Text

Proposed Tech Specs,Relocating 3/4.3.3.3,3/43.3.4,3/4.3.3.9 & 3/4.3.3.11 to Plant Procedure PLP-114, Relocated Tech Specs & Design Basis, IAW GL 95-10
	ML18016B013
Person / Time
Site:	Harris
Issue date:	07/09/1999
From:	; CAROLINA POWER & LIGHT CO.
To:	;
Shared Package
ML18016B012	List: ML18016B011; ML18016B013;
References
	GL-95-10, NUDOCS 9907150216
	Download: ML18016B013 (137)
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ENCLOSURE 5 TO SERIAL: HNP-99-108 SHEARON HARRIS NUCLEAR POWER PLANT DOCKET NO. 50-400/LICENSE NO. NPF-63 RELOCATION OF SELECTED INSTRUMENTATION TECHNICAL SPECIFICATION PAGES Page E5-1 99071502i6 990709 05000400 PDR ADQCK PDR

INDEX LIMITING CONDITIONS FOR OPERATION AND SURVEILLANCE REQUIREMENTS SECTION PAGE TABLE 3.3-6 RADIATION MONITORING INSTRUMENTATION FOR PLANT OPERATIONS 3/4 3-51 TABLE 4.3-3 RADIATION MONITORING INSTRUMENTATION FOR PLANT OPERATIONS SURVEILLANCE REQUIREMENTS 3/4 3-54 pg(

(Deleted) 3/4 3-56 I Seismic Instrumentation Add 3/4 3-57 TABLE 3.3-7 SEISMIC MONITORING INSTRUHENTATIO .C~~f<24cf) 3/4 3-58 TABLE 4.3-4 SEISMIC MONITORING INSTRUMENTATION SURVEILLANC REQUIRFMENTS CD I Meteorological Instrumentation

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.C4</eke . . . .

3/4 3-59 3/4 3-60 TABLE 3.3-8 METEOROLOGICAL MONITORING INSTRUMENTATION Qelcfal), 3/a 3-61 TABLE 4.3-5 METEOROLOGICAL MONITORING'INSTRUMENTATION SURVEILLANC REQUIREMENTS...g. p~/~~gg.. ~gg........ 3/4 3-62 Remote Shutdown System . . . . . . . . . . . . . . . 3/4 3-63 TABLE 3.3-9 REMOTE SHUTDOWN SYSTEM 3/4 3-64 TABLE 4.3-6 REMOTE SHUTDOWN MONITORING INSTRUMENTATION SURVEILLANCE REQUIREMENTS 3/4 3-65 Accident Monitoring Instrumentation 3/4 3-66 TABLE 3. 3-10 ACCIDENT MONITORING INSTRUMENTATION 3/4 3-68 TABLE 4.3-7 ACCIDENT MONITORING INSTRUMENTATION SURVEILLANCE REQUIREMENTS.................... 3/4 3-70 TABLE 3.3-11 (DELETED) . . . . . . . . . . . . . . . . . . . . . 3/4 3-73 ge,le& Metal Impact Monitoring System, C4>elcfo/J ..... 3-74

. . . . . .. . . . . . . . .. . , . .. 3/4'DELETED) 3/a 3-75 Explosive Gas Monitoring Instrumentation C~/cf!4 . 3/a

'-82 TABLE 3.3-13 INSTR MENTATIO ......

EXPLOSIVE GAS MONITORING C~~~~+

>..@gal .. 3/4 3-83 TABLE 4.3-9 EXPLOSIVE GAS MONITORING INSTRUMENTATION SURVEILLANCE REQUIREMENTS 3/4 3-86 3/4.3.4 DELETED . 3/4 3-89 SHEARON HARRIS - UNIT 1 Vi Amendment No. 65

INSTRUMENTATION SEISMIC INSTRUMENTATION pg/le ~

LIMITING FOR OPERATION

.3.3. The seismic monitoring instrumentation shown in Table 3.3-7 shall be 0

APPLICABILITY: At al 1 times.

ACTION:

With one or more of the above required seismic monitoring instruments inoperable for more than 30 days, prepare and submit a Special Report to the Commission pursuant to Specification 6.9.2 within the next 10 days outlining the cause of the malf'unction and the plans for restoring the instrument(s) to OPERABLE status.

The provisions of Specification 3.0.3 are not applicable.

SURVEILLANCE REQUIREMENTS 4.3.3.3.1 Each of the above required seismic monitoring instruments shall be demonstrated OPERABLE by the performance of the CHANNEL CHECK, CHANNEL CALIBRATION, and an ANALOG CHANNEL OPERATIONAL TEST at the frequencies shown in Table 4.3-4.

4.3.3.3.2 Each of the above required seismic monitoring instruments actuated during a seismic event greater than or equal to 0.01 g shall be restored to OPERABLE status within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months and a CHANNEL CALIBRATION performed within 10 days following the seismic event. Data shall be retrieved from actuated instruments and analyzed to determine the magnitude of the vibratory ground motion. A Special Report shall be prepared and submitted to the Commission pursuant to Specification 6.9.2 within 14 days describing the magnitude, frequency spectrum. and resultant effect upon facility features important to safety.

SHEARON HARRIS - UNIT 1 3/4 3-57 Amendment No. 84

TABLE 3.3-7 SEISMIC MONITORING INSTRUMENTATION MINIMUM MEASUREMENT INSTRUMENTS INSTRUMENTS AND SENSOR LOCATIONS RANGE OPERABLE

1. Triaxial Time-History Accelerographs

a. Containment Mat (El 221 ft) 0.01-1.0 g

b. Containment (El 286 ft) 0.01-1.0 g

c. Diesel Fuel Oil Storage Tank 0.01-1.0 g Building (El 242 ft)

2. Triaxial Peak Accelerograph Recorders

a. Reactor Coolant Pipe (Loop B) +10 g

b. Steam Generator lA Pedestal + 2g (El 238 ft)

c. Reactor Auxiliary Building +10 g (El 236 ft)

3. Triaxial Seismic Switches

a. Starter Unit for Time History 0.005 - 0.05 Accelerograph System--Containment Mat (El 221 ft)

b. Triaxial Seismic Switch--Containment 0.025 - 0.25 Mat (El 221 ft)

4. Triaxial Response-Spectrum Recorders

a. Steam Generator 18 Pedestal + 2g (El 238 ft)

b. Reactor Auxiliary Building + 2g (El 216 ft)

c. Diesel Fuel Oil Storage Tank Building + 2 g (E1 242 ft)

d. Containment Building (El 221 ft) + 2 g With main control room indication.

"With main control room recording.

SHEARON HARRIS - UNIT 1 3/4 3-58 Amendment No. 66

TABLE 4.3-4 Ml+

SEISMIC MONITORING INSTRUMENTATION SURVEILLANCE RE UIREMENTS ANALOG CHANNEL CHANNEL CHANNEL OPERATIONAL INSTRUMENTS AND SENSOR LOCATIONS CHECK CALIBRATION TEST

1. Triaxial Time-History Accelerographs

a. Containment Mat (El 221 ft) SA

b. Containment (El 286 ft) M SA

c. Diesel Fuel Oil Storage Tank Building M SA (El 242 ft)

2. Triaxial Peak Accelerograph Recorders a.. Reactor Coolant Pipe (Loop B) N.A. N.A.

b. Steam Generator lA Pedestal (El 238 ft) N.A. N.A.

c. Reactor Auxiliary Building (El 236 ft) N.A. N.A.

3. Triaxial Seismic Switches

a. Starter Unit for Time History Accelerograph System--Containment SA Mat (El 221 ft)

b. Triaxial Seismic Switch--Containment M SA Mat (El 221 ft)

4. Triaxial Response-Spectrum Recorders

a. Containment Building (Active) SA (El 221 ft)

b. Steam Generator (Passive) 1B Pedestal N.A. N.A.

c. Reactor Auxiliary Building (Passive) N.A.

(El 216 ft)

d. Diesel Fuel Oil Storage Tank Building N.A. N.A.

(Passive) (El 242 ft)

'Except seismic starter unit.

With main control room alarms.

The bistable trip setpoint need not be determined during the performance of a channel operational test.

- UNIT

~fe,+'mendment SHEARON HARRIS 1 3/4 3-59 No. 66

INSTRUMENTATION METEOROLOGICAL INSTRUMENTATION LIMITING C OR OP RATION

,3.3.4 he meteorological monitoring instrumentation channels shown in Table 3.3-8 shall be OPERABLE.

APPLICABILITY: At al 1 times.

ACTION:

With one or more required meteorological monitoring channels inoperable for more than 7 days, prepare and submit a Special Report to the Commission pursuant to Specification 6.9.2 within the next 10 days outlining the cause of the malfunction and the plans for restoring the channel(s) to OPERABLE status.

b. The provisions of Specification 3.0.3 are not applicable.

SURVEILLANCE REQUIREMENTS 4.3.3.4 Each of the above meteorological monitoring instrumentation channels shall be demonstrated OPERABLE by the performance of the CHANNEL CHECK and CHANNEL CALIBRATION at the frequencies shown in Table 4.3-5.

~rd SHEARON HARRIS - UNIT 1 3/4 3-60 Amendment No. 84

TABLE 3.3-8 METEOROLOGICAL MONITORING INSTRUMENTATION I

MINIMUM INSTRUMENT LOCATION OPERABLE

1. Wind Speed Nominal Elev. 12.5 meters Nominal Elev. 61.4 meters

2. Wind Direction Nominal Elev. 12.5 meters Nominal Elev. 61.4 meters

3. Air Temperature--

Differential Temperature 11.0 meters and 59.9 meters SHEARON HARRIS - UNIT 1 3/4 3-61

TARLE 4.3-5 ek METEOROLOGICAL MONITO ING INSTRUMENTATION SURVEILLANCE RE UIREMENTS CHANNEL CHANNEL INSTRUMENT CHECK CALIBRATION

1. Wind Speed

a. Nominal Elev. 12.5 meters SA

b. Nominal Elev. 61.4 meters SA

2. Wind Direction

a. Nominal Elev. 12.5 meters SA

b. Nominal Elev. 61.4 meters SA

3. Differential Air Temperature Between 11.0 meters and 59.9 meters SA SHEARON HARRIS - UNIT 1 3/4 3-62

INSTRUMENTATION METAL IMPACT MONITORING SYSTEM LIMITING CONDITION FOR OPERATION 3.3.3.9 e Metal Impact Monitoring System shall be OPERABLE.

APPLICABILITY: MODES 1 and 2.

ACTION:

a. With one or more Metal Impact Monitoring System channels inoperable for more than 30 days, prepare and submit a Special Report to the Commission pursuant to Specification 6.9.2 within the next 10 days outlining the cause of the malfunction and the plans for restoring the channel(s) to OPERABLE status.

b. The provisions of Specification 3.0.3 are not applicable.

SURVEILLANCE REQUIREMENTS 4.3.3.9 Each channel of the Metal Impact Monitoring System shall be demonstrated OPERABLE by performance oi:

a. A CHANNEL CHECK at least once per 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months ,

b. An ANALOG CHANNEL OPERATIONAL TEST, except for verification of setpoint, at least once per 31 days, and

c. A CHANNEL CALIBRATION at least once per 18 months.

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SHEARON HARRIS - UNIT 1 3/4 3-74 Amendment No. 84

INSTRUMENTATION EXPLOSIVE GAS MONITORING INSTRUMENTATION LIMITING CO ITION FOR OPERATION

~)a+ed -6 3.3.3. 118 The explosive gas monitoring instrumentation channels shown in Table s all be OPERABLE with their Alarm/Trip Setpoints set to ensure that the limits of Specification 3. 11.2.5 are not exceeded.

APPLICABILITY: As shown in Table 3.3-13.

ACTION:

a. With an explosive gas effluent monitoring instrumentation channel Alarm/Trip Setpoint less conservative than required by the above specification declare the channel inoperable and take the ACTION shown in Table 3.3-13.

b. With the number of OPERABLE explosive gas monitoring instrumentation channels less than the Minimum Channels OPERABLE, take the ACTION shown in Table 3.3-13. Restore the inoperable instrumentation to OPERABLE status within 30 days, and if unsuccessful, prepare and submit a Special Report to the Commission pursuant to Specification 6.9.2 to explain why this inoperability was not corrected in a timely manner.

c. The provisions of Specification 3.0.3 are not applicable.

SURVEILLANCE RE UIREMENTS 4.3.3. 11 Each explosive gas monitoring instrumentation channel shall be demonstrated OPERABLE by performance of the CHANNEL CHECK, CHANNEL CALIBRATION and ANALOG CHANNEL OPERATIONAL TEST at the frequencies shown in Table 4.3-9.

" Note: The radioactive gaseous effluent monitoring portions of Specification 3/4.3.3. 11 have been deleted from Technical Specifications and have been relocated to the ODCM.

