in hardship without a compensating increa e in the level of quality and safety, or provided that the proposed alternative examination will provide an acceptable level of quality and safety.

Detailed descriptions and justifications for exceptions taken vill be submitted when needed by a Request for Relief.

5.0 QUALITY ASSURANCE The PSI Program Plan will be performed in accordance with the requirements of the CP&L Quality Assurance Hanual which is in compliance with Appendix B of 10 CFR 50.

6' EXAMINATION PROCEDURES, Subarticle IWA-1400 of Section.XI requires the development and preparation of written examination procedures necessary for the conduct of the nondestructive examinations associated, with PSI operations. The written procedures for the performance of visual, surface, and volumetric examinations', are.-provided by the .NDE Con-,

tractor and will be reviewed and approved by CP&L prior to use.

ISI-201 Rev. 0 Page 7 of 74

APR008 6.0 EXAMINATION PROCEDURES Methods, techniques, and procedures for the preservice inspections are titled visual, surface, and volumetric. Each term describes a general method permitting a select'on of different techniques and procedures restricted to that method to accommodate varying degrees of accessibility and radiation levels.

A visual examination is emp1.oyed to provide a report of the geneial condition of the part, component, or surface to be examined, includ-ing such conditions as scratches, wear, cracks, corrosion or erosion on the surfaces; misalignment or movement of the part of component; or evidence of leaking. Visual examinations are applicable to welds, support members, valves, pumps, fasteners, cladding, etc.

Visual examination procedure is based on the requirements of IWA-2210 of Section XI of the ASiK Code.

A liquid penetrant examination is specified as the surface examina>>

tion method to delineate or verify the presence of cracks or discon-tinuities open to the, examination surface. Liquid penetrant examina-tion procedure is in compliance with the requirements of Article 6 of Section V of the ASlK Code, as required by Section XI IWA-2222.

As a substitute to liquid penetrant, SEEPP can utilize a magnetic particle examination to satisfy surface examination requirements.

The ultrasonic pulse echo examination is selected as the volumetric examination method to indicate the presence of subsurface disconti-nuities by examining the entire volume of metal contained beneath the surface to be examined. Ultrasonic examination is incompliance with Appendix III of Section XI (or Articles 4 and 5 of Sectio.< V, as, applicable) of the AS'ode, as required by Section XI IWA-2232 and including Code Case N-335 as amended in Section 7.0. Radiography may be used as a substitute for ultrasonic examination when access to welds is restricted.

7.0 ULTRASONIC TESTING The calibration standard design drawing is part of the PSI Program Plan and shown in Figure 1. Table 1 lists all UT Calibration Standards required to perform the UT examinations. All calibration standards are retained on site.

The UT examination calibration standard design and material se-lection are in accordance with Subarticle III-3400 of Appendix III to Section XI 1980 Edition including Winter 81 addenda. In addition to the required notches, drilled holes have been installed as additional reflectors in accordance with the provisions of Article 5 of Section V of, the Code. These additional reflectors are allowed by Subarticle III-3400 of Appendix III of Section XI.

ISI-201 Rev. 0 Page 8 of 74

APR008 4~ ~

7.0 ULTRASONIC TESTING'.

In addition to this requirement it is CPEL's intent to perform ultrasonic examinations on austenitic stainless steel piping utilizing AS'.K Boiler and Pressure Vessel Code Case N-335 with the following input:

1. Personnel and procedures used to perform the examinations shall be qualified in accordance with a program described in Appendix E. The J. A. Jones EPRI NDE Center IGSCC Training/Qbalification Program may be used in lieu of or integral to this program.

2. Level I examiners will not be used to monitor the ultra-sonic instrument during examinations.

3. The typical calibration block design to be utilized is shown in Figure 1. CP&L reserves, the right to change segments of piping used deoendent upon pipe size, (e.g.,

small diameter piping 5 4 in may be 360 degree sections).

Calibration reflectors shall be installed as follows:

a. For calibration blocks with pipe wall nominal. thick-nesses of one (1) inch and greater Paragraph A.4 below applies.

b. For calibration blocks with pipe wall nominal thick>>

ness less than one (1) inch to and including 0.5 inch a single side drilled hole (SDH) will be installed at 1/2t. Notches will be staggered at the I.D. and O.D.

locations.

c. For calibration blocks with pipe wall nominal thick-ness less than 0.5 inch no SDH will be installed.

I.D. and O.D. notches will be staggered to prevent interference during calibration.

For angle beam calibration Subparagraph 3.2.2(d), of Code Case N-335 is revised to read as follows:

a. "Where the calibration is limited'o the half V path due to material attenuation or examination technique selection, side drilled holes shall be used to obtain the slope and shape of the-DAC curve. A minimum of .

two holes, each of the same diameter and located at 1/4t and 3/4t, shall be placed in the calibration block. The diameter of the holes shall be in accor-dance with Fig. T-546.1 of Article 5 of Section V-.

The holes shall be perpendicular to the-examination beam direction. The minimum hole length shall'be 1$ ,

inches. Calibration shall be accomplished by con-structing a DAC curve from the side drilled holes so that the maximum amplitude point is at 80 FSH. Once ISI-201 Rev. 0 Page 9 of 74

APR008

~ ~ 5 7.0 ULTRASONIC TESTING the shape and slope are determined and marked on the screen, the curve shall be extrapolated 1/4t to cover the full examination thickness. Next, establish the sensitivity from the inside diameter (I.D.) surface notches by setting the indication amplitude at the level of the DAC curve."

5. Recording requirements of Subparagraph 4.5.1, Code Case N-335 will be amended to read:

a. The following indications shall be recorded and investigated by a Level II or Level III examiner to the extent necessary to determine the shape, type, and location of the reflector.

1) An indication of a suspected flaw originating in the HAZ or adjacent base metal regardless of amplitude.-

2) Any indication 20~ of DAC or greater than those from geometric or metallurgical origin.

b. Indications 50~ of DAC or greater from geometric or metallurgical origin shall be recorded.

Criteria to record geometric and metallurg'cal ultrasonic indications is described as amended above. These indica-tions will not be zeported, they will be recorded for the record and for future'correlation to similar indications during Inservice Inspection. Ambiguous responses from geometry will be evaluated and characterized on a case basis using multiple ultrasonic techniques and correlation to radiographic results.

6. Since Supplement 7 of Code Case N-335 will be applied to SHNPP austenitic piping welds, concerns regarding Supple-ment 7 in Appendix III of Section XI do not apply. This position is taken as a result of the major improvements preferred in N-335.

B. The investigation, evaluation, or corrective measures taken as a result of indications recorded during piping ultrasonic examinations shall be based up A.S. above. It is CP&L's belief that in amending N-335, Paragraph 4.5.1 with more stringent requirement in A.5 above will ensure adequate evaluation and, if necessary, corrective action for disposition of any indi-cation investigated and found to be other than geometric or metallurgical in nature.

ISI-201 Rev. 0 Page 10 of 74

APRO08 7.0 ULTRASONIC TESTING Cast austenitic stainless steel fittings, nozzles, and other piping components will be ultrasonically examined using state-of-the-art techniques, eg. dual search units, etc.

Technique limitations due to material attenuation, noise, and access will be documented in the record. Capabilities to examine cast austenitic stainless steel ultrasonically is a function of the thickness involved. Cast main loop piping, cast-to-cast fitting welds or assemblies are recognized uninspectable. Thinner wall cast piping, fittings or assem-blies as in the pressurizer surge line are inspectable in most cases using conventional UT techniques. Cast'o wrought stainless steel welds will be examined from the wrought side, the cast side will be examined if it is determined that the results are meaningful. The examination record will reflect all scanning limitations.

8.0 'EVALUATION CRITERIA I

Evaluation of any indications detected during PSI shall be made in accordance with IWA-3000 of Section XI. Indications detected may be evaluated by other nondestructive methods, where practical, to assist in the determination of size, shape, location, and orien-tation before final disposition is made.

I 9.0 ',RECORDS AND REPORTS A system of records of the Preservice Inspection, plans, schedules, and calibration standards; the examination results. and reports, the corrective action required and taken, will be developed and main-tained at the site in accordance with IWA-6000 of Section XI,

10. 0 PERSONNEL QUALIFICATION Personnel performing nondestructive examination operations shall with procedures prepared in accordance with SNT-TC-1A, be'ualified 1980 Edition, for the applicable examination technique and methods as required by IWA-2300 of Section XI. All examinations shall be pezformed and the results evaluated by qualified nondestructive examination personnel.

For those nondestructive examination methods not covered by SNT-TC-1A documents, qualification will be based on the particular, method involved. Such qualification provides for uniform programs of training, evaluation, and certification of personnel. For personnel performing ultrasonic inspections the additional requirements of Section 7.0 will be zequired.

11.0 PRE-EXAMINATION REQUIRE"KNTS General provisions for accessibility have been defined by IWA-1500 of Section XI of the AS)K Code.

ISI"201 Rev. 0 Page 11 of 74

APR008

11. 0 PRE-EXA'fINATION REQUIREa'KNTS

l. All systems and components ~hat require inspection in accor-dance with the requirements of ASME Section Xl will be designed with adequate physical access to allow the required inspection.

2. It is intended that piping systems requiring ultrasonic in-spection will be designed so that all welds requiring in-spection are physically accessible for inspection with ultra-sonic equipment.

A. Access will be provided by leaving adequate space around pipes at these welds and by means of removable insulation and shielding as required.

B. Pipes welded to fittings will be designed to permit meaningful examination by avoidance of irregular surface geometries.

C. The surface of welds will be smoothed and contoured to permit effective use of ultrasonic transducers or surface examination indicators.

D. Piping systems requiring surface or visual examination will be designed to allow access and visibility adequate for'performance of such examination.

12.0 PROGRAM PLAN NOTES NOTE 1. Augmented Program FSAR Section 6.6.8.b NOTE 2. Augmented Program FSAR Section 6.6.8.c NOTE 3. Augmented Program FSAR Sect'on 6.6.8.d NOTE 4. Augmented Program FSAR Section 6.6.8.e NOTE 5. Augmented Program - Review of the FSAR and request for additional information regarding Preservice (PSI)/Inservice (ISI) Program Section 250.1 paragraph 2 NOTE 6. ISI Requirement Only (Not Required for PSI)

NOTE 7. No circumferential weld on this line.

ISI-201 Rev. 0 Page 12 of 74

APR008 TABLE 1 CALIBRATION BLOCKS Piping Calibration Piping Cal.

Blocks Material Block Number Svstems 24" sch 80 (XS) A106 GR.B UT-10 AF ll UT-11 3 sch 40S (STD) A312-304 RH II 3 sch 80 (XS) A106 GR.B UT-12 MS II 3 sch 160 A106 GR.B UT-13 FW II 3 sch 160 A376-304 UT-14 CS,SI 4tt sch 40 (STD) A106 GR.B UT-15 BD 4tt sch 80 (XS) A106 GR.B UT-16 AF 4tt sch 160 A376-304 UT-17 CS,RC,SI 6tt sch 80 (XS) A106 GR.B UT-18 AF IMS 6tt sch 120 A106 GR.B UT-19 FW It 6 sch 160 A376-304 UT-20 RC, SI II 8 sch 40S (STD) A312-304 UT-21 CT 8lt sch 80 (XS) A106 GR.B UT-22 MS 1PII sch 140 (XXS) A376-316 UT-23 SI 12ti sch 40S (STD) A312-304 UT-24 RH 12lt sch 60 A106 GR.B UT"25 MS 12" sch 140 A376-304 UT-26 CS,RC,RH,SI 14" sch 40 A358-304 UT"27 RH 14" sch 160 A376-316 UT-28 RC 16 I~

.668" MW A106 GR.B UT-29 FW ll 1.006" MW UT-30 16 A106 GR.B FW 32" 1.051" MW A106 GR.C. UT-31 MS 34lt 2.0" MW A106 GR.C. UT-32 MS 44tl 1.447" MW A106 GR.C. UT-33 MS

,5plt 3.279 MW A155 KC 70 UT-34 MS 9.22 6 1.5" MW A106 GR.C UT-35 MS Vessel Calibration Blocks Pressurizer Shell SA533 GRA, CL2 UT-50 S/G Channel Head (PRI) SA533 GRB, CL1 UT-51 S/G Secondary Shell SA533 GRA, CL2 UT-52 Regenerative HT EX SA351 - CF8 UT-53 RHR HT EX SA515 " 70 UT-54 BIT Shell SA351 CF8A UT-55 BIT Head SA240 Type 304 UT-56 ISI-201 Rev. 0 Page 13 of 74

CASE (continued) Figure '1 N-"'335 CASES OF ASME BOILER AND PRESSURE VESSEL CODE xE,Y AXIAL Hl3Lc P P XIAI NOTCH

3. Cl¹C VOL c

4 CIRC NLI TCH I

'I I I I I I I I I I I I I I I I I I I LONGITUDINAL I NOTCH I lQ Mill I TYP I

pter I 3

4T I

I CIRCUMFERENTIAL ,T NOTCH

~

~/ /

ftCI ttt 3430 3 AtcctOtNOKD nLItCS tea aaStC rtrt~C Cu.te~ttco ILOCX 4 O'ENGTH/ARC SHALL BE ADEQUATE TO PROVIDE REQUIRED ANGLE BEAM CALIBRATION FOR PIPE.

SCHEDULES LESS THAN ONE (1) INCH NOMINAL FIG 3.4.2-2 RECOMMENDED DES'IGN FO¹ WALL THICKNESSt 1 ~ STAGGER NOTCH ID/OD LOCATIONS BASIC CALIBRATION BLOCK 2. A 1/2t SIDE DRILLED HOLE MAY BE USED IN LIEU OF 1/4t AND 3/4t SOH.

SUPP. 11 NC XSI-201 Rev 0 Page 13A of 74

APR008 APPENDIX A QUALITY GROUP A INSPECTION PLAN

SUMMARY

ISI-201 Rev. 0 Page 14 of 74

APR008 SHEARON HARRIS UNIT iNO. 1

'RESERVICE INSPECTIOiV PROGRAM PLAN SUMERY ASME SECTION XI EDITION 80W81 CATEGORY: B"B, Pressure Retaining Welds in Vessels other than Reactor Vessels ITEM: . B2.11, Circumferential Welds FLOW PLOW SYSTEM/ DIAGRAM DIAG LINE EXAM RELIEF PROGRAM Comoonent ~(2166 "G COORD NUMBER RETEOD REIElZST Reeee PZR 801 J-6 Vol ISI-201 Rev. 0 Page 15 of 74

APR008 SHEARON HARRIS UNIT iNO. 1 PRESERVICE INSPECTION PROGRAM PLAN St".0/ARY ASME SECTION XI EDITION 80W81 CATEGORY: B"B, Pressure Retaining Welds in Vessels other than Reactor Vessels ITEM: B2 12, L'ongitudinal Welds

~

FLOW FLOW SYSTEM/ DIAGRAM DIAG LINE EXAM RELIEF PROGRAM C~om anenr. ~2166-G COORD NUMBER NETEOD REDDEST Nonce PZR 801 J-6 Vol ISI-201 Rev. 0 Page 16 of 74

APR008

~ e ~

SHEARON HARRIS UNIT NO. 1 PRESERVICE INSPECTION PROGRAM PLAN

SUMMARY

ASSME SECTION XI EDITION 80W81 CATEGORY: B"B, Pressure Retaining Welds in Vessels other than Reactor Vessel ITEM: B2.40, Tubesheet-to-Head Weld (Primary Side)

FLOW FLOW SYSTEM/ DIAGRAM DIAG EKE RELIEF PROGRA1'1 Comoonent ~2165-G COORD NUMBER HETEOD ~RE EST metes S/G 800 E-4 1A Vol S/G 800 H-4. 1B Vol S/G 800 Z-17 3.C Vol ISI-201 Rev. 0 Page 17 of 74

APR008 SHEARON HARRIS UNIT NO.'1 PRESERVICE INSPECTION PROGRAM'1 PLAN SUR6Li)ARY ASEEE SECTION XI EDITION 80V81 CATEGORY: B-D, Full Penetration Velds of Nozzles in Vessels - Inspection Program B ITE."1: B3.110, Nozzle to Vessel Velds FLOW FLOP SYSTEM/ DIAGRAN DIAG LINE EXQf RELIEF PROGRN Comoonent ~216S-G . COORO BRIBER RETEOO REQUEST Roses 801 J-6 Vol

~-201 Rev.' Page 18 of 74

APRO08 SHEARON HARRIS UNIT NO. 1 PRESERVICE IiVSPECTION PROGRrQf PLAiN SRf!fARY ASME SECTION XI EDITIOiN 80W81 CATEGORY: B-D, Full Penetration Welds of Nozzles in Vessels - Inspection Prog am B ITE.'f: B3.120, Nozzle Inside Radius Section FLOW FLOW SYSTEM/ DIAGRAM DIAG LINE EXQf RELIEF PROGRAi'f Comoonent ~2166-G COORD NUMBER EETEOD REQUEST Eeeee PZR 801 J-6 Vol ISI-201 Rev. 0 Page 19 of 74

APR008 SHEAROiN HARRIS UNIT NO. 1 PRESERVICE IeNSPECTION PROGRA' PLAN SU iiiARY ASME SECTION XI EDITION 80W81 CATEGORY: B-D, Full Penetration Welds of Nozzles in Vessels << inspection Program B ITEM: B3.130, Nozzle-to-Nozzle Welds FLOW FLOW SYSTEM/ DIAGRAM DIAG E~i RELIEF PROGRAi'i Comoonent ~(2165-G COORD NUMBER NETH OD ~EE GEST Notes S/G 800 E"4 1A Vol S/G 800 H-4 1B Vol S/G 800 E" 17 1C Vol ISI-201 Rev. 0 Page 20 of 74

APR008 SHEARON HARRIS UNIT iNO. 1 PRESERVICE INSPECTION PROGRAM PLAN SUiiMARY ASiiE SECTION XI EDITIOiN 80W81 CATEGORY: B-D, Full Penetration Welds of Nozzles in Vessels - Inspection Program B ITEM: B3.140, Nozzle Inside Radius Section FLOW FLOW RELIEF PROGRAM SYSTEM/

Comoonent DIAGRAM

~(2165 "G DIAG COORD NU".1EER EXAM NETHUD ~RE UEET 'otes S/G 800 E-4 1A Vol S/G 800 H-4 1B Vol S/G 800 E-17 1C Vol ISI-201 Rev. 0 Page 21 of 74

APR008 h

~~

SHEAROiN HARRIS UNIT NO. 1 PRESERVICE IiNSPECTION PROGRA'i PLAil SU.'i iARY ASME SECTION XI EDITION 80W81 CATEGORY: B-E, Pressure Retaining Partial Penetration Welds in Vessels ITEii: B4.20, Heater Penetration Welds FLOW FLOW SYSTEM/ DIAGRAM DIAG LINE EXAii RELIEF PROGRAM Comoonent ~(2166-G COORD NUMBER METHOD ~RE UEST Reeee PZR 801 J-6 VT-2 ISI-201 Rev. 0 Page 22 of 74

APR008 SHEARON HARRIS UeefIT iNO. 1 PRESERVICE lNSPECTION PROGRAM PLAI SU."fMARY ASifE SECTION XI EDITION 80W81 CATEGORY: B-F, Pressure Retaining Dissimilar Metal Welds ITEii: B5.40, Nozzle-to-Safe End Butt Welds, nps 2 4", Pressurizer FLOW FLOW SYSTEM/ DIAGRAM DIAG LlilE EDN RELIEF PROGRAM Comoonent ~(2162-G COORD NUBBER efETHOD ~RE UEST Noeee RC 801 L-6 RC14-35 Vol & Sur RC 801 I-6 RC6-124 Vol & Sur RC 801 I-6 RC6"126 Vol & Sur RC 801 I-6 RC6-128 Vol & Sur RC 801 I-6 RC6-135 Vol &, Sur RC 801 I-6 RC6-231 Vol & Sur t