SHEARON HARRIS - UNIT 1 3/4 3-82 Amendment No. 84

TARLE 3.3-13

~rW EXPLOSIVE GAS MONITORING INSTRUMENTATION MINIMUM CHANNELS INSTRUMENT OPERABLE APPLICABILITY ACTION

1. GASEOUS WASTE PROCESSING SYSTEM--HYDROGEN AND OXYGEN ANALYZERS

a. Recombiner Outlet Hydrogen Monitor 1/recombiner 50

b. Recombiner Outlet Oxygen Monitor 1/recombiner 48

c. Compressor Discharge Oxygen Monitor 1 48 Sav~4"ncaa(4.

z[q p-)) an )~(g zigg p

Page 3/4 3-84 has been deleted.

SHEARON HARRIS - UNIT 1 3/4 3-83 Amendment No. 58

p(g (p TABLE 3.3-13 Continued TABLE NOTATIONS

During GASEOUS WASTE PROCESSING SYSTEM operation ACTION STATEMENTS ACTION 45 (NOT USED)

ACTION 46 (NOT USED)

ACTION 47- (NOT USED)

ACTION 48 With the number of channels OPERABLE less than the Minimum Channels OPERABLE requirement, operation may continue provided grab samples are taken and analyzed at least once per 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months during degassing operations and at least once per 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months during other operations.

ACTION 49 (NOT USED)

ACTION 50 With the number of channels OPERABLE one less than required by the Minimum Channels OPERABLE requirement, suspend oxygen supply to the recombiner.

ACTION 51 (NOT USED)

ACTION 52 (NOT USED)

SHEARON HARRIS - UNIT 1 3/4 3-85 Amendment No. 58

TABLE 4.3-9 EXPLOSIVE GAS MONITORING INSTRUMENTATION SURVEILLANCE RE UIREMENTS ANALOG I CHANNEL MODES FOR WHICH CHANNEL CHANNEL OPERATIONAL SURVEILLANCE INSTRUMENT CHECK CALIBRATION TEST

1. GASEOUS WASTE PROCESSING SYSTEM--

HYDROGEN AND OXYGEN ANALYZERS

a. Recombiner Outlet Hydrogen Q(4)

Monitor

b. Recombiner Outlet Oxygen Q(5)

Monitor

c. Compressor Discharge Oxygen Monitor 9

r C, 0

I Q oo Mg

J II JI

TABLE 4.3-9 Continued TABLE NOTATIONS

During GASEOUS WASTE PROCESSING SYSTEH operation.

(1) (NOT USED)

(2) (NOT USED)

(3) (NOT USED)

(4) The CHANNEL CALIBRATION shall include the use of standard gas samples containing hydrogen and nitrogen.

(5) The CHANNEL CALIBRATION shall include the use of standard gas samples containing oxygen and nitrogen.

SHEARON HARRIS - UNIT 1 3/4 3-88 Amendment No. 58

RADIOACTIVE EFFLUENTS EXPLOSIVE GAS MIXTURE LIMITING CONDITION FOR OPERATION 3.11.2.5 The concentration of oxygen in the GASEOUS RADWASTE TREATMENT SYSTEM downstream of the hydrogen recombiners shall be limited to less than or equal to 2X by volume whenever the hydrogen concentration exceeds 4X by volume.

APPLICABILITY: At al 1 times.

ACTION:

With the concentration of oxygen in the GASEOUS RADWASTE TREATMENT SYSTEM downstream of the hydrogen recombiners greater than 2X by volume but less than or equal to 4X by volume, reduce the oxygen concentration to the above limits within 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months .

With the concentration of oxygen in the GASEOUS RADWASTE TREATMENT SYSTEM downstream of the hydrogen recombiners greater than 4X by volume and the hydrogen concentration greater than 4X by volume, immediately suspend all additions of waste gases to the system and reduce the concentration of oxygen to less than or equal to 4X by volume, then take ACTION a., above.

The provisions of Specification 3.0.3 are not applicable.

SURVEILLANCE REQUIREMENTS

4. 11.2.5 The concentrations of hydrogen and oxygen in the GASEOUS RADWASTE TREATMENT SYSTEM shall be determined to be within the above limits by monitoring, at least once er 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months . the waste gases in the GASEOU AST TMENT SY wit the y rogen an oxygen mono ors required OPERABLE by Ta le 3.3-13 of Specification 3.3.3. 11.

SHEARON HARRIS - UNIT 1 3/4 11-15 Amendment No. 84

INSTRUMENTATION BASES, 3/4.3.3.2 MOVABLE INCORE DETECTORS - DELETED Ze [c+

3/4.3.3.3 EISMIC INSTRUMENT TIO Ml<&

The OPERABILITY of the seismic instrumentation ensures that sufficient capability is available to promptly determine the magnitude of a seismic event and evaluate the response of those features important to safety. This capability is required to permit comparison of the measured response to that used in the design basis for the facility to determine if plant shutdown is required pursuant to Appendix A of 10 CFR Part 100. The instrumentation is consistent with the recommendations of Regulatory Guide 1. 12, "Instrumentation for Earthquakes," April 1974.

&(4 3/4 3 ETEO A NSTRUMENTATIO -he./CA'4 The OPERABILITY of the meteorological instrumentation ensures that sufficient meteorological data are available for estimating potential radiation doses to the public as a result of routine or accidental release of radioactive materials to the atmosphere. This capability is required to evaluate the need for initiating protective measures to protect the health and safety of the public and is consistent with the recommendations of Regulatory Guide 1.23, "Onsite Meteorological Programs," February 1972.

3/4.3.3.5 REMOTE SHUTDOWN SYSTEM The OPERABILITY of the Remote Shutdown System ensures that sufficient capability is available to permit safe shutdown of the facility irom locations outside of the control room. This capability is required in the event control room habitability is lost and is consistent with General Design Criterion 19 of 10 CFR Part 50.

The OPERABILITY of the Remote Shutdown System ensures that a fire will not preclude achieving safe shutdown. The Remote Shutdown System instrumentation, control, and power circuits and transfer switches necessary to eliminate etfects of the fire and allow operation of instrumentation, control and power circuits required to achieve and maintain a safe shutdown condition are independent of areas where a fire could damage systems normally used to shut down the reactor.

p~(eW SHEARON HARRIS - UNIT 1 B 3/4 3-4 Amendment No. 65

' ' INSTRUMENTATION BASES REMOTE SHUTDOWN SYSTEM Continued This capability is consistent with General Design Criterion 3 and Appendix R to 10 CFR Part 50.

3/4.3.3. 6 ACCIDENT MONITORING INSTRUMENTATION The OPERABILITY of the accident monitoring instrumentation ensures that suffi-cient information is available on selected plant parameters to monitor and assess these variables following an accident. This capability is consistent with the recommendations of Regulatory Guide 1.97, Revision 3.

"Instrumentation for Light-Water-Cooled Nuclear Power Plants to Assess Plant Conditions During and Following an Accident." Hay 1983 and NUREG-0737, "Clarification of THI Action Plan Requirements," November 1980.

3/4.3.3.7 DELETED 3/4.3.3.8 DELETED 3/4.3.3.9 M TORING YSTE ke.felid The OPERABILITY of the Metal Impact Monitoring System ensures that sufficient capability is available to detect loose metallic parts in the Reactor System and avoid or mitigate damage to Reactor System components. The allowable out-of-service times and surveillance requirements are consistent with the recom-mendations of Regulatory Guide 1. 133, "Loose-Part Detection Program for the Primary System of Light-Water-Cooled Reactors," Hay 1981.

3/4.3.3. 10 DELETED

~((W SHEARON HARRIS - UNIT 1 B 3/4 3-5 Amendment No. 58

INSTRUMENTATION BASES 3/4 3 3 11 EXPLOSIVE GAS MONITORING INSTRUMENTATION This instrumentation provides for monitoring and controlling the concentrations of potentially explosive gas mixtures in the GASEOUS RADWASTE TREATMENT SYSTEM. The OPERABILITY and use of this instrumentation is consistent with the requirements of General Design Criteria 60, 63, and 64 of Appendix A to 10 CFR Part 50. I 3/4.3.4 DELETED SHEARON HARRIS - UNIT 1 8 3/4 3-6 Amendment No. 58

LIMITING CONDITIONS FOR OPERATION AND SURVEILLANCE REQUIREMENTS SECTION PAGE TABLE 3.3-6 RADIATION MONITORING INSTRUMENTATION FOR PLANT OPERATIONS 3/4 3-51 TABLE 4.3-3 RADIATION MONITORING INSTRUMENTATION FOR PLANT OPERATIONS SURVEILLANCE REQUIREMENTS 3/4 3-54 (Deleted) . . . . . . . . . . . . . . . . . . . . 3/4 3-56 (Deleted) . . . . . . . . . . . . . . . . . . . . 3/4 3-57 f TABLE 3.3-7 (DELETED) 3/4 3-58 I TABLE 4.3-4 (DELETED) 3/4 3-59 /

(Deleted) . . . . . . . . . . . . . . . . . . . . 3/4 3-60 I TABLE 3.3-8 (DELETED) . 3/4 3-61 I TABLE 4.3-5 (DELETED) 3/4 3-62 I Remote Shutdown System 3/4 3-63 TABLE 3.3-9 REMOTE SHUTDOWN SYSTEM 3/4 3-64 TABLE 4.3-6 REMOTE SHUTDOWN MONITORING INSTRUMENTATION SURVEILLANCE REQUIREMENTS . 3/4 3-65 Accident Monitoring Instrumentation . . . . . . . 3/4 3-66 TABLE 3.3-10 ACCIDENT MONITORING INSTRUMENTATION . 3/4 3-68 TABLE 4.3-7 ACCIDENT MONITORING INSTRUMENTATION SURVEILLANCE REQUIREMENTS 3/4 3-70 TABLE 3.3-11 (DELETED) 3/4 3-73 (Deleted) 3/4 3-74 [

(Deleted) 3/4 3-75 (Deleted) 3/4 3-82 I TABLE 3.3-13 (DELETED) 3/4 3-83 I TABLE 4.3-9 (DELETED) 3/4 3-86 I 3/4.3.4 (Deleted) 3/4 3-89 SHEARON HARRIS - UNIT 1 V1 Amendment No.

INSTRUMENTATION SEISMIC INSTRUMENTATION LIMITING CONDITION FOR OPERATION 3.3.3.3 Deleted SHEARON HARRIS - UNIT 1 3/4 3-57 Amendment No.

TABLE 3.3-7 De1eted SHEARON HARRIS - UNIT 1 3/4 3-58 Amendment No.

TABLE 4.3-4 Oeleted SHEARON HARRIS - UNIT 1 3/4 3-59 Amendment No.

INSTRUMENTATION METEOROLOGICAL INSTRUMENTATION L IMITING CONDITION FOR OPERATION 3.3.3.4 Deleted SHEARON HARRIS - UNIT 1 3/4 3-60 Amendment No.

~ ~Pl i

TABLE 3.3-8 Deleted SHEARON HARRIS - UNIT 1 3/4 3-61 Amendment No.

~ g ~

~ lit, TABLE 4.3-5 Deleted SHEARON HARRIS - UNIT 1 3/4 3-62 Amendment No.

INSTRUMENTATION METAL IMPACT MONITORING SYSTEM LIMITING CONDITION FOR OPERATION 3.3.3.9 Deleted SHEARON HARRIS - UNIT 1 3/4 3-74 Amendment No.

INSTRUMENTATION EXPLOSIVE GAS MONITORING INSTRUMENTATION LIMITING CONDITION FOR OPERATION 3.3.3.11 Deleted SHEARON HARRIS - UNIT 1 3/4 3-82 Amendment No.

TABLE 3.3-13 Deleted Pages 3/4 3-84 and 3/4 3-85 have been deleted.

SHEARON HARRIS - UNIT 1 3/4 3-83 Amendment No.

TABLE 4.3-9 Deleted Pages 3/4 3-87 and 3/4 3-88 have been deleted.

SHEARON HARRIS - UNIT 1. 3/4 3-86 Amendment No.

' " RADIOACTIVE EFFLUENTS EXPLOSIVE GAS MIXTURE LIMITING CONDITION FOR OPERATION

3. 11.2.5 The concentration of oxygen in the GASEOUS RADWASTE TREATMENT SYSTEM downstream of the hydrogen recombiners shall be limited to less than or equal to 2X by volume whenever the hydrogen concentration exceeds 4X by volume.

APPLICABILITY: At al 1 times.

ACTION:

a. With the concentration of oxygen in the GASEOUS RADWASTE TREATMENT SYSTEM downstream of the hydrogen recombiners greater than 2X by volume but less than or equal to 4X by volume, reduce the oxygen concentration to the above limits within 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months .

b. With the concentration of oxygen in the GASEOUS RADWASTE TREATMENT SYSTEM downstream of the hydrogen recombiners greater than 4X by volume and the hydrogen concentration greater than 4l by volume, immediately suspend all additions of waste gases to the system and reduce the concentration of oxygen to less than or equal to 4X by volume, then take ACTION a., above.

c. The provisions of Specification 3.0.3 are not applicable.

SURVEILLANCE REQUIREMENTS

4. 11.2.5 The concentrations of hydrogen and oxygen in the GASEOUS RADWASTE TREATMENT SYSTEM shall be determined to be within the above limits by monitoring, at least once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months , the waste gases in the GASEOUS RADWASTE TREATMENT SYSTEM.

SHEARON HARRIS - UNIT 1 3/4 11-15 Amendment No.

INSTRUMENTATION BASES .

3/4.3.3.2 MOVABLE INCORE DETECTORS - DELETED 3/4.3.3.3 DELETED 3/4.3.3.4 DELETED 3/4.3.3.5 REMOTE SHUTDOWN SYSTEM The OPERABILITY of the Remote Shutdown System ensures that sufficient capability is available to permit safe shutdown of the facility from locations outside of the control room. This capability is required in the event control room habitability is lost and is consistent with General Design Criterion 19 of 10 CFR Part 50.

The OPERABILITY of the Remote Shutdown System ensures that a fire will not preclude achieving safe shutdown. The Remote Shutdown System instrumentation, control, and power circuits and transfer switches necessary to eliminate effects of the fire and allow operation of instrumentation, control and power circuits required to achieve and maintain a safe shutdown condition are independent of areas where a fire could damage systems normally used to shut down the reactor.

SHEARON HARRIS - UNIT 1 8 3/4 3-4 Amendment No.

INSTRUMENTATION BASES .

REMOTE SHUTDOWN SYSTEM Continued This capability is consistent with General Design Criterion 3 and Appendix R to 10 CFR Part 50.

3/4.3.3. 6 ACCIDENT MONITORING INSTRUMENTATION The OPERABILITY of the accident monitoring instrumentation ensures that suffi-cient information is available on selected plant parameters to monitor and assess these variables following an accident. This capability is consistent with the recommendations of Regulatory Guide 1.97, Revision 3, "Instrumentation for Light-Water-Cooled Nuclear Power Plants to Assess Plant Conditions During and Following an Accident," May 1983 and'NUREG-0737, "Clarification of TMI Action Plan Requirements," November 1980.

3/4.3.3.7 DELETED 3/4.3.3.8 DELETED 3/4.3.3.9 DELETED 3/4.3.3. 10 DELETED SHEARON HARRIS - UNIT 1 B 3/4 3-5 Amendment No.

INSTRUMENTATION BASES 3/4.3.3. 11 DELETED 3/4.3.4 DELETED SHEARON HARRIS - UNIT 1 B 3/4 3-6 Amendment No.

~y)gggdD Distri10.txt Distribution Sheet Priority: Normal From: Elaine Walker Action Recipients: Copies:

Internal Recipients:

FiLE.GENTLER D1 Paper Copy External Recipients:

NOAC Paper Copy Total Copies:

Item: ADAMS Document Library: ML ADAMS"HQNTAD01 ID: 003692943

Subject:

Harris, Exemption, EP Exercise Schedule Body:

ADAMS DISTRIBUTION NOTIFICATION.

Electronic Recipients can RIGHT CLICK and OPEN the first Attachment to View the Document in ADAMS. The Document may also be viewed by searching for Accession Number ML003692943.

DF01 - Direct Flow Distribution: 50 Docket (PDR Avail)

Docket: 05000400 Page 1

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i6, ~~+ Mr~~a 4%4odB~VPZ Mr. James Scarola, Vice F resident March 2000 '@r Shearon Harris Nuclear Power Plant Carolina Power 8 Light Company

.,Post Qffice Box 165, Mail Code: Zone 1 New Hill, North Carolina 27562-0165

SUBJECT:

EXEMPTION FOR EMERGENCY PREPAREDNESS EXERCISE SCHEDULE-SHEARON HARRIS NUCLEAR POWER PLANT, UNIT 1 (TAC NO. MA7384)

Dear Mr. Scarola:

By letter dated December 7, 1999, you requested a one-time exemption from the requirements of Title 10 of the Code of Federal Regulations (10 CFR) Part 50, Appendix E, Sections IV.F.2.b.

and c. to conduct a full participation exercise of the onsite and offsite emergency plans every 2 years. SpeciTically, you requested to reschedule the Harris Nuclear Plant exercise originally scheduled for September 21, 1999, and complete the onsite and offsite exercise requirements in two parts.

The staff notes that unforseen circumstances associated with Hurricane Floyd led to the postponement of the originally scheduled exercise. The staff also notes that before submitting the exemption request, you had ongoing discussions with the State and local governments to try to reschedule the exercise before the end of 1999, so that an exemption would not be required.

The staff has completed its review of your request for exemption and determined that the exemption would provide only temporary relief from the applicable regulation and that you made good faith efforts to comply with the regulation. Accordingly, the exemption is granted in accordance with 10 CFR 50.12(a)(2)(v).

A copy of the Exemption is being forwarded to the Office of the Federal~Re ister for publication.

Sincerely,

/IIA/

Richard J. Laufer, Project Manager, Section 2 Project Directorate II Division of Licensing Project Management

,Office of Nuclear Reactor Regulation Docket No. 50-400

Enclosure:

Exemption cc w/encl: See next page DISTRIBUTION:

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e UNITED STATES NUCLEAR REGULATORY COMMISSION f) <<f>' WASHINGTON, D.C. 20555-0001

.'Jllilll March 16, 2000 J/PKIIS Mr. James Scarola, Vice President Shearon Harris Nuclear Power Plant Carolina Power 8 Light Company Post Office Box 165, Mail Code: Zone 1 New Hill, North Carolina 27562-0165

SUBJECT:

EXEMPTION FOR EMERGENCY PREPAREDNESS EXERCISE SCHEDULE-SHEARON HARRIS NUCLEAR POWER PLANT, UNIT 1 (TAC NO. MA7384)

Dear Mr. Scarola:

By letter dated December 7, 1999, you requested a one-time exemption from the requirements of Title 10 of the Code of Federal Regulations (10 CFR) Part 50, Appendix E, Sections IV.F.2.b.

and c. to conduct a full participation exercise of the onsite and offsite emergency plans every 2 years. Specifically, you requested to reschedule the Harris Nuclear Plant exercise originally scheduled for September 21, 1999, and complete the onsite and offsite exercise requirements in two parts.

The staff notes that unforseen circumstances associated with Hurricane Floyd led to the postponement of the originally scheduled exercise. The staff'also notes that before submitting the exemption request, you had ongoing discussions with the State and local governments to try to reschedule the exercise before the end of 1999, so that an exemption would not be required.

The staff has completed its review of your request for exemption and determined that the exemption would provide only temporary relief from the applicable regulation and that you made good faith efforts to comply with the regulation. Accordingly, the exemption is granted in accordance with 10 CFR 50.12(a)(2)(v).

A copy of the Exemption is being forwarded to the Office of the Federal Reciister for publication.

Sincerely,

<~ J-Richard J. Laufer, roj ct Manager, Section 2 Project Directorate II Division of Licensing Project Management Office of Nuclear Reactor Regulation Docket No. 50-400

Enclosure:

Exemption ccw/encl: See next page

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7590-01-P UNITED STATES OF AMERICA NUCLEAR REG LATORY COMMISSION In the matter of )

)

Carolina Power 8 Light Company ) Docket No. 50400

)

(Shearon Harris Nuclear Power Plant, )

Unit 1) )

EXEMPTION Carolina Power 8 Light Company (CP8L or the licensee) is the holder of Facility Operating License No. NPF-63, which authorizes operation of the Shearon Harris. Nuclear Power Plant, Unit 1 (HNP) at power levels not to exceed 2775 megawatts thermal. The facility consists of one pressurized-water reactor located at the licensee's site in Wake and Chatham Counties, North Carolina. The license provides,,among other things, that the licensee is subject to all rules, regulations, and orders of the Nuclear Regulatory Commission (NRC, the Commission) now or hereafter in effect.

Section IV.F.2.b of Appendix E to Title 10 of the Code of Federal Regulations (10 CFR)

Part 50 requires each licensee at each site to conduct an exercise of its onsite emergency plan every 2 years and indicates the exercise may be included in the full-participation biennial exercise required by paragraph 2.c. Paragraph 2.c requires offsite plans for each site to be

exercised biennially with full participation by each offsite authority having a role under the plan.

~

I During such biennial full-participation exercises, the NRC evaluates onsite emergency preparedness activities and the Federal Emergency Management Agency (FEMA) evaluates offsite emergency preparedness activities. CP8L successfully conducted a full-participation exercise for HNP during the week of October 7, 1997. By letter dated December 7, 1999, the licensee requested an exemption from Sections IV.F.2.b and c of Appendix E regarding the conduct of a full-participation exercise originally scheduled for September 21, 1999.

Specifically, the licensee proposed rescheduling the exercise originally scheduled for September 21, 1999, and completing the onsite and offsite exercise requirements in two parts.

The licensee would use the onsite.exercise conducted on January 11, 2000, without the participation of the State of North Carolina and local government response agencies, to meet the onsite requirement. The offsite portion of the exercise would be conducted on June 27, 2000, with the participation of the State of North Carolina and local government response agencies.

The Commission, pursuant to 10 CFR 50.12(a)(1), may grant exemptions from the requirements of 10 CFR Part 50 that are authorized by law, will not present an undue risk to public health and safety, and are consistent with the common defense and security. The Commission, however, pursuant to 10 CFR 50.12(a)(2), will not consider granting an exemption unless special circumstances are present. Under 10 CFR 50.12(a)(2)(v), special circumstances are present whenever the exemption would provide only temporary relief from the applicable regulation and the licensee or applicant has made good faith efforts to comply h

with the regulation.

The licensee requests a one-time change in the schedule for the next full-participation exercise for HNP. Subsequent full-participation exercises for HNP would be scheduled at no greater than 2-year intervals in accordance with 10 CFR Part 50, Appendix E, Section IV.F.2.c.

Accordingly, the exemption would provide only temporary relief from that regulation.

As indicated in the licensee's request for an exemption of December 7, 1999, the licensee had originally scheduled a full-participation exercise for September 21, 1999. As further set forth in that letter, however, due to the significant impact and damage from hurricane "Floyd," the State of North Carolina and the local emergency response agencies were occupied with responding to the natural disaster and were unable to participate in and could not support the exercise. In discussions on September 14, 1999, the NRC and FEMA indicated concurrence with rescheduling the exercise due to preparations and response to hurricane "Floyd." In a letter dated January 19, 2000, FEMA documented its support for rescheduling the exercise.

Accordingly, the licensee made a good faith effort to comply with the schedule requirements of Appendix E for full-participation exercises.

The staff completed its evaluation of the licensee's request for an exemption. The staff, having considered the schedule and resource issues resulting from responding to hurricane "Floyd" and the subsequent flooding, and the fact that the licensee conducted the onsite portion of the exercise on January 11, 2000, only 3 months beyond the required interval, finds the Y

request acceptable.

IV.

The Commission has determined that, pursuant to 10 CFR Part 50, Appendix E, this exemption is authorized by law, will not endanger life or property or the common defense and

~ I I 4-security, and is otherwise in the public interest. Further, the Commission has determined, pursuant to 10 CFR 50.12(a), that special circumstances of 10 CFR 50.12(a)(v) are applicable in that the exemption would provide only temporary relief from the applicable regulation and the licensee has made good faith efforts to comply with the regulation. Therefore, the Commission hereby grants the exemption from Section IV.F.2.b and c of Appendix E to 10 CFR Part 50.

Pursuant to 10 CFR 51.32, the Commission has determined that the granting of this exemption will have no significant impact on the quality of the human environment (65 FR 14322).

This exemption is effective upon issuance.

Dated at Rockville, Maryland, this ~g~ day of ~eh 2000.

FOR THE NUCLEAR REGULATORY COMMISSION John . Zwolinski, Director Division of Licensing Project Management Office of Nuclear Reactor Regulation

Y I ~ 0

Mr. James Scarola Shearon Nuclear Power Plant Carolina Power 8 Light Company Unit 1 cc:

Mr. William D. Johnson Chris L. Burton Vice President and Corporate Secretary Director of Site Operations Carolina Power 8 Light Company Carolina Power 8 Light Company Post Office Box 1551 Shearon Harris Nuclear Power Plant Raleigh, North Carolina 27602 Post Office Box 165, MC: Zone 1 New Hill, North Carolina 27562-0165 Resident Inspector/Harris NPS c/o U.S. Nuclear Regulatory Commission Mr. Robert P. Gruber 5421 Shearon Harris Road Executive Director New Hill, North Carolina 27562-9998 Public Staff NCUC Post Office Box 29520 Ms. Karen E. Long Raleigh, North Carolina 27626 Assistant Attorney General State of North Carolina Chairman of the North Carolina Post Office Box 629 Utilities Commission Raleigh, North Carolina 27602 Post Office Box 29510 Raleigh, North Carolina 27626-0510 Public Service Commission State of South Carolina Post Office Drawer Columbia, South Carolina 29211 Mr. Vernon Malone, Chairman Board of County Commissioners of Wake County, P. O. Box 550 Mr. Mel Fry, Director Raleigh, North Carolina 27602 Division of Radiation Protection N.C. Department of Environment and Natural Resources-3825 Barrett Dr. Mr. Richard H. Givens, Chairman Raleigh, North Carolina 27609-7721 Board of County Commissioners of Chatham County P. O. Box 87 Mr. Terry C. Morton Pittsboro, North Carolina 27312 Manager Performance Evaluation and Ms. Donna B. Alexander, Manager Regulatory Affairs CPB 7 Regulatory Affairs Carolina Power 8 Light Company Carolina Power & Light Company Post Office Box 1551 Shearon Harris Nuclear Power Plant Raleigh, North Carolina 27602-1551 P.O. Box 165, Mail Zone 1 New Hill, NC 27562-0165 Mr. Robert J. Duncan II 20037-1128'r.