ISI-201 Rev. 0 Page 23 of 74

APR008 SHEAROiV HARRIS PilIT NO. 1 PRESERVICE INSPECTION PROGRAN PLAN SUNiNARY ASNE SECTION XI EDITION 80'4'81 CATEGORY: B-F, Pressure Retaining Dissimilar Welds ITEN: B5.70, Nozzle-to-Safe End Butt Velds, nps > 4", Steam Generator FLOV FLOV SYSTEN/ DIAGRAN DIAG LINE EXAN RELIEF PROGRAN Comuonent ~(2165 -G COORD NURSER NETHOD REIEUEST Notes RC 800 F-3 RC31-2 Vol & Sur RC 800 I-3 RC31-5 Vol & Sur RC 800 F-17 RC31-8 Vol & Sur RC 800 F-4 RC29"1 Vol & Sur RC 800 I-4 RC29-4 Vol & Sur RC 800 F-17 RC29-7 Vol & Sur ISI-201 Rev. 0 Page 24 of 74

APRO08 SHEARON HARRIS UNIT NO. 1 PRESERVICE INiSPECTIOVi PROGRAH PLAal'UHHARY ASiHE SECTION ZI EDITIOiV 80W81 CATEGORY: B-G-l, Pressure Retaining Bolting, Greater than 2" in Diameter ITEiH: B6.180, Bolts and Studs FLOW FLOW SYSTEH/ DIAGRAH DIAG E!RH RELIEF PROGRAH Comaonent ~(2165-G COOPJ) NJHBER HETHOD R~E DEBT Heres RCP 800 C-3 1A Vol RCP 800 L-3 1B Vol RCP 800 C-17 1C Vol ISI-201 Rev. 0 Page 25 of 74

, APR008 SHEARON HARRIS UNIT NO. 1 PRESERVICE INSPECTION PROGRAM PLAN

SUMMARY

ASME SECTION XI EDITIOiN 80W81 CATEGORY: B-G-1, Pressure Retaining Bolting, Greater than 2" in Diameter ITEM: B6.190, Flange Surface FLOW FLOW SYSTEM/ DIAGRAM DIAG EQM RELIEF PROGRAM

~

Comoonent ~(2165-G COORD HUNGER HETHOD MIIUEET Notes RCP 800 C-3 1A VT-1 RCP 800 L-3 1B VT-1 RCP 800 C-17 1C VT-1 ISI'-201 Rev. 0 Page 26 of 74

APRO08 SHEARON HARRIS UNs'IT NO. 1 PRESERVICE INSPECTION PROGRAM PLAN

SUMMARY

ASME SECTION XI EDITION 80W81 CATEGORY: B-G-1, Pressure Retaining Bolting, Greater than 2" in Diameter" ITEM: B6.200, Nuts, Bushings and Washers FLOW FLOW SYSTEM/ DIAGRAM DIAG EXAM RELIEF PROGRAM Comoonent ~2165-G COORD NUMBER HETHOD &INQUEST Noses RCP 800 C-3 1A VT-1 RCP 800 L-3 1B VT-1 RCP 800 C-17 1C VT-1 ISI-201 Rev.. 0, Page 27 of. 74

APR008 SHEARON HARRIS UNIT NO. 1 PRESERVICE INSPECTION PROGRAM PLAN

SUMMARY

ASME SECTION XI EDITIOiN 80W81 CATEGORY: B-G-2, Pressure Retaining Bolting, 2" and less in Diameter ITEM: B7.20, Bolts, Studs and Nuts FLOW FLOW SYSTEM/ DIAGRAM DIAG EXAM RELIEF PROGRAM Comoonent ~(2165-G COORD EEMBER EETEOD ~RE EEET Recce PZR 801 J-6 VT-1 ISI-201 Rev. 0 ,Page 28 of 74

APR008 SHEARON HARRIS UNIT NO. 1 PRESERVICE INSPECTION PROGRAi'i PLAiN

SUMMARY

ASiME SECTIOiN XI EDITION 80W81 CATEGORY: B-G-2, Pressure Retaining Bolting, 2" and less in Diameter ITEM: B7.30, Bolts, Studs and Nuts (Vessels)

FLOW FLOW SYSTEM/ DIAGRAM DIAG ERR RELIEF PROGRAii Component ~2266-G COORD NUMBER METEQD WIIUEST Notes Stm Gen 800 C-3 lA VT-1 Stm Gen 800 L-3 1B VT-1 Stm Gen 800 C-17 lc VT-1 ISI-201 Rev.' Page 29 of 74

APR008 SHEARON HARRIS UNIT NO. 1 PRESERVICE INSPECTIOiN PROGRAH PLAN SUHHARY ASHE SECTIOiN XI EDITION 80W81 CATEGORY: B-G-2, Pressure Retaining Bolting, 2" and less in Diameter ITEH: B7.50, Bolts, Studs and Nuts (Piping)

FLOW FLOW SYSTEH/ DIAGRAH DIAG LINE EX821 RELIEF PROGRAH Comuonent ~2165-G COORD NUHBER NETEOD REQUEST Notes CS 803 I"6 CS14-16 VT-1 CS 803 I-6 CS1$ -17 VT-1 CS 803 I-6 ~

CS1$ -18 VT-1 RC 802 D-6 RC3"21 VT-1 RC 802 D-6 RC3-40 VT-1 RC 802 D-6 RC3-61 VT-1 RC 802 E-6 RC2-24 VT-1 RC 802 E-6 RC2-43 VT-1 RC 802 E-6 RC2"64 VT-1 ISI-201 Rev. 0 Page 30 of 74

APR008 SHEAROiN HARRIS UNIT NO. 1 PRESERVICE iNSPECTION PROGRAM PLY

SUMMARY

ASiME SECTlON XI'DITION 80W81 CATEGORY: B-G-2, Pressure Retaining Bolting, 2" and less in Diameter ITEM: B7.70, Bolts, Studs and Nuts (Valves)

FLOW FLOW SYSTEM/ DIAGRAM DIAG VALVE EE4'I RELIEF PROGRAM Component ~2166-G COORD NUBBER 'IETEUD R~E BEET Notes RC 800 B-3 V500 VT"1 RC 800 C"2 V501 VT-1 RC 800 M-2 V502 VT-1 RC 800 C-18 V503 VT-1 RC 801 E-2 V526 VT-1 RC 801 E-1 V527 VT-1 RC 801 H-2 V528 VT-1 RC 801 I-10 P525 VT-1 RC 801 K-10 P526 VT-1 RC 801 E"1 P527 VT-1 RC 801 F-1 P528 VT-1 RC 801 H-1 P529 VT-1 RC 801 F-8 R528 VT-1 RC 801 F-6 R529 VT-1 RC 801 F~4 R530 VT-1 RC 802 E-6 V540 VT-1 RC 802 E-6 V541 'IT-1 RC 802 E-6 V542 VT-1 CS 803 A"3 L500 VT-1 CS 803 A-4 L501 VT-1 CS 803 C-3 V504 VT-1 CS 803 C-3 V505 VT-1 CS 803 B-3 V506 VT'-1 CS 803 B-3 V507 VT-1 ISI-201 Rev. 0 Page 31 of 74

APR008 SHEARON HARRIS UNIT NO. 1 PRESERVICE INSPECTION PROGRAE'1 PLAN

SUMMARY

ASME SECTION XI EDITION 80W81 CATEGORY: B-G-2, Pressure Retaining Bolting, 2" and less in Diameter ITEM: B7.70, Bolts, Studs and Nuts (Valves)

FLOW FLOW SYSTEM/ DIAGRAM DIAG VALVE EXAM RELIEF PROGRAM Component ~2165-G COORD NUBBER NETNOD &ttUEST Notes SI 808 B-3 V507 VT-1 SI 808 C-3 V508 VT-1 SI 808 D-3 V509 VT-1 SI 808 B-ll V510 VT-1 SI 808 C-11 V511 VT-1 SI 808 B-17 V512 VT-1 SI 808 C-17 V513 VT-1 SI 808 D"17 V514 VT-1 SI 809 D-6 V544 VT-1 SI 809 H-6 V545 VT-1 SI 809 K-6 V546 VT-1 SI 809 D"3 V547 VT-1 SI 809 H-3 V548 VT-1 SI 809 K-3 V549 VT-1 SI 810 C-2 V584 VT-1 SI 810 E-2 V585 VT-1 SI 810 E-2 V586 VT-1 RH 824 L-4 V503 VT-1 RH 824 L-3 V502 VT-a RH 824 I-4 V501 VT-1 RH 824 I-3 V500 VT-1 ISI"201 Rev. 0 Page 32 og 74'

APR008 SHEARON HARRIS UNIT NO. 1 PRESERVICE INSPECTION PROGRAM PLAN

SUMMARY

ASME SECTION XI EDITION 80W81 CATEGORY: B-H, Integral Attachments for Vessels ITEM: B8.20, Integrally Welded Attachments FLOW FLOW SYSTEM/ DIAGRAM DIAG LINE EXAM RELIEF PROGRAM Comaonent ~2165-G COORD NUMBER HETEOO EEOOEET Eeeee PZR 801 J-6 Vol or Sur ISI-201 Rev. 0 Page 33 of 74

APR008 SHEARON HARRIS UNIT iNO. 1 PRESERVICE INSPECTION PROGRAi'l ?LAN SUMi'fARY ASME SECTION XI EDITION 74S75 CATEGORY: B-J, Pressure Retaining Welds in Piping ITEM: B9.11, Circumferential Welds, nps > 4" FLOW FLOW SYSTEM/ DIAGRAM DIAG LINE EXAM RELIEF PROGRAM Comnonent ~2166-G COORD NUMBER NETEOD ~RE EEET Notes RC 800 E-l. RC31"2 Vol & Sur RC 800 K-1 RC31-5 Vol & Sur RC 800 E" 19 RC31-8 Vol & Sux RC 800 G-7 RC29"1 Vol & Sur RC 800 J-7 RC29-4 Vol & Sur RC 800 G-14 RC29-7 Vol & Sur RC 800 D-6 RC274-3 Vol & Sur RC 800 L-7 RC27$ -6 Vol &, Sur RC 800 C-14 RC27$ -9 Vol & Sur RC 800. J~4 RC14-35 Vol & Sur RC 800 G-6 RC12-12 Vol & Sur RC 800 D-8 RC12-26 Vol & Sur RC 800 L-6 RC12-46 Vol &, Sur RC 800 F"11 RC12"51 Vol & Sur RC 800 C"11 RC12-65 Vol & Sur RC 800 G-8 RC6-10 Vol &. Sur RC 800 D-8 RC6-27 Vol & Sur RC 800 I-9 RC6-29 Vol & Sux RC 800 L-9 RC6-47 Vol & Sur RC 800 G" 10 RC6-49 Vol & Sur RC 800 E-10 RC6"66 Vol & Sur RC 800 D-6 RC6-25 Vol & Sur RC 800 M"5 RC4-44 Vol & Sur RC 801 M"6 RC14-35 Vol &, Sur RC 801 I-9 RC6-122 Vol & Sur RC 801 H-8 RC6-124 Vol & Sur RC 801 H"6 RC6-126 Vol & Sur RC "