Plant General Manager Carolina Power & Light Company Shearon Harris Nuclear Power Plant Mr. Johnny H. Eads, Supervisor Licensing/Regulatory Programs Carolina Power 8 Light Company P.O. Box 165, Mail Zone 3 Shearon Harris Nuclear Power Plant New Hill, North Carolina 27562-0165 P. O. Box165, Mail Zone 1 New Hill, NC 27562-0165 Mr. John H. O'eill, Jr.

Shaw, Pittman, Potts 8 Trowbridge 2300 N Street, NW.

Washington, DC

y/yy/~so Distri42.txt

~

Distribution Sheet Priority: Normal From: Elaine Walker Action Recipients: Copies:

Inter eoipi CENTE 01 Paper Copy External Recipients:

NOAC Paper Copy Total Copies:

Item: ADAMS Document Library: ML ADAMS"HQNTAD01 ID: 003692439

Subject:

Harris, Relief, reactor vessel shell-to-flange weld examination, MA7886 Body:

ADAMS DISTRIBUTION NOTIFICATION.

Electronic Recipients can RIGHT CLICK and OPEN the first Attachment to View the Document in ADAMS. The Document may also be viewed by searching for Accession Number ML003692439.

DF01 - Direct Flow Distribution: 50 Docket (PDR Avail)

Docket: 05000400 Page 1

0 1

]3c~i~ 4- M4oENM l39 Mr. James Scarola, Vice ident March 16, "2000 Shearon Harris Nuclear Po er Plant eM." 628 Carolina Power 8 Light Company Post Office Box 165, Mail Code: Zone 1 New Hill, North Carolina 27562-0165 I

SUBJECT:

EVALUATIONOF ASME SECTION XI INSERVICE INSPECTION RELIEF REQUEST 2R1-013 - SHEARON HARRIS NUCLEAR POWER PLANT (TAC NO. MA7886)

Dear Mr. Scarola:

By letter dated December 20, 1999, you submitted relief request 2R1-013 for relief from certain requirements of the 1989 Edition of the American Society of Mechanical Engineers (ASME)

Code,Section XI for the Harris Nuclear Plant (HNP). Specifically, you requested relief from performing at least 50% of the reactor vessel shell-to-flange weld examination by the end of the first inspection period, and requested relief to use ASME Code Case N-623 for 100% deferral of the shell-to-flange'weld examination to the end of the inservice inspection (ISI) interval.

The staff has reviewed and evaluated your request as documented in the enclosed Safety Evaluation. The staff has determined that the proposed alternative to use Code Case N-623 for the reactor vessel shell-to-flange weld examination provides an acceptable level of quality and safety. The proposed alternative is authorized pursuant to 10 CFR 50.55a(a)(3)(i) for the second 10-year ISI interval at HNP until such time as Code Case N-623 is incorporated into a future revision of Regulatory Guide (RG) 1.147. Upon issuance of the RG, you shall follow all provisions in Code Case N-623, including any exceptions or limitations discussed in the RG.

Sincerely,

/m/

Richard P. Correia, Chief, Section 2 Project Directorate II Division of Licensing Project Management Office of Nuclear Reactor Regulation Docket No. 50-400

Enclosure:

Safety Evaluation ~>>>>>>tItP P ) [>> Pg~ggi>>>>" t'I'IIII' cc w/encl: See next page Distribution:

File Center PUBLIC HBerkow BBonser, Rll SPeterson PD II Rdg OGC GHill (2) ACRS FILENAME - G:>>IPDII-2>>>>Harris>>>>RRma7886.wpd

No significant change to SE OFFICE PM:PDII/S2 LA:PDII/S2 EMCB QGG Sc:PDII/S2 NAME RLaufe ED 'n Esullivan

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>> UNITED STATES

NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 March 16, 2000 J/////S Mr. James Scarola, Vice President Shearon Harris Nuclear Power Plant Carolina Power 8 Light Company Post Office Box 165, Mail Code: Zone 1 New Hill, North Carolina 27562-0165

SUBJECT:

EVALUATIONOF ASME SECTION XI INSERVICE INSPECTION RELIEF REQUEST 2R1-013 - SHEARON HARRIS NUCLEAR POWER PLANT (TAC NO. MA7886)

Dear Mr. Scarola:

By letter dated December 20, 1999, you submitted relief request 2R1-013 for relief from certain requirements of the 1989 Edition of the American Society of Mechanical Engineers (ASME)

Code,Section XI for the Harris Nuclear Plant (HNP). Specifically, you requested relief from performing at least 50% of the reactor vessel shell-to-flange weld examination by'he end of the first inspection period, and requested relief to use ASME Code Case N-623 for 100% deferral of the shell-to-flange weld examination to the end of the inservice inspection (ISI) interval.

The staff has reviewed and evaluated your request as documented in the enclosed Safety Evaluation. The staff has determined that the proposed alternative to use Code Case N-623 for the reactor vessel shell-to-flange weld examination provides an acceptable level of quality and safety. The proposed alternative is authorized pursuant to 10 CFR 50.55a(a)(3)(i) for the second 10-year ISI interval at HNP until such time as Code Case N-623 is incorporated into a future revision of Regulatory Guide (RG) 1.147. Upon issuance of the RG, you shall follow all provisions in Code Case N-623, including any exceptions or limitations discussed in the RG.

Sincerely, Richard P. Correia, Chief, Section 2 Project Directorate II Division of Licensing Project Management Office of Nuclear Reactor Regulation Docket No. 50<00

Enclosure:

Safety Evaluation ccw/encl: See next page

. Mr. James Scarola Shearon Nuclear Power Plant"

'arolina Power 8 Light Company Unit 1 CC:

Mr. Qfilliam D. Johnson Mr. Chris L. Burton Vice President and Corporate Secretary Director of Site Operations Carolina Power & Light Company Carolina Power & Light Company Post Office Box 1551 Shearon Harris Nuclear Power Plant

'Raleigh, North Carolina 27602 Office Box 165, MC: Zone 1 'ost Ne'w Hill, No'rth Carolina 27562-0165 Resident Inspector/Harris NPS c/o U.S. Nuclear Regulatory Commission Mr. Robert P. Gruber 5421 Shearon Harris Road Executive Director New Hill, North Carolina 27562-9998 Public Staff NCUC Post Office Box 29520 Ms. Karen E. Long Raleigh, North Carolina 27626 Assistant Attorney General State of North Carolina Chairman of the North Carolina Post Office Box 629 Utilities Commission Raleigh, North Carolina 27602 Post Office Box 29510 Raleigh, North Carolina 27626-0510 Public Service Commission State of South Carolina Post Office Drawer Columbia, South Carolina 29211 Mr. Vernon Malone, Chairman Board of County Commissioners of Wake County.

P. O. Box 550 Mr. Mel Fry, Director Raleigh, North Carolina 27602 Division of Radiation Protection N.C. Department of Environment and Natural Resources

-3825 Barrett Dr. Mr. Richard H. Givens, Chairman Raleigh, North Carolina 27609-7721 Board of County Commissioners of Chatham County P. O. Box 87 Mr. Terry C. Morton Pittsboro, North Carolina 27312 Manager Performance Evaluation and Ms. Donna B. Alexander, Manager Regulatory Affairs CPB 7 Regulatory Affairs Carolina Power 8 Light Company Carolina Power 8 Light Company Post Office Box 1551 Shearon Harris Nuclear Power Plant Raleigh, North Carolina 27602-1551 P.O. Box 165, Mail Zone 1 New Hill, NC 27562-0165 Mr. Robert J. Duncan II

, Plant General Manager Mr. Johnny H. Eads, Supervisor Carolina Power 8 Light Company Licensing/Regulatory Programs Shearon Harris Nuclear Power Plant Carolina Power 8 Light Company P.O. Box 165, Mail Zone 3 Shearon Harris Nuclear Power Plant New Hill, North Carolina 27562-0165 P. O. Box 165, Mail Zone 1 New Hill, NC 27562-0165 Mr. John H. O'eill, Jr.

Shaw, Pittman, Potts 8 Trowbridge 2300 N Street, NW.

Washington, DC 20037-1128

~

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UNITED STATES y NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 205554001

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~zerux SAFETY EVALUATIONBY THE OFFICE OF NUCLEAR REACTOR REGULATION RELIEF RE UEST 2R1-013 REACTOR VESSEL SHELL-TO-FLANGE WELD CAROLINA POWER 8 LIGHT COMPANY SHEARON HARRIS NUCLEAR POWER PLANT DOCKET NO. 50-400

1.0 INTRODUCTION

By letter dated December 20, 1999, Carolina Power and Light Company (the licensee) submitted a request for relief from the ASME Code Section XI nondestructive examination (NDE) requirements.

2.0 BACKGROUND

Inservice inspection (ISI) of the American Society of Mechanical Engineers (ASME) Code Class 1, 2 and 3 components shall be performed in accordance with Section XI of the ASME Boiler and Pressure Vessel (B&PV) Code and applicable addenda as required by 10 CFR 50.55a(g),

except where specific written relief has been granted by the Commission pursuant to 10 CFR 50.55a(6)(g)(i). 10 CFR 50.55a(a)(3) states that alternatives to the requirements of paragraph (g) may be used, when authorized by the NRC, if (i) the proposed alternatives would provide an acceptable level of quality and safety or (ii) compliance with the specified requirements would result in hardship or unusual difficulty without a compensating increase in the level of quality and safety.

Pursuant to 10 CFR 50.55a(g)(4), ASME Code Class 1, 2 and 3 components (including supports) shall meet the requirements, except the design and access provisions and the preservice examination requirements, set forth in the ASME Code,Section XI, "Rules for Inservice Inspection of Nuclear Power Plant Components," to the extent practical within the limitations of design, geometry, and materials of construction of the components. The regulations require that inservice examination of components and system pressure tests conducted during the first 10-year interval and subsequent intervals comply with the requirements in the latest edition and addenda of Section XI of the ASME Code incorporated by reference in 10 CFR 50.55a(b) twelve months prior to the start of the 120-month interval, subject to the limitations and modifications listed therein. The Code of record for the Shearon Harris Nuclear Power Plant's second 10-year ISI interval is the 1989 Edition of Section XI of the ASME B&PV Code.

3.0 THE COMPONENT FOR WHICH RELIEF IS RE VESTED Class 1 reactor vessel shell-to-flange weld (Category 8-A) 3.1 APPLICABLE CODE REQUIREMENT FROM WHICH RELIEF IS REQUESTED (as stated):

The American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code Section XI, 1989 Edition with no Addenda, Table IWB-2500-1, Examination Category B-A, requires inspection of the reactor vessel shell-to-flange weld. Partial deferral of the volumetric examination is permitted. Notes 3 and 4 in Table IWB-2500-1, Category B-A state, "If partial examinations are conducted from the flange face, the remaining volumetric examinations required to be conducted from the vessel wall may be performed at or near the end of each inspection interval. The examination of shell-to-flange welds may be-performed during the first and third inspection periods in conjunction with the nozzle examinations of Exam. Cat. 8-D (Program B). At least 50%

of the shell-to-flange welds shall be examined by the end of the first inspection period, and the remainder by the end of the third inspection period."

Relief is requested from performing at least 50% of the shell-to-flange weld by the end of the first inspection period. Relief is requested to use ASME Code Case N-623 for 100%

deferral of the shell-to-flange weld examination to the end of the inservice inspection interval.

3.2 LICENSEE'S BASIS FOR REQUESTING RELIEF (as stated):

Pursuant to 10 CFR 50.55a(a)(3)(ii), relief is requested on the basis that compliance with the original examination requirements would result in hardship or unusual difficulty without a compensating increase in the level of quality and safety.

The ASME Code Committee has approved Code Case N-623, "Deferral of Inspections of Shell-to-Flange and Head-to-Flange welds of a Reactor Vessel Section XI, Division 1."

Code Case N-623 provides an alternative to costly and time consuming first period examinations. In Code Case N-623, the ASME Code Committee has stated that the Code Case may be used if the following conditions have been met:

(a) No weld repair/replacement activities have ever been performed on the shell-to-flange or head-to-flange weld.

(b) Neither the shell-to-flange weld nor head-to-flange weld contains identified fiaws or relevant conditions that currently require successive inspections in accordance with IWB-2420(b).

(c) The vessel is not in the first inspection interval ~

The Harris Nuclear Plant (HNP) reactor vessel complies with these requirements.

Therefore, this code case is applicable to HNP.

By performing the reactor vessel shell-to-flange weld examination at the end of the inspection interval, it can be performed with the same automated equipment used to examine the remaining reactor vessel welds. This will provide a significant reduction in radiation exposure and cost associated with performing the examination.

3.3 LICENSEE'S PROPOSED ALTERNATIVEEXAMINATION(as stated):

Code Case N-623 is to be applied to the reactor vessel shell-to-flange weld. The required examination is to be performed at the end of the inspection interval.