801 H-5 RC6-128 Vol & Sur RC 801 H-3 RC6-135 Vol & Sux' RC RC 801 801 J ll K-ll RC4-25 RC4-44 Vol Sur Vol &, Sur RC 801 I-7 RC4"231 Vol & Sur ISI-201 Rev. 0 Page 34 of 74

APRO08 SHEARON HARRIS UNIT NO. 1 PRESERVICE INSPECTION PROGRAi'i PLAN

SUMMARY

ASiiE SECTION XI EDITION 74S75 CATEGORY: B-J, Pressure Retaining fields in Piping ITEM: ,B9.11, Circumferential fields, nps > 4 FLOM FLOV SYSTEM/ DIAGRAii DIAG LINE EXAM RELIEF PROGRAM Component ~(2266-G COORD iiMBER NETEOD ~RE EEET Notes SI 808 B "5 SI6-272 Vol & Sur SI 808 C-5 SI6"271 Vol & Sur SI 808 D-4 SI6-270 Vol & Sur SI 808 B-14 SI6-81 Vol & Sur SI 808 .C-14 SI6-80 Vol & Sur SI 808 D-17 SI6"314 Vol & Sur SI 809 D-4 SI12-161 Vol & Sur SI 809 G-4 SI12-i,62 Vol & Sur SI  ! 809 J-4 SI12-163 Vol & Sur RH 824 I-4 RH12-39 Vol & Sur RH 824 L-4 RH12 "38 Vol & Sur e

ISI-201 Rev. 0 Page 35 of 74

APR008 SHEARON HARRIS UNIT NO. -1 PRESERVICE INSPECTION PROGRAM PLAN SUiMMARY ASHE SECTION XI EDITION 74S75 CATEGORY: B>>J, Pressure Retaining Welds in Piping ITEM: B9.21, Circumferential Welds, nps G.T. 1 and L.T. 4" FLOW FLOW SYSTEM/ DIAGRAM DIAG LINE EXAM RELIEF PROGRAM Comoonent ~2165 "G COORD NUMBER HETHOD ~RE UEST Notes RC 800 D-2 RC3-21 Sur RC 800 D-3 RC3-23 Sur RC 80,0 E-8 'C3-28 Sur RC 800 M-7 RC3-45 Sur RC 800 M-2 RC3-40 Sur RC 800 C-18 RC3-61 Sur RC 801 H-2 RC3-139 Sur RC 801 F-2 RC3-140 Sur RC 801 E-2 RC3-141 Sur RC 802 E-6 RC3-21 Sur RC 802 E-6 RC3-40 Sur RC 802 E-6 RC3-61 Sur CS 803 A-3 CS3-116 Sur CS 803 B-3 CS3 117 Sur CS 803 C-3 CS3-118 Sur CS 803 I-4 CS1$ "16 Sur CS 803 I-4 CS14-17 Su" CS 803 I-4 CS14-18 Sur ISI-201 Rev. 0 Page 36 of 74

APRO08 SHEARON HARRIS UNIT itO. 1 PRESERVICE INSPECTION PROGRAM PLAN SU1'1'1ARY ASLfE SECTION XI EDITION 74S75 CATEGORY: B-J, Pressure Retaining Welds in Piping ITE.'f: B9.31, Branch Pipe Connection Welds, nps > 4" FLOW FLOW SYSTEM/ DIAGRAM DIAG LINE EXAM RELIEF PROGRAM Comnonent ~216 6 -G COORD NUifBER METHOD MIILKST Neeee RC 800 G-7 RC29-1 Vol & Sur RC 800 J-7 RC29-4 Vol & Sur RC 800 G-14 RC29-7 Vol & Sur RC 800 D-6 RC274"3 Vol &. Sur RC 800 L"7 ~ RC27$ -6 Vol & Sur'ol RC 800 C-14 RC274-9 & Sur ISI-201 Rev. 0 Page 37 of 74

APR008

~ ~

SHEARON HARRIS UNIT iNO. 1 PRESERVICE INSPECTION PROGRAM PLAN

SUMMARY

ASME SECTION XI EDITION 74S75 CATEGORY: B-J, Pressure Retaining fields in Piping ITEM: B9.32, Branch Pipe Connection Welds, nps G.T. 1" and L.T. 4" FLOW FLOV SYSTEM/ DIAGRAM DIAG LINE EXAM RELIEF PROGRAM Comaonent ~2161-G COORD QPifBER METHOD ~RE VEST Nones RC 800 E-1 RC31-2 Sur RC 800 K-1 RC31-5 Sur RC 800 E-19 RC31-8 Sur RC 800 G"7 RC29-1 Sur RC 800 J-7 RC29-4 Sur RC 800 G-14 RC29-7 Sur RC 800 D>>6 RC274-3 Sur RC 800 L-7 RC27j-6 Sur RC 800 C-4 RC274-9 Sur SI 808 C-5 SI6-272 Sur SI 808 C-5 SI6-271 Sur SI 808 D-4 SI6"270 Sur SI 808 ~ B-14 SI6-81 Sur SI 808 C"14 SI6-80 Sur ISI-201 Rev. 0 Page 38 of 74,

APR008

~ ~ ~

SHEARON HARRIS UNIT NO. 1

, PRESERVICE INSPECTIOiV PROGRAM PLAiV

SUMMARY

ASiK SECTIOiV Xl EDITION 74S75 CATEGORY: B-J, Pressure Retaining Welds in Piping ITEM: B9.40, Socket Welds, nps G.T. 1" FLOW FLOW SYSTEM/ DIAGRAM DIAG LINE EXAM RELIEF PROGRAM Component ~2165-G COOED NUMBER METHOD &IIUEST Notes RC 800 G-6 RC2-16 Sur RC 800 D-5 RC2"24 Sur RC 800 D-3 RC2-71 Sur RC 800 C-3 RC2-22 Sur RC 800 J-6 RC2-34 Sur RC 800 L-4 RC2-43 Sur RC 800 M-3 RC2"41 Sur RC 800 F-14 'C2-55 Sur RC 800 D-18 RC2 63 Sur RC 800 D-17 RC2-64 Sur RC 801 H-10 RC2-1.23 Sur RC 801 K-11 RC1$ -284 Sur RC 801 J"11 RC1$ "285 Sur RC 802 E-11 RC2"16 Sur RC 802 E-2 RC2-24 Sur RC 802 E-11 RC2-34 Sur RC 802 E-2 RC2-43 Sur RC 802 E-11 RC2"55 Sur RC 802 E-2 RC2-64 Sur CS 803 D-3 CS2-658 Sur SI 808 C "3 SI2-18 Sur SI 808 C-6 SI2-63 Sur SI 808 D-4 SI2"22 Sur SI 808 D"7 SI2-59 Sur SI 808 D-5 SI2-26 Sur SI 808 D-8 SI2-55 Sur SI 808 C-12 SI2-36 Sur SI 808 C" 14 SI2-69 Sur SI 808 C-13 SI2"40 Sur SI 808 C-16 SI2-73 Sur SI 808 D-16 SI2-78 Sur SI 808 D" 16 SI2-77 Sur SI 808 D-14 SI2"43 Sur TSI-201 Rev. 0 Page 39 of 74

0

~s ~

APR008

~ ~

SHEAROiN HARRIS UiNIT NO. 1 PRESERVICE INSPECTION PROGRAM PLAih

SUMMARY

ASiiE SECTIOiN XI EDITIOiN 74S75 CATEGORY: B-K-1, Integral Attachments for Piping, Pumps, and Valves

. ITEM: B10.10, Integrally Welded Attachments FLOW FLOW SYSTEM/ DIAGRAM DIAG LINE EXAM RELIEF PROGRAM Component ~2166-G COORD i%MMBER IIETEOO EEOOEET Notes RC 800 L-5 RC4-44 Sur RC 801 H-6 RC6-126 Sur RC 801 F-2 RC3-140 Sur RC 801 H-2 RC3-139 Sur RC 801 E-2 RC3-141 Sur SI 808 D-4 SI6"270 Sur SI 808 C-5 SI6 "271 Sur SI 808 B-5 SI6-272 Sur SI 808 C-14 SI6-80 Sur SI 808 B-14 SI6-81 Sur RH 824 L-4 RH12-38 Sur ISI-201 Rev. 0 Page 40 of 74

APR008 SHEARON HARRIS UNIT NO. 1 PRESERVICE INSPECTION PROGRAM PLAiN Sli~l"fARY ASME SECTION ZI EDITIOiN 74S75 CATEGORY: B-L-l, Pressure Retaining Welds in Pump Casing ITEM: B12.10, Pump Casing We'lds FLOW FLOW SYSTEM/ DIAGRAM DIAG EKQf RELIEF PROGRAM Component ~2165-G COORD NURSER NETRUD MIIUEST Notes RCP 800 C-3 1A'B Vol RCP 800 L-3 Vol RCP 800 C-17 lc Vol ISI-201 Rev. 0 Page 41 of .74

APR008

~ ~

SHEARON HARRIS lJNIT iNO. 1 PRESERVICE IiNSPECTION PROGRAi'I PLAN

SUMMARY

ASME SECTIOiN XI EDITION 74S75 .

.CATEGORY: B-L-2, Pump Casing and Valve Bodies ITEM: B12.20, Pump Casing FLOW FLOW SYSTEM/ DIAGRAM DIAG EXAM RELIEF PROGRAM'RE Comnonent ~2165-G COORD NUMBER IIETEOD UEET Nones RCP 800 C-3 lA VT-3 RCP 800 L"3 1B VT-3 RCP 800 C-17 1C VT-3 ISI-201 Rev. 0 Page 42 of 74

APRO08

~ ~

SHEARON HARRIS UNIT iNO. 1 PRESERVfCE IitSPECTION PROGRAi'1 PLAN

SUMMARY

ASiiE SECTION XI EDITION 80W81 CATEGORY: B-M-2, Pump Casing and Valve Bodies ITEiM B12.50, Valve Body G.T. 4" nps FLOW FLOW SYSTEM/ DIAGRAM DIAG VALVE EXAM RELIEF PROGRAM Comnonent ~2166 "G COORD NUMBER METHOD REOGEET Eeeee RC 801 F-8 R528 VT-3 RC 801 F-6 R529 VT-3 RC 801 F~4 R530 VT-3 SI 808 B-3 V507 VT-3 Sl 808 C-3 V508 VT-3 SI 808 D-3 V509 VT-3 SI 808 B-11 V510 VT-3 SI 808 C-11 V511 VT-3 SI 808 B-17 V512 VT-3 SI 808 C-17 V513 VT-3 SI 808 D"17 V514 VT"3 SI 809 D-6 V544 VT-3 SI 809 H"6 V545 VT-3 SI 809 K-6 V546 VT-3 SI 809 D"3 V547 VT-3 SI 809 H-3 V548 VT-3 SI 809 K-3 V549 VT"3 SI 810 C-2 V584 VT-3 SI 810 F"2 V585 VT-3 SI 810 E"2 V586 VT-3 RH 824 I-3 V500 VT"3 RH 824 I-4 V501 VT-3 RH 824 L"3 V502 VT-3 RH 824 L-4 V503 VT-3 ISI-201 Rev. 0 Page 43 of 74

APR008 SHEARON HARRIS UNIT NO. 1 PRESERVICE INSPECT1ON PROGRAM PLAN SUM.'1ARY ASME SECTION XI EDITION 80W81 CATEGORY: B-Q, Steam Generator Tubing ITr"'1: B16.20, U-Tube Steam Generator Tubing FLOW FLOW DIAGRAM DIAG EXAM RELIEF PROGRA'1 SYSTEiM/

~Con anent ~2166 -G COORD NUMBER METHOD REQUEST Notes S/G 800 E"3 1A Vol S/G 800 H-3 1B Vo1 S/G 800 E-17 1C Vo1 ISI-201 Rev. 0 Page 44 of 74

APR008

~ ~

APPENDIX B QUALITY GROUP B INSPECTION PLAN SALARY ISI-201 Rev, 0 Page 45 of 74

APR008 SHEAROiN HARRIS UBBtlT NO. 1 PR SERVICE INSPECTION PROGRAil PLAi4 St:..'i.'QBY ASifE SECTION XI EDITION 80W81 CATEGORY: C-A, Pressure Retaining Welds in Pressure Vessels ITEN: C1.10, Shell Circumferential Welds FLOW FLOW SYSTEM/ DIAGRAH DIAG EMM RELIEF PROGRAN Component ~(2165-G COORD NENBER iKTHOD &ttUEST Neeee S/G 042 E-1 lA Vol S/G 042 I-1 1B Vol S/G 042 L-1 1C Vol Rgn Ht Xchg 803 C-8 Vol X.L. Ht Xchg 803 D-11 Vol RHR Ht Xchg 824 C-14 1A Vol RHR Ht Xchg 824 E-14 1B Vol ISI-201 Rev. 0 Page 46 of 74

APRO08 SHEAROiN HARRIS UNIT NO. 1 PRESERVICE INSPECTION PROGRAi'i PLAN SUifiARY ASME SECTIOiN XI EDITIOiN 80W81 CATEGORY: C-A, Pressure Retaining Welds in Pressure Vessels ITE'i: C1.20, Head Circumferential Welds FLOW FIOW SYSTEii/ DIAGRAM DIAG EXAM RELIEF PROGRAM Component ~2165 -G COORD NUMBER METHOD .~RE VEST Notes S/G 042 E-1 1A Vol S/G 042 I-1 1B Vol S/G 042 L-1 1C Vol Rgn Ht Xchg 803 C-8 Vol X.L Ht Xchg 803 D-11 Vol B.I.T. 808 J"3 Vol RHR Ht Xchg 824 C-14 1A Vo 1 RHR Ht Xchg 824 E-14 1B Vol ISI-201 Rev. 0 Page 47 of 74

APR008 SHEARON HARRIS UNIT NO. 1 PRESERVICE INSPECTION PROGRAEi PLAN SUii.'1ARY ASiiE SECTION XI EDITION 80W81 CATEGORY: C-A, Pressure Retaining Welds in Pressure Vessels ITEii: Cl.30, Tubesheet-To-Shell Welds 1 FLOW FLOW SYSTEii/ DIAGRAH DIAG EXAii RELIEF PROGRAi~i Component ~2165-G COORD NUHBER METHOD &IIDEST Gee ee S/G 042 E-1 1A Vol S/G 042 I-1 1B Vol S/G 042 L-1 1C Vol ISI-201 Rev. 0 Page 48 of 74

APRO08 SHEARON HARRIS UNIT NO. 1 PRESERVICE INSPECTION PROGRAM PLAN SPL'1ARY ASME SECTION XI EDITION 80W81

.CATEGORY: C-B, Pressure Retaining Nozzle Welds in Vessels ITEM: C2.21, Nozzle to Shell (or Head) Weld, Nozzles without Reinforcing Plate in Vessels G.T. $ " nom. Thickness FLOW FLOW SYSTEM/ DIAGRAM DIAG EXAM RELIEF PROGRAM Comoonent ~2165-G COORD NUMBER METHOD R~E UEST Neeee B.I.T. 808 J"3 WW Vol & Sur S/G 42 E-1 1A Vol & Sur S/G 42 I-1 1B Vol & Sur S/G 42 L-1 IC Vol & Sur ISI-201 Rev. 0 Page 49 of 74

APR008

'SHEARON HARRIS UNIT NO. 1 PRESERVICE INSPECTION PROGRAM PLAN SUM".fARY ASi'iE SECTION XI EDITION 80W81 CATEGORY: C-B, Pressure Retaining Nozzle Welds in Vessels ITEM: C2.31, Reinforcing Plate Welds to Nozzle and Vessels in Vessels G.T.

nom. Thickness FLOW FLOW SYSTEM/ DIAGRAM DIAG EXAM RELIEF PROGRAif

'Com onset ~2165-G COORD NUMBER NETHOD R~EtiVST Notes RHR Ht Xchg 824 C-14 1A Sur RHR Ht Xchg 824 E-14 1B Sur ISI-201 Rev. 0 Page 50 of 74

APR008

~ ~ e SHEARON HARRIS UNIT NO. 1 PRESERVICE INSPECTION PROGRA.'1 PLAN SUM."SRY ASME SECTION XI EDITION 80W81 CATEGORY: C-B, Pressure Retaining Nozzle Welds in Vessels ITEM: C2e32, Nozzle'to Shell in Vessels G.T. $ " nom. Thickness, Inside of Vessel Inaccessible

'I FLOW FLOW SYSTEM/ DIAGRAM DIAG EXAM RELIEF PROGRAM Comnonent (2165"G) COORD NUBBER METHOD R~E liEST Rates RHR Ht Xchg 824 C" 14 1A VT-2 RHR Ht Xchg 824 E-14 1B VT-2 ISI-201 Rev. 0 Page 51 of 74

APR008 SHEARON HARRIS UNIT NO. 1 PRESERVICE INSPECTION PROGRAM PLAN

SUMMARY

ASNE SECTIOiN XI EDITION 80W81 CATEGORY: C-C, Integral Attachments for Vessels, Piping Pumps, and Valves ITEM: C3.10, Integrally Welded Attachments for Pressure Vessels FLOW FLOW SYSTEM/ DIAGRAM DIAG EXAif RELIEF PROGRAM Comnonent ~2165-G OOORD MPilBER METHOD &ttUEST 'Mates Regenerative Ht Xchg 803 C-8 Su?

Excess Letdown Ht Xchg 803 D-ll .Sur B.I.T. 808 J"3 Sur Accuml 809 C-11 1A Sur Accuml 809 F-11 1B Sur Accuml 809 I-11 1C Sur RHR Ht Xchg 824 C-14 1A Sur RHR Ht Xchg 824 E-14 1B Sur ISI-201 Rev. 0 Page 52 of 74

V y

6 e

APR008 SHEARON HARRIS UNIT iNO. 1 PRESERVICE INSPECTION PROGRAM PLAN SUi21ARY ASi'iE SECTIOiN XI EDITION 80W81 CATEGORY: C-C, Integral Attachments for Vessels, Piping Pumps, and Valves ITE'ii: C3.20, Integrally Welded Attachments for Piping FLOW FLOW SYSTEM/ DIAGRAM DIAG LINE EXAM RELIEF PROGRAM Component ~2166 -G COORD NUMBER NETEDD ~ffVEST Notes MS 042 H-1 MS32-2 Sur

~

MS 042 K-1 iMS32-3 Sur MS 042 D-2 i'iS32-1 Sur FW 044, L-2 FW16-69 Sur FW 044 D-2 FW16-67 Sur AF 044 C-6 AF6-59 Sur AF 044 C-6 AF6-60 Sur CT 050 K-13 CT12-3 Sur CT 050 M-10 CT12-7 Sur CT 050 F-16 CT12-4 Sur CT 050 J-16 CT12-6 Sur CT 050 . F-8 CT8-10 Sur CT 050 K-8 CT8-15 Sur CT 050 F-2 CT6-60 Sur CT 050 K-2 CT6-62 Sur CS 803 D-9 CS12-721 Sur CS 805 J-12 CS8-282 Sur CS 805 J-11 CS8-284 Sur CS 805 I-12 CS8-281 Sur ISI-201 Rev. 0 Page 53 of 74