3.4 LICENSEE'S TECHNICALJUSTIFICATION FOR RELIEF REQUEST (as stated):

The proposed alternative provides an acceptable level of quality and safety since the shell-to-flange weld will still receive the same high quality examinations that have been required by the ASME Code Section XI since the reactor was placed in commercial service. The only change is that the shell-to-flange weld will be examined at the same time as the remainder of the reactor vessel welds, including the nozzle examinations of Examination Category B-D. Reactor vessel nozzle weld examinations are allowed to be deferred to the end of the interval by Code Case N-521, which is acceptable to the NRC staff for application as stated in NRC Regulatory Guide 1.147, Revision 12, "Inservice Inspection Code Case Acceptability, ASME Section XI, Division 1." No changes are being made to the volumes or areas of material that are examined, nor to the nondestructive examination (NDE) personnel qualifications. This relief request does not involve changes to NDE methods or acceptance criteria.

In addition, the following information should be considered. HNP is currently in the first period of the second inspection interval. The shell-to-flange weld was partially examined, as required, from the flange face during the first period of the first interval.

This exam was conducted again at the end of the first interval in conjunction with the 10-year vessel examination. The weld was examined from the flange face as well as the vessel wall using both Code required techniques and Performance Demonstration Initiative (PDI) techniques. This will allow the examination schedule for this weld not to exceed the length of one inspection interval.

4.0 STAFF EVALUATIONAND CONCLUSION Section XI of the ASME Code, 1989 Edition, Table IWB-2500-1, requires that the reactor pressure vessel (RPV) shell-to-flange weld be volumetrically examined once each inspection interval. The footnotes to Table IWB-2500-1 provide partial deferrals for the subject weld.

Footnote 3 specifies that during the first and second period, the examination may be performed from the flange face, and the remaining volumetric examinations required to be conducted from the vessel wall may be performed at or near the end of the inspection interval. Footnote 4 provides deferral of the shell-to-flange weld stating that the examinations may be performed during the first and third periods, provided at least 50% of the shell-to-flange weld be examined by the end of the first period, and the remainder by the end of the third inspection period.

The licensee proposes to follow the requirements of Code Case N-623 for the reactor vessel shell-to-flange weld. The staff finds the licensee meets the requirements listed in Code Case

'L 4

N-623'and that deferral of the weld examinations to the end of the inspection interval is supported by the operating history of the industry. Industry experience to date indicates that examinations performed on the RPVs'hell-to-flange weld have not identified any detrimental flaws or relevant conditions and that changing the schedule for examining this weld to the end of the licensee's 10-year ISI interval will provide a suitable frequency for verifying the integrity of the subject weld. The subject weld will still receive the same examinations that have been required by the ASME Code Section XI since the reactor was placed in commercial service.

The only change is that the RPV shell-to-flange weld examinations will be deferred to the end of the inspection interval without conducting partial examinations from the flange face earlier in the inspection interval. No changes are being made to the volumes or areas of material that are examined, nor to the NDE personnel qualifications. This relief request does not involve changes to NDE methods or acceptance criteria. In addition, the licensee partially examined the shell-to-flange weld from the flange face during the first period of the first interval, as required. This examination was conducted again at the end of the first interval in conjunction with the.10-year vessel examination. The weld was examined from the flange face as well as the vessel wall using both Code-required techniques and PDI techniques. This allows for the examination schedule for this weld to not exceed the length of one inspection interval.

The staff has determined that the licensee's proposed alternative to use Code Case N-623 for the reactor vessel shell-to-flange weld provides an acceptable level of quality and safety.

Therefore, the licensee's proposed alternative is authorized pursuant to 10 CFR 50.55a(a)(3)(i) for the second 10-year ISI interval at the Shearon Harris Nuclear Power Plant, Unit 1 until such time as Code Case N-623 is incorporated into a future revision of Regulatory Guide (RG) 1.147.

Upon issuance of the RG, the licensee will follow all provisions in Code Case N-623, including any exceptions or limitations discussed in the RG.

Principal Contributor: A. Keim Date: March 16, 2000

/-

g/@au fan Distri86.txt

'istribution Sheet Priority: Normal From: Stefanie Fountain Action Recipients: Copies:

Internal"Recipiente.

FILE CENTER 01 Paper Copy External Recipients:

NOAC Paper Copy Total Copies:

Item: ADAMS Document Library: ML ADAMS"HQNTAD01 ID: 003688908

Subject:

Shearon Harris Nuclear Power Plant, Unit 1 - Evaluation of Generic Letter 95-07 Respon se - (TAC M93469)

Body:

ADAMS DISTRIBUTION NOTIFICATION.

Electronic Recipients can RIGHT CLICK and OPEN the first Attachment to View the Document in ADAMS. The Document may also be viewed by searching for Accession Number ML003688908.

DF01 - Direct Flow Distribution: 50 Docket (PDR Avail)

Docket: 05000400 Page 1

'0 I

'arch 8, 2000 /jCM~lra +~ ~

~a~~ e-Mr. James Scarola, Vice President Shearon Harris Nuclear Power Plant Carolina Power 8 Light Company Post Office Box165, Mail Code: Zone 1 New Hill, North Carolina 27562-0165

SUBJECT:

SHEARON HARRIS NUCLEAR POWER PLANT, UNIT 1 - EVALUATIONOF GENERIC LETTER 95-07 RESPONSE (TAC NO. M93469)

Dear Mr. Scarola:

On August 17, 1995, the NRC issued Generic Letter (GL) 95-07, "Pressure Locking and Thermal Binding of Safety-Related Power-Operated Gate Valves," to request that licensees take actions to ensure that safety-related power-operated gate valves that are susceptible to pressure locking or thermal binding are capable of performing their safety functions.

By letters dated February 13 and August 19, 1996, May 26, 1997, and September 29 and December 30, 1999, Carolina Power 8 Light Company (CP8L) provided its responses to GL 95-07, and to NRC requests for additional information regarding the responses, for the Shearon Harris Nuclear Power Plant (HNP). As discussed in the enclosed Safety Evaluation, the NRC staff has reviewed the submittals and finds that CP8L has adequately addressed the actions requested in GL 95-07 for HNP.

Sincerely,

/RA/

Richard J. Laufer, Project Manager, Section 2 Project Directorate II Division of Licensing Project Management Office of Nuclear Reactor Regulation Docket No. 50-400

Enclosure:

Safety Evaluation ccw/encl: See next page ~R. F15 $~$ 7ipg @)p Distribution

'ile Center'D PUBLIC HBerkow STingen II-2 Rdg OGC ACRS BBonser, Rll FILENAME - G:)PDII-2>HARRIS>MPA9507M93469.WPD *no major changes to SE OFFICE PM:PDII/S2 LA:PDII/S2 SC: P DII/S2 NAME RLaufer ~ EDu ing ton SC:EMEB'Terao DATE / /00 $ /g /00 2 /18 /00 /r. /00 COPY es No, es/ o Yes/No OFFICIAL RECORD COP e /No

0 (

l I v II

+y***y+

lf 4t UNITED STATES

-NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001

~ . Alllli, I<arch 8, 2000 J/(XIIX Mr. James Scarola, Vice President Shearon Harris Nuclear Power PJant Carolina Power 8 Light Company Post Office Box 165, Mail Code: Zone 1 New Hill, North Carolina 27562-0165

SUBJECT:

SHEARON HARRIS NUCLEAR POWER PLANT, UNIT 1 - EVALUATIONOF GENERIC LETTER 95-07 RESPONSE (TAC NO. M93469)

Dear Mr. Scarola:

On August 17, 1995, the NRC issued Generic Letter (GL) 95-07, "Pressure Locking and Thermal Binding of Safety-Related Power-Operated Gate Valves," to request that licensees take actions to ensure that safety-related power-operated gate valvesithat are susceptible to pressure locking or thermal binding are capable of performing their safety functions.

By letters dated February 13 and August 19, 1996, May 26, 1997, and September 29 and December 30, 1999, Carolina Power 8 Light Company (CP8L) provided its responses to GL 95-07, and to NRC requests for additional information regarding the responses, for the Shearon Harris Nuclear Power Plant (HNP). As discussed in the enclosed Safety Evaluation, the NRC staff has reviewed the submittals and finds that CP8L has adequately addressed the actions requested in GL 95-07 for HNP.

Sincerely, Richard J. Laufer, Project Manager, Section 2 Project Directorate II Division of Licensing Project Management Office of Nuclear Reactor Regulation Docket No. 50-400

Enclosure:

Safety Evaluation cc w/encl: See next page

Mr. James Scarola Shearon ris Nuclear Power Plant Carolina Power 8 Light Company Unit 1 CC Mr. William D. Johnson Mr. Chris L. Burton Vice President and Corporate Secretary Director of Site Operations Carolina Power & Light Company Carolina Power & Light Company Post Office Box 1551 Shearon Harris Nuclear Power Plant Raleigh,:North Carolina 27602 Post Office Box 165, MC: Zone 1 New Hill, North Carolina 27562-01 65 Resident Inspector/Harris NPS c/o U.S. Nuclear Regulatory Commission Mr. Robert P. Gruber 5421 Shearon Harris Road Executive Director New Hill, North Carolina 27562-9998 Public Staff NCUC Post Office Box 29520 Ms. Karen E. Long Raleigh, North Carolina 27626 Assistant Attorney General State of North Carolina Chairman of the North Carolina Post Office Box 629 Utilities Commission Raleigh, North Carolina 27602 Post Office Box 29510 Raleigh, North Carolina 27626-0510 Public Service Commission State of South Carolina Post Office Drawer Columbia, South Carolina 29211 Mr. Vernon Malone, Chairman Board of CoUnty Commissioners of Wake County P. O. Box 550 Mr. Mel Fry, Director Raleigh, North Carolina 27602 Division of Radiation Protection N.C. Department of Environment and Natural Resources 3825 Barrett Dr. Mr. Richard H. Givens, Chairman Raleigh, North Carolina 27609-7721 Board of County Commissioners of Chatham County P. O. Box 87 Mr. Terry C. Morton Pittsboro, North Carolina 27312 Manager Performance Evaluation and Ms.- Donna B. Alexander, Manager-Regulatory Affairs CPB 7 Regulatory Affairs Carolina Power & Light Company Carolina Power & Light Company Post Office Box 1551 Shearon Harris Nuclear Power Plant Raleigh, North Carolina 27602-1551 P.O. Box 165, Mail Zone 1 New Hill, NC 27562-0165 Mr. Robert J. Duncan II Plant General Manager Mr. Johnny H. Eads, Supervisor Carolina Power & Light Company Licensing/Regulatory Programs Shearon Harris Nuclear Power Plant Carolina Power & Light Company P.O. Box 165, Mail Zone 3 Shearon Harris Nuclear Power Plant New Hill, North Carolina 27562-0165 P. O. Box 165, Mail Zone 1 New Hill, NC 27562-0165 Mr. John H. O'eill, Jr.

Shaw, Pittman, Potts & Trowbridge 2300 N Street, NW.

Washington, DC 20037-1128

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lt UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555.0001 SAFETY EVALUATIONBY THE OFFICE OF NUCLEAR REACTOR REGULATION LICENSEE RESPONSE TO GENERIC LETTER 95-07 "PRESSURE LOCKING AND THERMAL BINDING OF SAFETY-RELATED MOTOR-OPERATED GATE VALVES "

SHEARON HARRIS NUCLEAR POWER PLANT DOCKET NUMBER 50-400

1.0 INTRODUCTION

Pressure locking and thermal binding represent potential common-cause failure mechanisms that can render redundant safety systems incapable of performing their safety functions. The identification of susceptible valves and the determination of when the Phenomena might occur require a thorough knowledge of components, systems, and plant operations. Pressure locking occurs in flexible-wedge and double-disk gate valves when fluid becomes pressurized inside the valve bonnet and the actuator is not capable of overcoming the additional thrust requirements resulting from the differential pressure created across both valve disks by the pressurized fluid in the valve bonnet. Thermal binding is generally associated with a wedge gate valve that is closed while the system is hot and then is allowed to cool before an attempt is made to open the valve.

Pressure locking or thermal binding occurs as a result of the valve design characteristics (wedge and valve body configuration, flexibility, and material thermal coefficients) when the valve is subjected to specific pressures and temperatures during various modes of plant operation. Operating experience indicates that these situations were not always considered in many plants as part of the design basis for valves.

2.0 REGULATORY REQUIREMENTS Title 10 of the Code of Federal Regulations (10 CFR) Part 50 (Appendix A, General Design Criteria 1 and 4) and plant licensing safety analyses require or commit (or both) that licensees design and test safety-related components and systems to provide adequate assurance that those systems can perform their safety functions. Other individual criteria in Appendix A to 10 CFR Part 50 apply to specific systems. In accordance with those regulations and licensing commitments, and under the additional provisions of 10 CFR Part 50 (Appendix B, Criterion XVI), licensees are expected to act to ensure that safety-re1ated power-operated gate valves susceptible to pressure locking or thermal binding are capable of performing their required safety functions.