APR008 SHEARON HARRIS UNIT NO. 1 PRESERVICE INSPECTION PROGRAM PLAN SU'1.'1ARY ASi'iE SECTION XI EDITION 80W81 CATEGORY: C-C, Integral Attachments for Vessels, Piping Pumps, and Valves ITEM: C3.20, Integrally Welded Attachments for Piping FLOW FLOW SYSTEM/ DIAGRAM DIAG LINE EXAM RELIEF PROGRAM Conoonent ~2165-G COORD NUMBER METHOD ~E<EUEST Notes Sl 809 D"8 SI12-223 Sur SI 809 K-8 SI12-225 Sur SI 810 M-7 SI14-254 Sur SI 810 C-5 SI 10-309 Sur SI 810 E-4 SI10-258 Sur SI 810 E-6 SI10-257 Sur SI 8 1'0 B-4 SI6-264 Sur SI 810 C-2 SI6-269 Sur SI 810 E-3 SI6-283 Sur RH 824 I-5 RH12-6 Sur RH 824 L-5 RH12-1 Sur RH 824 I-12 RH10 "8 Sur RH 824 E-9 RH10 "9 Sur RH 824 C-8 RH10-4 Sur ISI-201 Rev. 0 Page 54 of 74

APR008

~ ~

SHEAROiN HARRIS UiNIT NO. 1 PRESERVICE INSPECTION PROGRAM PLAN

SUMMARY

ASME SECTION XI EDITION 80W81 CATEGORY: C-C, Integral Attachments for Vessels, Piping, Pumps, and Valves ITEM: C3.30, Integrally Welded Attachments for Pumps FLOW FLOW SYSTEiM/ DIAGRAM DIAG EK221 RELIEF PROGRAM Component ~(2166-G COORD iiMBER iMETHOD ~RE OEST Seeee CSIP 805 H-9 1A Sur CSIP 805 K-9 1B Sur CSIP 805 J-9 1C Sur ISI-201 Rev. 0 Page 55 of 74

APR008 SHEARON HARRIS UNIT iNO. 1 PRESERVICE INSPECTION PROGRAM PLAN SUM."fARY ASiME SECTION XI EDITION 74S75 CATEGORY: C-r, Pressure Retaining titelds in Piping "

ITEif: C-5.11, Circumferen ial Melds, Th < $ Nom.

PLOtit FLOW SYSTEM/ DIAGRAM DIAG LINE EXALT RELIEF PROGRAif Comoonent ~2165-G COORD NUMBER METEOR REtEUEST Noses CS 805 K-12 CS8-320 Sur CS 805 K-11 CS8-302 Sur CS 805 K"13 CS8-327 Sur CS 805 J"12 CS8-282 Sur CS 805 J-12 CS8"321 Sur CS 805 I-12 CS8-281 Sur CS 805 J-11 CS8-284 Sur CS 805 H-10 CS6-285 Sur CS 805 J-10 CS6-288 Sur CS 805 K-10 CS6-290 Sur SI 809 D-8 SI12-158 Sur SI 809 H-10 ST12-159 Sur SI 809 K-10 ST12-160 Sur SI 810 if-4 SI14-251 Sur SI 810 M-7 SII4"254 Bur SI 810 M"11 SI14-256 Sur SI 810 N-4 SI14-252 Sur SI 810 N"8 SI14-253 Sur SI 810 N-11 SI14-255 Sur SI 810 E-6 SI10"257 Sur SI 810 B-4 SI10-264. Sur SI 810 C "5 SI10-309 Sur SI 810

'E-4 SI10-258 Sur SI 810 B"5 SI8-265 Sur ISI-201 Rev. 0 Page 56 of 74

APR008 SHEARON HARRIS UNIT NO. 1 PRESERVICE INSPECTlON PROGRAM PLAN SUiiMARY ~

ASiiE SECTIOiV KI EDITION 74S75 CATEGORY: C-F, Pressure Retaining, Welds in Piping ITEM: C-5.11, Circumferential Welds, Th 5 $ " Nom.

FLOW FLOW SYSTEM/ DIAGRAM DIAG LINE ETIAM RELIEF PROGRAM Component ~2165-G COORD NUNBER RETRO U &INQUEST Ãotee RH 824 L-9 RH14-2 Sur RH 824 I-8 RH14-7 Sur RH 824 L-5 RH12-1 Sur RH 824 I "5 RH12-6 Sur RH 824 L"12 RH10-3 . Sur 824 C-8 RH10-4 Sur RH 824 I-12 t RH10 "8 Sur RH 824 E-9 RH10-9 Sur RH 824- C-13 RH8-20 Sur RH 824 E-14 RH8-5 Sur RH 824 E-12 RH8-33 Sur RH 824 G-11 RH8"10 Sur MS 042 C-8 MS8-107 Sur MS 042 J-7 MS8-109 Sur MS 042 G-8 MS8-108 Sur MS 042 K-7 MS6-57 Sur MS 042 .

H"7 e MS6-56 Sur AF 044 C-6 AF6-59 Sur AF 044 I"5 AF6-7 Sur AF 044 M-5 AF6-60 Sur AF 044 C-2 AF6-93 Sur AF 044 C-2 AF6-92 Sur AF 044 C-2 AF6-91 Sur CT 050 F-16 CT12-4 Sur 050 J-16 CT12-6 Sur CT 050 K-13 CT12-3 Sur CT 050 M-10 CT12-7 Sur 050 F-8 CT8-10 Sur CT 050 K-8 CT8" 15 Sur 050 F-5 CT6-14 Sur 050 F-3 CT6-163 Sur 050 F-2 CT6-60 Sur CT 050 K-2 CT6-62 Sur 050 L-4 CT6-19 Sur CT 050 L-3 CT6-162 Sur ISI-201 Rev. 0 Page 57 of 74

APR008 SHEARON HARRIS UNIT NO. 1 PRESERVICE INSPECTIOiV PROGRAM PLAiV SUM.'fARY ASiME SECTIOiV XI EDITION 74S75 CATEGORY: C-F, Pressure Retaining Velds in Piping ITEM: C-5.12, Longitudinal Velds, Th S $ " Nom.

FLOW FLOtlt SYSTEM/ DIAGRAM DIAG I INE EXAM RELIEF PROGRAM Component ~2165-G COORD NONBEE NETEOD &ttUEET Ne tee SI 810 N-8 SI14-253 Sur SI 810 M-7 SI14-254 Sur RH 824 L-9 RH14-2 Sur RH 824 I-8 RH14-7 Sur RH 824 L"5 RH12-6 Sur RH 824 I "5 RH12-1 Sur e

ISI-201 Rev. 0 Page 58 of 74

APRO08 SHEARON HARRIS UNIT NO. 1 PRESERVICZ INSPECTION PROGRA.'i PLAN SUiiMARY ASEME SECTION XI EDITION 74S75 CATEGORY: C-F, Pressure Retaining Welds in Piping ITEM: C5.21, Circumferential Welds, Th > $ " Nom.

FLOW FLOW SYSTEM/ DIAGRAM DIAG LINE EXAM RELIEF PROGiMi Component ~(2166-G COORD NUMBER HETEOD ~EE VEST Mores CS 803 D-9 CS12-721 Vol & Sur SI 808 C-ll SI10-304 Vol & Sur SI 808 C-ll SI6 "27 Vol & Sur SI 808 C-11 SI6-28 Vol & Sur SI 809 D-8 SI12"223 Vol & Sur SI . 809 H-8 SII2-224 Vol & Sur SI 809 K-8 SI12-225 Vol & Sur SI 810 B-2 SIIO-304 Vol & Sur SI 810 C-3 SI10-308 Vol & Sur SI 810 E-3 SI10-303 Vol & Sur

. SI 810- C-2 SI6-269 Vol & Sur SI 810 E-2 SI6-267 Vol &,Sur SI 810 E-3 SI6-283 Vol & Sur SI 810 E-2 SI6"268 Vol & Sur MS 042 D-2 MS34-235 Vol & Sur MS 042 G-5 MS34-236 Vol & Sur MS 042 K-5 MS34-237 Vol & Sur MS 042 D-1 MS32-1 Vol &, Sur MS 042 H-l MS32-2 Vol & Sur MS 042 K-1 MS32-3 Vol & Sur MS 042 D-8 MS12-122 Vol & Sur MS 042 H-8 MS12-123 Vol & Sur MS 042 K-8 MS12-124 Vol & Sur FW 044 B-6 FW16-13 Vol & Sur FW 044 G-6 FW16-15 Vol & Sur FW

'44 L-6 FW16-17 Vol & Sur FW 044 D"3 FW16-67 Vol & Sur FW 044 D-3 FW16-68 Vol & Sur FW 044 D-3 FW16"69 Vol & Sur ISI-201 Rev. 0 Page 59 of 74

APR008 APPENDIX C QUALITY GROUP C INSPECTION PLAN

SUMMARY

ISI-201 Rev. 0 Page 60 of 70

~ . APR008 SHEARON HARRIS UNIT NO. 1 PRESERVICE INSPECTION PROGRAM PLAN

SUMMARY

ASME SECTION XI EDITION 80W81 CATEGORY: D-A, Systems in Support of Reactor Shutdown Function ITE.'i: D1.20, Dl.30, Dl.40, D1.50, and D1.60; Integral Attachments FLOW FLOW SYSTEM/ DIAGRAM DIAG LINE EXAi~f RELIEF PROGRAM

~Com ooeot ~2165 -G COORD EIDIBER 'IETEOD REOOEET Rot em MS 042 N-3 MS16-185 VT-3 ifS 042 M-3 'fS16-238 VT"3 MS 042 L-2 MS8"230 VT"3

."iS 042 N-3 MS8"239 VT-3 ifS 042 L"2 MS6"223 VT-3

.'iS 042 H-.3 MS6-59 VT-3 MS 042 L-'5 MS6-60 VT-3 MS 042 M-,2 'iS6-130 VT-3 ifS 042 N-1 MS6-166 VT-3 AF 044 M-,ll AF6-8 VT-3 AF 044 if-9 AF6-16 VT-3 AF 044 N-5 AF4-76 VT"3 AF 044 N-4 AF4-6 VT-3 AF 044 N-9 AF4-10 VT-3 AP 044 M"8 AF4-11 VT-3 AF 044 N-9 AF4-9 VT-3 AF 044 J-7 AF4-78 VT-3 AF 044 J-5 AF4-5 VT-3 AF 044 E-6 AF4-94 VT-3 AF 044 I-7 AF4 "55. VT-3 AF 044 I-11 AF4-3 VT-3 AF 044 N-ll AF4-74 VT-3 AF 044 D-6 AF4-2 VT-3 AF 044 D-11 AF4-1 VT"3 AF 044 H"7 AF4-4 VT"3 AP 044 N-7 AF4-77 VT-.3 AF, 044 H-13 AF3-15 VT-3 AF 044 D"12 AF2-12 VT-3 AF 044. I"12 AF2-13 VT-3 AF 044 L-13 AF2-14 VT-3 AF 045 B-6 AF3-120 VT-3 AF 045 B-6'-7 AF2-119 VT-3 045 CE8 38

'T-3 CE CE 045 H"9 CE8"41 VT-3 CE 045 H-7 CE6-39 VT-3 CE 045 H-8 CE6-40 VT"3 CE 045 J-9 CE6"196 VT"3 ISI"201 Rev. 0 Page 61 of 74

APR008 SHEARON HARRIS UNIT NO. 1 PRESERVICE INSPECTION PROGRAi'1 PLAN SU.'1.'1ARY ASME SECTION XI EDITION 80V81 1

CATEGORY: D-B, Systems in Support of ECCS, Containment Heat Removal, Atmosphere Cleanup, and RHR ITEM: D2.20, D2.30, D2.40, D2.50 and D2.60, Integral Attachments FLOW FLOW SYSTEM/ DIAGRAM DIAG LINE EXAN RELIEF PROGRAM Comaonent ~(2266-G COORD i%JMBER EETEQD ~EE bVST Getee SV '047 D-5 SV30-2 VT-3 SW 047 G-1 SW30-3 VT-3 SW 047 C "5 SW30"5 VT-3 SV 047 G-2 SW30"6 VT-3 SW 047 I-1 SW30-10 VT-3 SW 047 I-2 SV30-11 VT-3 SW 047 .'1-9 SW30-25 VT-3 SW 047 L-15 SW30-99 VT-3 SW 047 L-13 SW30"146 VT-3 SV 047 L-6 SV24"67 VT-3 SW 047 H-5 SW24-66 VT-3 SV 047 H-13 SV24-72 VT-3 SW 047 K-13 SW24-73 VT-3 SW 047 H"4 SW20-8 VT-3 SV 047 M" 12 SWI8-22 VT-3 SW 047 H-13 SW16"7 VT-3 SW 047 H"6 SW14-26 VT-3 SW 047 F-5 SW14-27 VT-3 SW 047 E-6 SW14-28 VT-3 SV 047 G-7 SW14-39 VT-3 SW 047 H-14 SW14"45 VT-3 SV 047 F-14 SW14-46 VT-3 SW 047 F"14 SV14-47 VT-3 SW 047 F-13 'W14-53 VT-3 SW 047 H-7 SW14-.343 VT-3 SV 047 ,G-13 SW14-345 VT-3 SW 047 G 5 SW12-4 10 VT-3 SW 047 G-14 SV12-411 VT-3 SW 047 "

I-4 SW12-83 VT"3 SW 047 M-7 SW12-84 VT-3 SW 047 I-11 SW12-85 VT-3 SW 047 K-11 SW12-86 VT-3 SV 047 ~ D-6 SW10-31 VT-3 SW 047 D-7 SW10"33 VT-3 SW 047 G-13 SW10-34 VT-3 SW 047 E-8 SW10-36 VT-3 ISI-201 Rev. 0 Page 62 of 74

APR008 SHEARON HARRIS UNIT NO. 1 PRESERVICE INSPECTION PROGRAM PLAN Sl iMARY ASME SECTION XI EDITION 80V81 CATEGORY: D-B, Systems in Support, of ECCS, Containment Heat Removal, Atmosphere Cleanup, and RHR ITEM! D2.20, D2.30, D2.40, D2.50 and D2.60, Integral Attachments FLOW FLOW

, SYSTEM/ DIAGRAM DIAG LINE EXI RELIEF PROGRAi'1 Component ~(2165-G COORD NtKBER METHOD R~E DEBT Notes SW 047 E-10 SW10-38 VT-3 SV 047 E-11 SW10-52 VT-3 SW 047 D-13 SW10-54 VT-3 SV 047 D-13 SW10-57 VT-3 SW 047 I-7 SW10-68 VT-3 SV 047 D-14 SV10"297 VT-3 SW 047 I-10 SV10-74 VT-3 SV 047 B-1 SW10 "752 VT-3 SW 047 J-9 SW8-81 VT-3 SV 047 H-10 SW8-87 VT>>3 SV 047 L-14 SW8-88 VT-3 SV 047 K-14 SW8-122 VT-3 SV 047 I-8 SW8-128 VT-3 SV 047 I"14 SW8-165 VT"3 SW 047 H"9 SW8-338 VT-3 SW 047 J-10 SW6"80 VT"3 SW 047 J-S SV6-82 VT-3 EA 133 G"3 EA24-1 VT-3 EA 133 G-3 EA24-2 VT-3 EA 133 G-5 EA24-3 VT-3 EA 133 G-5 EA24-4 VT-3 CH 498 B"2 CH10-91 VT"3 CH 498 B-5 CH8"208 VT-3 CH 498 B-11 CH-205 VT-3 CX 498 M-5 CX10"118 VT-3 CX 498 M"7 CX8-201 VT-3 498 J-3 CX6-187 VT-3 CX 498 K-10 CX6-200 VT-3 CH 498S02 G-14 CH10" 91 VT-3 CX 498S02 H-6 CX10" 168 VT-3 CX 498S02 K"9 CX10-118 VT-3 SW 498S02 F-6 SV10 938 VT-3 SV 498S02 E-7 SV8-800 VT"3 498S02 E"11 SV8-801 VT"3 SV 498802 D"8 SW6-875 . VT"3 CH 499 B CH10-50 VT-3 CH 499 B 11 CH8-51 VT-3 CH 499 ~ 3-10 CH6-72 VT-3 ISI-201 Rev. 0 Page 63 of 74

'l APR008 SHEARON HARRIS UNIT NO. 1 PRESERVICE INSPECTION PROGRAM PLAN SEi.'1ARY ASME SECTION XI EDITION 80W81 CATEGORY: D-B, Systems in Support, of ECCS, Containment Heat Reraoval, Atmosphere Cleanup, and RHR ITEM: D2.20, D2.30, D2.40, D2.50 and D2.60, Integral Attachments FLOW FLOW SYSTEM/ DIAGRAM DIAG LINE EXAM RELIEF PROGRAM Comoonent ~2165-G COORD EDEBER EETEQD l~K DEBT Noses CX 499 K-16 CX10-68 VT-3 CX 499 L-12 CX8-69 VT-3 CX 499 K-10 CX6-116 VT-3 CH 499S02 G" 14 CH10-50 VT-3 CX 499S02 L-12 CX10-68 VT-3 CX 499S02 H-6 CX10-172 VT-3 SW 499S02 E-7 SW8-804 VT-3 SW >>99S02 E-11 SW8-805 VT-3 SW 499S02 D-8 SW8-876 VT-3 CC 819 G-3 CC18-2 VT-3 CC 819 E-8 CC18-3 VT"3 CC 819 E-15 CC18"4 VT-3 CC 819 K-4 CC18-5 VT-3 CC 819 L-11 CC18-6 VT-3 CC 819 H"8 CC18-18 VT-3 CC 819 H-9 CC18-19 VT-3 CC 819 J-16 CC18-7 VT-3 CC 819 G-5 CC18"16 VT-3 CC 820 B-12 CC12-12 VT-3 CC 820 A 3 CC12-13 VT-3 CC 820 M-12 CC12-14 VT-3 CC 820 L-3 CC12-15 VT-3 CC 821 D-1 CC8-10 VT-3 CC 821 B-16 CC8-146 VT-3 CC 821 B"11 CC6-145 VT-3 CC 821" E-1 CC6-147 VT-3 CC 821 E-1 CC6-148 VT-3 CC 821 G-1 CC6-149 VT-3 CC 821, G"12 CC6-195 VT-3 CC 821 D-12 CC6-201 VT"3 CC 821 D-2 CC6 130 VT-3 CC, 822 M"8 CC20-254 VT-3 CC 822 F-5 CC20-11 VT-3 CC 822 F-13 CC18-251 VT-3 CC 822 L-14 CC18"252 VT-3 ISI-201 Rev. 0 Page 64 of 74

APR008 SHEARON HARRIS UNIT NO. 1 PRESERVICE INSPECTION PROGRAM PLAN SUlMRY ASifE SECTION XI EDITION 80W81 CATEGORY: D-B, Systems in Support of ECCS, Containment Heat Removal, Atmosphe e Cleanup, and RHR ITEM: D2.20, D2.30, D2.40, D2.50 and D2.60, Integral Attachments FLOW FLOW SYSTEM/ DIAGRAM DIAG LINE EXAM RELIEF PROGRAM Comoonent ~(2166-G COORD NUMBER: METHOD R~E UiST Notes J

CC 822 F-14 CC14-281 VT-3 CC 822 J-15 CC14-282 VT-3 CC 822 F-13 CC14 -411 VT-3 CC 822 G-14 CC14"412 VT-3 CC 822 H-14 ~ CC14-413 VT-3 CC 822 K-15 CC14-414 VT-3 CC 822 L-4 CC6-275 VT-3 CC 822 i'-12 CC8-544 VT-3 CC 822 G-4 CC6-274 VT-3 ISI-201 Rev. 0 Page 65 of 74

0 APR008 SHEARON HARRIS UNIT NO. 1 PRESERVICE INSPECTION PROGRAM PLAN SUiiMARY ASME SECTION XI EDITIOiN 80W81 CATEGORY: D-C, Systems in Support, of Residual Heat Removal from Spent Fuel Storage Pool ITEM: D3.20, D3.30, D3.40, D3.50 and D3.60, Integral Attachments FLOW FLOW SYSTEM/ DIAGRAM DIAG LINE EXAM RELIEF PROGRAM Comoonent ~(2165-G COORD NUBBER METHOD ~RE UEST Notes SF 305 E-16 SF16"1 VT-3 SF 305 E-16 SF16-2 VT-3 SF 305 H-11 SF16-7 VT-3 SF 305 J-ll SF1'6<<8 VT-3 SF 305 H-10 SF14-283 VT-3 SF 305 J-10 SF14-284 VT-3 SF 305 H-5 SF12-3 VT-3 SF 305 K-5 SF12-4 VT-3 SF 305 B-3 SF 12-5 VT-3 SF 305 A-3 SF 12-6 VT-3 SF 305 G-8 SF 12-9 VT-3 SF 305 J"8 SF 12-10 VT-3 SF. 305 J-6 SF12-11 VT-3 SF 305 H-11 SF12-12 VT-3 SF 305 J-11 SF12-14 VT-3 SF 305 F"14 SF12-171. VT-3 SF 305 . F-13 SF12-174 VT-3 SF 305 B-6 SF12-176 VT-3 SF 305 C-6 SF12-179 VT"3 SF 305 F-14 SF12-82 VT-3 ISI-201 Rev. 0 Page 66 of 74