On August 17, 1995, the NRC issued Generic Letter (GL) 95-07, "Pressure Locking and Thermal Binding of Safety-Related Power-Operated Gate Valves," to request that licensees take

I certain actions to ensure that safety-related power-operated gate valves that are susceptible to pressure locking or thermal binding are capable of performing their safety functions within the current licensing bases of the facility. GL 95-07 requested that each licensee, within 180 days of the date of issuance of the GL: (1) evaluate the operational configurations of safety-related power-operated gate valves in its plant to identify valves that are susceptible to pressure locking or thermal binding; and (2) perform further analyses and take needed corrective actions (or justify longer schedules) to ensure that the susceptible valves identified in (1) above, are capable of performing their intended safety functions under all modes of plant operation, including test configuration. In addition, GL 95-07 requested that licensees, within 180 days of the date of issuance of the GL, provide to the NRC a summary description of (1) the susceptibility evaluation used to determine that valves are or are not susceptible to pressure locking or thermal binding; (2) the results of the susceptibility evaluation, including a listing of the susceptible valves identified; and (3) the corrective actions, or other dispositioning, for the valves identified as susceptible to pressure locking or thermal binding. The NRC issued GL 95-07 as a "compliance backfit" pursuant to 10 CFR 50.109(a)(4)(i) because modification may be necessary to bring facilities into compliance with the rules of the Commission referenced above.

In a letter of February 13, 1996, Carolina Power 8 Light Company (Cf'8L) submitted its 180-day response to GL 95-07 for the Shearon Harris Nuclear Plant (HNP). The NRC staff reviewed the licensee's submittal and requested additional information in a letter dated July 2, 1996. In a letter of August 19, 1996, the licensee provided the additional information. In a letter of May 26, 1997, the licensee updated several GL 95-07 commitments. On September 29 and December 30, 1999, the licensee provided responses to a request for additional information regarding GL 95-07 forwarded by the NRC staff on April 14, 1999.

3.0 STAFF EVALUATION 3.1 Scope of Licensee's Review GL 95-07 requested that licensees evaluate the operational configurations of safety-related power-operated gate valves in their plants to identify valves that are susceptible to pressure locking or thermal binding. The CP8L letters of February 13 and August 19, 1996, May 26, 1997, and September 29 and December 30, 1999, described the scope of valves evaluated in response to GL 95-'07. The NRC staff has reviewed the scope of the licensee's susceptibility evaluation performed in response to GL 95-07 and found it complete and acceptable.

The low head safety injection (Sl) to reactor coolant system (RCS) hot leg valve 1SI-359, and the residual heat removal (RHR) cross-tie valves 1SI-326 and 1SI-327, are not included in the scope of GL 95-07 because the HNP licensing basis credits redundant charging Sl pump hot leg recirculation/injection paths for providing flow to the RCS hot legs. Normally open, safety-related power-operated gate valves which are closed for test or surveillance but must return to the open position were evaluated within the scope of GL 95-07. The staff finds the criteria for determining the scope of power-operated valves for GL 95-07 are consistent with the staffs acceptance of the scope of motor-operated valves associated with GL 89-10, "Safety-Related Motor-Operated Valve Testing and Surveillance."

3.2 Corrective Actions GL 95-07 requested that licensees, within 180 days, perform further analyses as appropriate, and take appropriate corrective actions (or justify longer schedules), to ensure that the susceptible valves identified are capable of performing their intended safety function under all modes of plant operation, including test configuration. The licensee's submittals discussed proposed corrective actions to address potential pressure-locking and thermal-binding problems. The staffs evaluation of the licensee's actions is discussed in the following paragraphs:

a. The licensee stated that it used a thrust-prediction methodology developed by Commonwealth Edison Company (ComEd) (for the industry to use) to demonstrate that the following valves are capable of opening during pressure-locking conditions:

1SI-3 Boron Injection Tank Outlet 1SI-4 Boron Injection Tank Outlet On April 9, 1997, the staff held a public meeting to discuss the technical adequacy of the ComEd pressure-locking thrust prediction methodology and it4 generic use by licensees in their submittals responding to GL 95-07. The minutes of the public meeting were issued on April 25, 1997. At the public meeting, ComEd recommended that, when using its methodology, minimum margins should be applied between calculated pressure-locking thrust and actuator capability. These margins along with diagnostic equipment accuracy and methodology limitations are defined in a letter from ComEd to the NRC dated May 29, 1998. The NRC considers the use of the ComEd pressure-locking methodology acceptable provided these margins, diagnostic equipment accuracy requirements and methodology limitations are incorporated into the pressure-locking calculations. The CP8L letter of December 30, 1999, describes the licensee's method for determining minimum margins. The licensee accounts for accuracies associated with its test equipment and variances in static unwedging force. The NRC staff considers that calculations that are used to demonstrate that valves can overcome pressure locking are required to meet the requirements of 10 CFR Part 50, Appendix B, Quality Assurance Criteria for Nuclear Power Plants, and therefore, controls are required to be in place to ensure that any industry pressure-locking thrust prediction methodology requirements and revisions are properly implemented. Under this condition, the staff finds that the ComEd methodology provides a technically sound basis for assuring that valves susceptible to pressure locking are capable of performing their intended safety-related function.

The licensee stated that it used the ComEd thrust-prediction methodology to demonstrate that the following valves are capable of operating during pressure-locking conditions:

1SI-86 Normal High Head Sl to RCS Hot Leg 1SI-107 Alternate High Head Sl to RCS Hot Leg

4 The margin between actuator capability and the thrust required for the valves to open during pressure-locking conditions is positive but less than that required for long-term corrective action. The licensee also credited seat leakage over a 6.5-hour period as short-term corrective action to justify the reduction of the pressure in the bonnets of the valves. The leakage rate was based on test data obtained from similar valves.

As a long-term corrective action, the actuators are scheduled to be modified to increase thrust and margin during the refueling outage scheduled for the spring of 2000. The NRC staff finds that the licensee's short-term and long-term actions provide reasonable assurance that the valves are capable of operating during pressure-locking conditions, and are thus acceptable.

c. The licensee stated that it used the ComEd thrust-prediction methodology to demonstrate that the following valves are capable of operating during pressure-locking conditions:

1SI-52 High Head SI to RCS Cold Leg 1RC-113 Pressurizer Power Operated Relief Valve (PORV) Block 1RC-115 Pressurizer PORV Block i 1RC-117 Pressurizer PORV Block In its letter to the NRC dated May 29, 1999, ComEd stated that its pressure-locking methodology was developed and validated for balanced and near balanced pressure-locking conditions (the difference between upstream and downstream pressure is not significant when compared to the difference between the bonnet pressure and upstream (downstream) pressure). In its letter dated December 30, 1999, CPB L stated that pressure-locking conditions for valves 1RC-113, 1RC-115, 1RC-117, and 1SI-52 do not meet the ComEd pressure-locking methodology balanced conditions. As a short-term corrective action, a maximum prediction error based on dynamic test results was used to compensate for the unbalanced conditions. As long-term corrective actions, the actuators are scheduled to be modified to increase thrust output during the refueling outage scheduled for the spring of 2000. The margins between calculated pressure-locking thrust and actuator capability will exceed 100% following the completion of the modifications. The NRC staff finds that the licensee's short-term and long-term actions provide reasonable assurance that the valves are capable of operating during pressure-locking conditions, and are thus acceptable.

The licensee also stated that the boron injection tank inlet valves 1SI-1 and 1SI-2 are susceptible to pressure locking and will operate for up to 1.5 seconds at locked-rotor conditions following a loss-of-offsite power concurrent with emergency core cooling system automatic initiation. It takes a maximum of 1.5 seconds for a charging Sl pump to develop full discharge pressure and equalize pressure across the upstream disk of each valve. Pressure-locking conditions do not exist once the pressure across the upstream disk is equalized.

The NRC staff accepts operation of ac-powered motor actuators for short periods at locked-rotor conditions (approximately 1 second) because testing performed by Idaho National Engineering and Environmental Laboratory (NUREG/CR-6478) demonstrates that the capability of the actuator does not significantly degrade.

The licensee stated that procedures require that: (1) the piping between the RHR pump sump suction valves, 1SI-300 and 1SI-301, and the containment sump; and (2) the piping between the containment spray pump suction valves 1CT-102 and 1CT-105, and the containment sump, be filled with water to a level that maintains approximately 24 feet of filled vertical piping between the valves and the containment sump to insulate the valves from the hot, post-accident sump fluid. The staff. finds that the licensee's procedural change to fill the piping between 1SI-300, 1SI-301, 1CT-102, and 1CT-105 and the containment sump provide assurance that thermal pressure-locking conditions are eliminated, and is an acceptable corrective action.

f. The licensee stated that procedures were modified to cycle the following valves following evolutions that could potentially create a pressure-locking condition:

1CT-50 Containment. Spray Pump Discharge 1CT-88 Containment Spray Pump Discharge 1RH-25 RHR Pump to Charging/Sl Pump Suction 1RH-63 RHR Pump to Charging/Sl Pump Suction 1SI-300 Containment Sump to RHR Pump 1SI-301 Containment Sump to RHR Pump 1SI-310 Containment Sump to RHR Pump 1SI-311 Containment Sump to RHR Pump The staff finds that the licensee's procedural changes to require cycling the valves provide assurance that pressure-locking conditions are adequately identified and eliminated, and are thus acceptable.

g. The licensee stated that the following valves will be modified to eliminate the potential for pressure locking during the refueling outage scheduled for the fall of 2001:

1SI-322 RHR Pump Suction From Refueling Water Storage Tank (RWST) 1SI-323 RHR Pump Suction From RWST For the short-term, operational experience representative of pressure-locking conditions was used to demonstrate operability of the valves. The staff finds that operational experience provides reasonable assurance that the valves will be operable until the planned modifications to prevent pressure locking are completed as scheduled. The staff finds that physical modification to valves susceptible to pressure locking is an appropriate long-term corrective action to ensure operability of the valves, and is thus acceptable.

The licensee stated that the RHR pump suction valves 1RH-1, 1RH-2, 1RH-39, and 1RH-40 are susceptible to pressure locking. The licensee stated that these valves are periodically opened during pressure-locking conditions and that operational history demonstrates that these valves have not failed to open due to pressure locking. These valves are not required to open to mitigate any of the accidents analyzed in Chapter 15 of the Final Safety Analysis Report. These valves are normally opened during plant

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cooldown when full design voltage is available to the actuators. Also, there are two redundant RCS hot leg flow paths available to accomplish this function. The NRC staff finds that the analysis and operational history results provide an acceptable approach for resolving 1RH-1, 1RH-2, 1RH-39, and 1RH-40 pressure-locking concerns.

The licensee stated that all flexible and solid wedge gate valves in the scope of GL 95-07 were evaluated for thermal binding. When evaluating whether valves were susceptible to thermal binding, the licensee assumed that thermal binding would not occur below specific temperature thresholds. Operating conditions for the pressurizer PORV block valves 1RC-113, 1RC-115, and 1RC-117, and the RCS to RHR pump suction valves 1RH-2 and 1RH-40, exceeded the temperature thresholds. The licensee stated that procedures require that valves 1RC-113, 1RC-115, and 1RC-117 be opened prior to cooling the plant to prevent the valves from thermal binding and that operating experience demonstrated that valves 1RH-2 and 1RH-40 are not susceptible to thermal binding. The screening criteria used by the licensee appear to provide a reasonable approach to identify those valves that might be susceptible to thermal binding. Until more definitive industry criteria are developed, the staff concludes that the licensee's actions to address thermal binding of gate valves are acceptable.

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4.0 CONCLUSION

On the basis of this evaluation, the NRC staff finds that the licensee has performed appropriate evaluations of the operational configurations of safety-related power-operated gate valves to identify valves at the HNP that are susceptible to pressure locking or thermal binding. In addition, the NRC staff finds that the licensee has taken, or is scheduled to take, appropriate corrective actions to ensure that these valves are capable of performing their intended safety functions. Therefore, the staff concludes that the licensee has adequately addressed the requested actions discussed in GL 95-07.

Principal Contributor: S. Tingen, NRR Date: March 8, 2000

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ILE CENTER 01 Paper Copy External Recipients:

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Item: ADAMS Document Library: ML ADAMS*HQNTAD01 ID: 003677010

Subject:

Shearon Harris Nuclear Power Plant, Unit 1 Completion of Licensing A ction for Generic Letter 99-02, "Laboratory Testing of Nuclear-Grade A ctivated Charcoal" (TAC No. MA5798)

Body:

ADAMS DISTRIBUTION NOTIFICATION.

Electronic Recipients can RIGHT CLICK and OPEN the first Attachment to View the Document in ADAMS. The Document may also be viewed by searching f or Accession Number ML003677010.

DF01 Direct Flow Distribution: 50 Docket (PDR Avail)

Docket: 05000400 Page 1

t UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001

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Mr.,James Scarola january 27, 2000 (2) plants in compliance with their TS that test in accordance with a test protocol other than ASTM D3803-1989 (3) plants not in compliance with their TS that test in accordance with ASTM D3803-1989 (4) plants not in compliance with their TS that test in accordance with a test protocol other than ASTM D3803-1989 By letter dated November 19, 1999, you provided the GL 99-02 response for the Harris Nuclear Plant. Your response referenced a request for a license amendment to change your TS to provide for testing as described in the GL which was also submitted on November 19, 1999.

The NRC staff has reviewed your response and has concluded that you have provided the requested information and a TS change request in accordance with the GL. In addition, you have committed to test in accordance with ASTM D3803-1989 until your TS amendment is issued. Therefore, we consider GL 99-02 to be closed for your facility. The TS change will be reviewed as a separate, plant-specific action under TAC No. MA7183; We thank you for your prompt and complete response.

If you have any questions. regarding this matter, please contact me at 301-415-1373.

I I

j Sincerely,

/RA/

Richard J. Laufer, Project Manager, Section 2 Project Directorate II Division of Licensing Project Management Office of Nuclear Reactor Regulation Docket No. 50-400

Enclosure:

Safety Evaluation cc w/encl: See next page Distribution Docket File EDunnington PUBLIC HBerkow PD II-2 Rdg OGC JZwolinski/S Black ACRS BBonser, Rll BMozafari JSegala JHannon FILENAME -':ipDI I-2iHARRISiMPA9902MA5798.W P D OFFICE PM:PDII/S2 LA:PDII/S2 LPM'G 9-02 SC:SP SC:PDII/S2 NAME RLaufer EDunnin ton BMo an E eiss R M DATE / /00 // /9 /00 i/ /00 /00 /eH00 COPY es No es No Ye No /No e /No OFFICIA CORD CO

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Direct Flow Distribution: 50 Docket (PDR Avail)

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Docket: 05000400, Notes: Application for permit renewal filed.

Page 1

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UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001

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Mr. James Scarola, Vice President Shearon Harris Nuclear Power Plant Carolina Power & Light Company PostOffice Box165, Mail Code: Zone 1 New Hill, North Carolina 27562-0165

SUBJECT:

NRC STAFF'S EVALUATIONOF THE SHEARON HARRIS NUCLEAR POWER PLANT, UNIT 1, INDIVIDUALPLANT EXAMINATIONOF EXTERNAL EVENTS (IPEEE) SUBMITTAL(TAC NO. M83627)

Dear Mr. Scarola:

On June 28, 1991, the NRC issued Generic Letter (GL) 88-20, Supplement 4, "Individual Plant Examination of External Events (IPEEE) for Severe Accident Vulnerabilities - Title 10 CFR 50.54(f)," requesting that each licensee perform an IPEEE to identify plant-specific vulnerabilities to severe accidents, and report the results to the NRC together with any licensee-determined improvements and corrective actions. By letter dated December 19, 1991, as supplemented on October 15, 1992, June 30, 1995, and December 16, 1998, Carolina Power &

Light Company (CP&L) provided'its response to GL 88-20, Supplement 4, for the Shearon Harris Nuclear Power Plant, Unit 1 (HNP).

The staff performed a screening review which examined the IPEEE results for their completeness and reasonableness considering the design and operation of the plant. On the basis of this review and further review by a senior review board (SRB), the staff concluded that the aspects of seismic; fires; and high winds, floods, transportation and other external events were adequately addressed. The SRB is comprised of representatives from the NRC's Offices of Research (RES) and Nuclear Reactor Regulation (NRR), and RES consultants (Sandia National Laboratories) with probabilistic risk assessment expertise for external events. The staff's review findings are summarized in the enclosed Staff Evaluation Report (SER), and the details of the findings of the contractors'and staff appear'in the Technical Evaluation Reports attached to the SER.

On the basis of the IPEEE review, the staff concludes that CP&L's IPEEE process is capable of identifying the most likely severe accidents and severe accident vulnerabilities and, therefore,

'e that the HNP IPEEE has met the intent of Generic Letter 88-20, Supplement 4.

The following set of generic safety issues applicable to HNP were identified in GL 88-20, Supplement 4, and its associated guidance in NUREG-1407, "Procedural and Submittal Guidance," as needing to be addressed as part of the IPEE (1) Unresolved Safety Issue (USI) A-45, "Shutdown Dec hht, Requirements;"

(2) Generic Safety Issue (GSI) 57, "Effects of Fire Protection System Actuation on Safety-Related Equipment;"

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(3) GSI-103, "Design for Probable Maximum Precipitation (PMP);"

(4) GSI-131, "Potential Seismic Interaction Involving the Movable In-Core Flux Mapping System Used In Westinghouse Plants;" and, (5) The Sandia Fire Risk Scoping Study (FRSS) issues.

Except for the FRSS issue of misdirected manual fire suppression, which is also part of GSI-148, "Smoke Control and Manual Fire-Fighting Effectiveness," all of the issues called out directly in GL 88-20, Supplement 4, and its associated guidance document, are considered resolved.

The need for any additional assessment or actions related to the resolution of GSI-148 and its associated FRSS issue will be addressed by the NRC staff separately from the IPEEE program.

In addition, CP8 L's IPEEE submittal contains some specific information that addresses the external event aspects of certain other generic issues: GSI-147, "Fire-Induced Alternate Shutdown/Control Room Panel Interactions" (also an FRSS issue) and GSI-172, "Multiple System Responses Program (MSRP)." As discussed in the enclosed SER, the staff also considers these issues resolved for HNP.

I This completes our action with respect to TAC No. M83627. If you have any comments regarding the enclosed evaluation, please contact'me at (301) 415-1373.

Sincerely, Original signed by R.Laufer Richard J. Laufer, Project Manager, Section 2 Project Directorate II Division of Licensing Project Management Office of Nuclear Reactor Regulation Docket No. 50-400

Enclosure:

As stated cc w/encl: See next page Distribution:

File Center PUBLIC HBerkow BBonser, Rll PD II Rdg OGC JZwolinski/S Black ACRS GHill (2) LWiens ABuslik ARubin DCoe FILENAME - G:<PDII-2IIHARRIS<IPEEEM83627.WPD

no major changes to SE OFFICE PM:PDII/S2 LA:PDII/ 2 RES Sc:PDII/S2 NAME RLaufer ~ EDunnington TKing R orreia DATE / 8/00 6 /9/oo /00

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(3) GSI-103, "Design for Probable Maximum Precipitation (PMP);"

(4) GSI-131, "Potential Seismic Interaction Involving the Movable In-Core Flux Mapping System Used In Westinghouse Plants;" and (5) The Sandia Fire Risk Scoping Study (FRSS) issues.

Except for the FRSS issue of misdirected manual fire suppression, which is also part of GSI-148, "Smoke Control and Manual Fire-Fighting Effectiveness," all of the issues called out directly in GL 88-20, Supplement 4, and its associated guidance document, are considered resolved.,

The need for any additional assessment or actions related to the resolution of GSI-148 and its associated FRSS issue will be addressed by the NRC staff separately from the IPEEE program.

In addition, CP8 L's IPEEE submittal contains some specific information that addresses the external event aspects of certain other generic issues: GSI-147, "Fire-Induced Alternate Shutdown/Control Room Panel Interactions" (also an FRSS issue) and GSI-172, "Multiple System Responses Program (MSRP)." As discussed in the enclosed SER, the staff also consjders these issues resolved for HNP.

This completes our action with respect to TAC No. M83627. If you have any comments regarding the enclosed evaluation, please contact me at (301) 415-1373.

Sincerely, Richard J. Laufer, Project Manager, Section 2 Project Directorate II Division of Licensing Project Management Office of Nuclear Reactor Regulation Docket No. 50-400

Enclosure:

As stated ccw/encl: See next page

Mr. James Scarola Shearon Harris Nuclear Power Plant Carolina Power & Light Company Unit 1 CC:

Mr. William D. Johnson Mr. Chris L. Burton Vice President and Corporate Secretary Director of Site Operations Carolina Power & Liqht Company Carolina Power & Light Company Post Office Box 1551 Shearon Harris Nuclear Power Plant Raleigh, North Carolina 27602 Post Office Box 165, MC: Zone 1 New Hill, North Carolina 27562-0165 Resident Inspector/Harris NPS c/o U.S. Nuc ear Regulatory Commission Mr. Robert P. Gruber 5421 Shearon Harris Road Executive Director New Hill, North Carolina 27562-9998 Public Staff NCUC Post Office Box 29520 Ms. Karen E. Long Raleigh, North Carolina 27626 Assistant Attorney General State of North Carolina Chairman of the North Carolina Post Office Box 629 Utilities Commission Raleigh, North Carolina '27602 Post Office Box 29510 Raleigh, North Carolina 27626-0510 Public Service Commission State of South Carolina Post Office Drawer Columbia, South Carolina 29211 Mr. Vernon Malone, Chairman Board of County Commissioners of Wake Countv P. O. Box 550 Mr. Mel Fry, Director Raleigh, North Carolina 27602 Division of Radiation Protection N.C. Department of Environment and Natural Resources 3825 Barrett Dr. Mr. Richard H. Givens, Chairman Raleigh, North Carolina 27609-7721 Board of County Commissioners of Chatham County P. O. Box 87 Mr. Terry C. Morton Pittsboro, North Carolina 27312 Manager Performance Evaluation and Ms. Donna B. Alexander, Manager Regulatory Affairs CPB 7 Regulatory Affairs Carolina Power & Liqht Company Carolina Power & Light Company Post Office Box 1551 Shearon Harris Nuclear Power Plant Raleigh, North Carolina 27602-1551 P.O. Box 165, Mail Zone 1 New Hill, NC 27562-0165 Mr. Bo Clark Plant General Manager - Harris Plant Mr. Johnny H. Eads, Supervisor Carolina Power & Light Company Licensing/Regulatory Programs Shearon Harris Nuclear Power Plant Carolina Power & Light Company P.O. Box 165 Shearon Harris Nuclear Power Plant New Hill, North Carolina 27562-01 65 P. O. Box 165, Mail Zone 1 New Hill, NC 27562-0165 Mr. John H. O'eill, Jr.

Shaw Pittman, Potts & Trowbridge 2300 4 Street, NW.

Washington, DC 20037-1128

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Item: ADAMS Document Library: ML ADAMS"HQNTAD01 ID: 003730645:1

Subject:

CONNECTICUT COALITION AGAINST MILLSTONE AND LONG ISLAND COALITIONAGA INST MILLSTONE SUPPLEMENTAL RESPONSE TO NORTHEAST NUCLEAR ENERGY C OMPANY'S FIRST REQUEST FOR PRODUCTION Body:

ADAMS DISTRIBUTION NOTIFICATION.

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SECY02- Mail Directed to SECY/RAS Rulemakings and Adjudications Section Docket: 05000423 Page 1

'~e UNITED STATES OF AMERICA NUCLEAR REGULATORY COMMISSION BEFORE THE ATOMIC SAFETY AND LICENSXNG BOARD g J",,l gO pg In the Matter of: Docket No. 50-423-LA-3.

Northeast Nuclear Energy Company (Millstone Nuclear Power Station, AC Unit No. 3) ASLBP No. 00-771-Ol-LA CONNECTICUT COALITXON AGAINST MXLLSTONE AND LONG ISLAND COALITION AGAXNST MILLSTONE SUPPLEMENTAL RESPONSE TO NORTHEAST NUCLEAR ENERGY COMPANY' FIRST REQUEST FOR PRODUCTION The Connecticut Coalition Against Millstone ("CCAM"). and Long Island Coalition Against Millstone ("CAM") (collectively, "Intervenors") herewith supplement their production of documents in response to the Northeast Nuclear Energy Company's First Request for Production, as follows:

Documents submitted by Orange County In the Matter of Carolina Power & Light (Shearon Harris Nuclear Power Plant), Docket No.

50-400-LA, ASLBP No. 99-762-02-LA, as follows:

(l) Detailed Summary of Facts, Data and Arguments and Sworn Submission on Which Orange County Intends to Rely at Oral Argument to Demonstrate the Existence of a Genuine and Substantial Dispute of Fact .with the Licensee Regarding the Proposed Expansion of Spent Fuel Storage Capacity at the Harris Nuclear Power Plant With Respect to Criticality Orevention Issues (Contention TC-2);

(2) Appendix B to the above Detailed Summary; and (3) Appendix C to the above Detailed Summary.

CONNECTICUT COALITION AGAINST MILLSTONE LONG 'ISLAND COALITION AGAINST 'MILLSTONE By:

Nancy rton, Esq.

l47 r ss Highway Red ing Ridge CT 06876 Tel. 203-938-3952

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UNITED STATES OF AMERICA NUCLEAR REGULATORY COMMISSION BEFORE THE ATOMIC SAFETY AND LICENSING BOARD In the Matter of: Docket No. 50-423-LA-3 Northeast Nuclear Energy Company (Millstone Nuclear Power Station, Unit No. 3) ASLBP No. 771-Ol-LA CERTIFICATE OF SERUICE I hereby certify that, copies of "Connecticut Coalition Against Millstone and Long Island Coalition Against Millstone to Northeast Nuclear Energy Company's First Request for Supplemental'esponse Production" and the documents identified therein in the above-captioned proceeding have been served on the following by deposit in the United States Mail, first class, this 30th day of May, 2000.