. APR008 APPENDIX D AUGiiEiVZED INSPECTION PLAN SUNRAY ISI-201 Rev. 0 Page 67 of 74

APR008 SHEARON HARRIS WiIT aaiO. 1 PRESERVICE INSPECTION PROGRAM PLAN StTMMARY CATEGORY: Reg. Guide 1.14 ITEM: RCP Flywheel Keyway and Bore Areas FLOW FLOW SYSTEM/ DIAGRAM DIAG EXAM RELIEF PROGRAM

~Com onenn ~2165-6 COORD N1DlBER tlETHOD . RElEUEBT Nomen Flywheel 800 C-3 1A Vol Flywheel 800 L-3 1B Vol Flywheel 800 C-17 1C Vol ISI-201 Rev. 0 Page 68 of 74

APR008 SHEARON HARRIS UNIT NO. 1 PRESERVICE IiNSPECTION PROGRAM PLAN SUif.'fARY CATEGORY: Reg. Guide 1.14 ITE'f Flywheel Exposed Surface FLOW FLOW SYSTEM/ DIAGRAM DIAG LINE EM RELIEF PROGRAM Comnonent, ~2165-G COORD NUMBER EETEOD REIEUEST Retee Flywheel 800 C-3 1A Vol 6 Sur Flywheel 800 L-3 1B Vol & Sur Flywheel 800 C-17 1C Vo'1 8 Sur ISI-201 Rev. 0 Page 69 of 74

APR008 SHEARON HARRIS UiNIT NO. 1 PRESERVICE INSPECTION PROGRAM PLAih SUHijARY CATEGORY: Augmented Piping Welds FLOW FLOW SYSTEM/ DIAGRAM DIAG LINE EXAM RELIEF PROGRAi'j Comoonent ~2565-G COORD IIIeeIBEE .'IETEOD RE(EGEST Eoeee MS 042 D-8 MS12-122 Vol 2,4 MS 042 K"8 MS12-123 Vol 2,4

'jS 042 H-8 MS12-124 Vol 2,4 MS 042 D-2 MS34-235 Vol HS 042 G-5 MS34-236 Vol iiS 042 K-5 i~js34-237 Vol iiS 042 F-10 MS50-7 Vol

.'iS 042 F-11 MS44-8 Vol 2,4 MS 042 G-11 "jS44-9 Vol 4, "jS 042 D"9 iS32-4 Vol 2,4 iiS 042 G-9 ".jS32-5 Vol 2,4 iiS 042 K-9 MS32-6, 2,4

'jS 042 C-8 MS8-107 4 MS 042 G-8 MS8-108 Vol'ol'ol'ol'ol 2,4 MS 042 J-7 HS8-109 2,4 Ms 042 C"3 MS8-62 2,4,7 iiS 042 C-4 MS8-63 Vol 2,4,7 MS 042 C "5 MS8-64 Vol MS 042 C"6 MS8-65 Vol iiS 042 C-6 MS8-66 Vol ijS 042 G"3 MS8-67 Vol HS 042 G-4 MS8"68 Vol HS 042 G-5 MS8-69 Vol iiS 042 G-6 MS8-70 Vol MS 042 G-6 MS8-71 Vol MS 042 J"3 MS8-72 Vol MS 042 J~4 MS8-73 Vol Ms 042 J-5 MS8-74 Vol MS 042 J-6 MS8-75 Vol MS 042. J-6 MS8-76 Vol Ms 042 H"7 MS6-56 Vol iiS 042 K-7 MS6-57 Vol 2,4 HS 042 D-8 MS3 116 Vol 2,4 Ms 042 H-8 MS3-117 Vol Ms 042 K-8 MS3-118 Vol 454 FW 044 C-3 FW16-13 Vol 1,2,4 FW 044 F-3 FW16-15 Vol 1,2,4 FW 044 F-3 FW16-17 Vol AF 044 C-5 AF6-59 Vol AF 044 G-3 AF6-7 Vol 1,4 AF 044 K"3 AF6-60 Vol 1,4 AF 044 H-8 AF4-98 Vol 1,4 AF 044 C-6 AF4-95 Vol 1,4 AF 044 E-6 AF4-75 Vol 1,4 ISI-201 Rev. 0 Page 70 of 74

APRO08 SHEARON HARRIS UNIT NO. 1 PRESERVICE INSPECTION PROGRAM PLAN

SUMMARY

CATEGORY: Augmented Piping Welds FLOW FLOW SYSTEM/ DIAGRAM DIAG LINE RELIEF PROGRAM EXP'ETROD Conoonent ~(2165-G COORD NU11BER RE(El)EST Notes G-4 AF4"96 Vol 1,4 044 F-5 AF4-97 Vol 1,4 044 G-7 AF4 "85 Vol 1,4 044 G-19 FW3-83 Vol 2 4 044 G-19 FV3-82 Vol 2,4 044 G-19 FW3 "84 Vol 2,4 G-19 FV3-85 Vol 2,4 044 G-19 FV3-86 Vol 2,4 044 G-19 FW3-87 Vol 2,4 044 B-8 FV16-12 Vol 4 044 G-8 FV16-14 Vol 044 K-8 FV16-16 Vol 2,4 FV 044 E-19 FW6-78 Vol 2,4 FV 044 E-19 FV6-76 Vol 2,4 FV E-19 FV6-80 Vol 2,4 FW E-19 FW2-129 Sur 2,4 FV E-19 FW2-130 Sur 2,4 FV E-19 FW2-131 Sur CT 050 F-16 CT24-1 Sur 5 CT 050 H-16 CT16-8 Sur CT 050 G-16 CT14-79 Sur 5 CT 050 H-16 CT14-9 Sur CT 050 G"16 CT8-65 Sur 5 CT 050 G"16 CT8-77 Sur CT 050 F-8 CT8-10 Sur 5 CT 050 K-8 CT8-15 Sur 5 BD 051 D"5 BD4"3 Sur 3,4 BD 051 I-4 BD4-7 Sur 3,4 BD 051 N"5 BD4-11 Sur 3,4 CS 803 A"14 CS3"96 Sur 3,4 CS 803 B-17 CS3-95 Vol 1,4 CS 803 B-10 CS2-138 Sur 3,4 CS 803 B "11 CS2"91 Sur 3,4 CS 803 B-12 CS2-92 Sur 3,4 CS. 803 J-3 CS14-19 Sur 3,4 CS 803 J"3 CS1$ -20 "Sur . 3,4 CS 80,3 J-3 CS1$ -21 Sur 3,4 CS 805 H-6 CS4-300 Vol 5 CS 805 H-8 CS3-294 Vol 5 ISI-201 Rev. 0 Page 71 of. 74

APR008 SHEARON HARRIS UNIT NO. 1 PRESERVICE IiNSPECTION PROGRAM PLAN SRPifARY CATEGORY: Augmented Piping Welds FLOW FLOW SYSTEM/ DIAGRAM DIAG LINE EXAM RELIEF PROGRAM Comoonent ~(2165-G COORD NUffBER i'fETHOD REfEUEBT Notes CS 805 K-8 CS3-337 Vol 5 CS 805 J-7 CS3-292 Vol 5 SI 808 K-13 SI4"32 Vol 5 SI 808 M-13 SI4-1 Vol 5 SI 808 J"13 SI4-47 Vol 5 SI 808 M-14 SI4-84 Vol 5 SI 808 F-11 SI3-2. Vol 5 SI 808 N-6 SI3-4 Vol 5 SI 808 if-5 SI3-45 Vol 5 SI 808 L-3 SI3-44 Vol 5 SI 808 K-3 SI3-410 Vol SI 808 H"3 SI3-11 Vol 5 SI 808 F-2 SI3-12 Vol 5 SI 808 K-12 SI3-3 Vol 5 SI 80& H-13 SI3-49 Vol 5 SI 808 F-11 SI3-50 Vol 5 SI 808 F 14 SI3-51 Vol 5 SI 808 E-3 SI2-17 Sur 5 SI 808 E"4 SI2-21 Sur 5 SI 808 E-5 SI2-23 Sur 5 SI 808 E-14 SI2-68 Sur 5 SI 808 E-15 SI2-72 Sur 5 SI 808 E"8 SI2-52 Sur 5 SI 808 E-7 SI2-58 Sur 5 SI 808 E-6 'I2-60 Sur 5 SI 808 E-16 SI2-76 Sur 5 SI 808 E" 13 SI2-39 Sur 5 SI 808 E-14 SI2-29 Sur 5 SI 808 E-12 S12"33 Sur 5 ISI-201 Rev. 0 Page 72 of 74

APR008 APPENDIX E PERSONNEL QUALIFICATION PROGiVui FOR AUSTENETIC MELD INSPECTION ISI-201 Rev. 0 Psge 73 of 74

APR008 QUALIFICATION PROGRAM (1) CP&L or their agent will prepare a Qualificat'on Program Plan to assure the following:

(a) The techniques applied are effective for the detection, characterization, sizing, and evaluation of service induced defects.

(b) Personnel performing the examinations, including de-tection, characterization, and sizing are capable of carrying out these procedures.

(c) That performance of examinations in the plant reflect the capabilities .demonstrated in the qualification program (1)

(a) and (b) above.

(2) The Qualification Program Plan shall address the 'follow'ng:

(a) Procedure and equipment requirements.

(b) The description of the test parts including number of cracks, geometrical reflectors, and samples containing no defects. The suitability of these samples to demonstrate the objectives of the Qualification Program Plan.

(c) Criteria for acceptance of the demonstration for both procedures and personnel.

(d) Period for which qualification is valid. as well as con-ditions which require requalification.

(e) The components to which the qualification applies.

Documentation of the qualification results.

(3) The Qualification Test Program shall be 'reviewed by the Authorized Nuclear Inservice Inspector.

ISI-201 Rev. 0 Page 74 of 74

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