David A. Repka, Esq. Charles Bechhoefer Winston 6 Strawn Chairman 1400 L Street NW Atomic Safety and Licensing Board Washington DC 20005 U. S. Nuclear Regulatory Commission Washington DC 20555 Office of the Secretary U.S. Nuclear Regulatory Commission Dr. Richard F. Cole Washington DC 20555 Administrative Judge Atomic Safety and Licensing Board Adjudicatory File U.S. Nuclear Regulatory Commission U. S. Nuclear Regulatory Commission Washington DC 20555-0001 Atomic Safety and Licensing Board Panel Dr. Charles N. Kelber Washington DC 20555 Administrative Judge Atomic Safety and Licensing Board Office of Commission U.S. Nuclear Regulatory Commission Appellate Adjudication Washington DC 20555-0001 U. S. Nuclear Regulatory Commission Washington DC 20555 Ann P. Hodgdon Office of General Counsel U.S. Nuclear Regulatory Commission Washington DC 20555 Nancy B on, Esq.

147 Cr s Highway Reddi g Ridge CT 06876 Tel. 203-938-3952

'I January 4, 2000 UNITED STATES OF AMERICA NUCLEAR REGULATORY COMMISSION BEFORE THE ATOMIC SAFETY AND'LICENSINGBOARD In the Matter of CAROLINAPOWER & LIGHT Docket No. 50-400 -LA (Shearon Harris Nuclear ASLBP No. 99-762-02-LA Power Plant)

DETAILED

SUMMARY

OF FACTS, DATA AND ARGUMENTS AND SWORN SUBMISSION ON WHICH ORANGE COUNTY INTENDS TO RELY AT ORAL ARGUMENT TO DEMONSTRATE THE EXISTENCE OF A GENUINE AND SUBSTANTIALDISPUTE OF FACT WITH THE LICENSEE REGARDING THE PROPOSED EXPANSION OF SPENT FUEL STORAGE CAPACITY AT THE HAZuuS NUCLEAR POWER PLANT WITH RESPECT TO CRITICALITYPREVENTION ISSUES (CONTENTION TC-2)

Submitted by:

Diane Curran HARMON, CUtuVA, SPIELBERG, & EISENBERG, L.L.P 1726 M Street N.W., Suite 600 Washington, D.C. 20036 202/328-3500 Counsel for Orange County Gordon Thompson, Ph.D.

Executive Director INSTITUTE FOR RESOURCE AND SECURITY STUDIES 27 Ellsworth Avenue Cambridge, MA 02139 Expert witness for Orange County January 4, 2000 I

Distri67.txt Distribution Sheet Priority: Normal From: Esperanza Lomosbog Action Recipients: Copies:

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Subject:

Direct Flow Distribution: 50 Docket (PDR Avail)

Body:

PDR ADOCK 05000400 Docket: 05000400, Notes: Application for permit renewal filed.

Page 1

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ttttr. James Scarcta, Vice +ident De 8, 1999 Shearon Harris Nuclear Power Plant Carolina Power 8 Light Company Post Office Box 165, Mail Code: Zone 1 New Hill, North Carolina 27562-0165

SUBJECT:

EVALUATIONOF SECOND 10-YEAR INTERVAL INSERVICE INSPECTION PLAN RELIEF REQUESTS 2RG-004, 2RG-005, 2RG-006, AND 2RG-007-SHEARON HARRIS NUCLEAR POWER PLANT, UNIT 1 (TAC NO. MA0989)

Dear Mr-.Scarola:

By letter dated January 27, 1998, you submitted the Harris Nuclear Plant (HNP) Inservice Inspection (ISI) Program Plan for the second 10-year inspection interval. The ISI Program Plan submittal included 21 relief requests (including 2RG-001 and 2RG-002, which had been previously approved by the NRC). By letter dated August 24, 1998, you withdrew 8 of the original 21 relief requests and submitted an additional relief request. The staff approved relief requests 2R1-010 and 2RG-009 on November 4, 1998, and approved relief request 2RG-008 on June 18, 1999. Based on a September 23, 1999, conference call with the staff related to Code Cases that had been approved in Regulatory Guide 1.147, Rev. 12, you withdrew 7 more of the original 21 relief requests on October 12, 1999.

The staff has reviewed and evaluated the four remaining relief requests included in the January 27, 1998 submittal: 2RG-004,2RG-005, 2RG-006, and 2RG-007. As documentedin the enclosed Safety Evaluation, the staff has determined that the proposed alternatives will provide an equivalent or acceptable. level of quality and safety. Accordingly, the requests for relief are authorized pursuant to 10 CFR 50.55a(a)3(i)'for the second 10-year inspection interval or until such time as Code Ca'ses N-532, N-534, N-535, and N-546 are published in Regulatory Guide 1.147. At that time, if you intend to continue to implement these Code Cases, you should follow all conditions specified in the Regulatory Guide, if any.

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Richard P.'orreia, Chief, Section 2 Project Directorate II Division of Licensing Project Management Office of Nuclear Reactor Regulation Docket No. 50-400

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NUCLEAR REGULATORY COMMISSION VIASHINGTONO.C, cOH&4COl Decaobex 28, 1999 Mr. James Scarola, Vice President Shearon Harris Nuclear Power Plant Carolina Power 8 Light Company Post Office Box 165, Mail Code: Zone 1 New Hill, North Carolina 27562-0165

SUBJECT:

EVALUATIONOF SECOND 10-YEAR INTERVAL INSERVICE INSPECTION PLAN RELIEF REQUESTS 2RG-004, 2RG-005, 2RG-006, AND 2RG-007-SHEARON HARRIS NUCLEAR POWER PLANT, UNIT 1 (TAC NO. MA0989)

Dear Mr. Scarola:

By letter dated January 27, 1998, you submitted the Harris Nuclear Plant (HNP) Inservice Inspection (ISI) Program Plan for the second 10-year inspection interval. The ISI Program Plan submittal included 21 relief requests (including 2RG-001 and 2RG-002, which had been previously approved by the NRC). By letter dated August 24, 1998, you withdrew 8 of the original 21 relief requests and submitted an additional relief request. The staff approved relief requests 2R1-010 and 2RG-009 on November 4, 1998, and approved relief request 2RG-008 on June 18, 1999. Based on a September 23, 1999, conference call with the staff related to Code Cases that had been approved in Regulatory Guide 1.147, Rev. 12, you withdrew 7 more of the original 21 relief requests on October 12, 1999.

The staff has reviewed and evaluated the four remaining relief requests included in the January 27, 1998 submittal: 2RG-004, 2RG-005, 2RG-006, and 2RG-007. As documented in the enclosed Safety Evaluation, the staff has determined that the proposed alternatives will provide an equivalent or acceptable level of quality and safety. Accordingly, the requests for relief are authorized pursuant to 10 CFR 50.55a(a)3(i) for the second 10-year inspection interval or until such time as Code Cases N-532, N-534, N-535, and N-546 are published in Regulatory Guide 1.147. At that time, if you intend to continue to implement these Code Cases, you should follow all conditions specified in the Regulatory Guide, if any.

Sincerely, Richard P. Correia, hief, Section 2 Project Directorate II Division of Licensing Project Management Office of Nuclear Reactor Regulation Docket No. 50-400

Enclosure:

Safety Evaluation cc w/encl: See next page

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~'AFETYEVALUATIONBY THE OFFICE OF NUCLEAR REACTOR REGULATION SECOND 10-YEAR INTERVAL INSERVICE INSPECTION PLAN RELIEF REQUESTS 2RG-004 2RG-005 2RG-006 2RG-007 CAROLINA POWER 8 LIGHT COMPANY SHEARON HARRIS NUCLEAR POWER PLANT DOCKET NO. 50-400

1.0 INTRODUCTION

Inservice inspection (ISI) of the American Society of Mechanical Engineers (ASME) Code Class 1, 2, and 3 components shall be performed in accordance with Section XI of the ASME Boiler and Pressure Vessel (B8 PV) Code and applicable addenda as required by 10 CFR 50.55a(g),

except where specific written relief has been granted by the Commission pursuant to 10 CFR 50.55a(6)(g)(i). 10 CFR 50.55a(a)(3) states in part that alternatives to the requirements of paragraph (g) may be used, when authorized by the NRC, if (i) the proposed alternatives would provide an acceptable level of quality and safety or (ii) compliance with the specified requirements would result in hardship or unusual difficulty without a compensating increase in the level of quality and safety.

Pursuant to 10 CFR 50.55a(g)(4), ASME Code Class 1, 2, and 3 components (including supports) shall meet the requirements, except the design and access provisions and the pre-service examination requirements, set forth in the ASME Code,Section XI, "Rules for Inservice Inspection of Nuclear Power Plant Components," to the extent practical within the limitations of design, geometry, and materials of construction of the components. The regulations require that inservice examination of components and system pressure tests conducted during the first 10-year interval and subsequent intervals comply with the requirements in the latest edition and addenda of Section XI of the ASME Code incorporated by reference in 10 CFR 50.55a(b) 12 months prior to the start of the 120-month interval, subject to the limitations and modifications listed therein. For the Shearon Harris Nuclear Power Plant (HNP), the applicable edition of Section XI of the ASME Code for the second 10-year ISI interval is the 1989 Edition.

2.0 EVALUATION By letter dated January 27, 1998, Carolina Power 8 Light Company (CP8L, the licensee) submitted the HNP ISI Program Plan for the second 10-year inspection interval. The ISI Program Plan submittal included 21 relief requests (including 2RG-001 and 2RG-002, which had been previously approved by the NRC). By letter dated August 24, 1998, CP8L withdrew 8 of the original 21 relief requests and submitted an additional relief request. The staff approved relief requests 2R1-010 and 2RG-009 on November 4, 1998, and approved relief request 2RG-008 on June 18, 1999. Based on a September 23, 1999, conference call with the staff related to

Code Cases that had been approved in Regulatory Guide 1.147, Rev. 12, CP8L withdrew 7 more of the original 21 relief requests on October. 12, 1999.

The Idaho National Engineering and Environmental Laboratory (INEEL) staffs evaluation of the remaining requests for relief, 2RG-004, 2RG-005, 2RG-006, and 2RG-007, is attached. Based on the results of the 'review, the staff adopts the contractor's conclusions presented in the attached technical letter report (TLR).

The information provided by the licensee in support of the requests for relief from Code requirements has been evaluated and the basis for disposition is documented below.

Re uest for Relief No. 2RG-004:

ASME Code,Section XI, Subarticles IWA-4800, -6200, and -7500 require the Owner to prepare preservice and ISI summary reports for Class 1 and Class 2 pressure-retaining components and their supports. Paragraph IWA-6230 also requires that these summary reports be submitted to the enforcement and regulatory authorities having jurisdiction at the plant site within 90 days of the completion of the'Sls conducted each refueling outage.

Pursuant to 10 CFR 50.55a(a)(3), the licensee proposed to use Code Case N-532 as alternative requirements to repair and replacement documentation requirements and inservice summary report preparation and submission as required by IWA-4000 and IWA-6000.

Code Case N-532 requires preparation of the Repair/Replacement Certification Record, Form NIS-2A with endorsement by an Authorized Nuclear Inservice Inspector (ANII) as defined in ASME Code,Section XI, IWA-2130 and requires the record to be maintained by the Owner.

Furthermore, this Code Case requires Owner's Activity Report Form, OAR-1, preparation and certification by an ANII upon completion of each refueling outage. The OAR-1 form contains an abstract of applicable examinations and tests, a list of item(s) with flaws or relevant conditions that require evaluation to determine acceptability for continued service, and an abstract of repairs, replacements and corrective measures performed as a result of unacceptable flaws or relevant conditions. Code Case N-532 provides an equivalent level of quality and safety to that required by the licensee's Code of record. The licensee's proposed alternative is authorized pursuant to 10 CFR 50.55a(a)(3)(i) for the second 10-year inspection interval or until such time as the Code Case is published in Regulatory Guide 1.147. At that time, if the licensee intends to continue to implement Code Case N-532, the licensee must follow all conditions specified in the Regulatory Guide, if any.

Re uest for Relief No. 2RG-005:

ASME Code,Section XI, IWA-5000, IWC-5000, and IWD-5000, requires hydrostatic tests for Class 2 and 3 components. IWA-5211(e) allows a system pneumatic test to be conducted in lieu of a hydrostatic test for components within the scope of IWC and IWD.

Pursuant to 10 CFR 50.55a(a)(3), the licensee proposed to use Code Case N-534 as alternative requirements for pneumatic pressure testing.

Code Case N-534, Alternative Requirements for Pneumatic Pressure Testing. Code Case N-534 states that:

"...an alternative to the hydrostatic test pressure requirements of IWA-5211, IWA-5212 and IWC-5000 or IWD-5000, the test pressure for a pneumatic test in accordance with IWA-5211(e) [IWA-5211(c) in the 1993 Addenda] shall be normal operating pressure."

In addition to the requirements specified in Code Case N-534, the licensee has committed to:

Conduct the system pneumatic pressure test at or near the end of the inspection, interval or during the same inspection period as previously performed in the first 10-year inspection Interval.

Pressurize the boundaries such that the system test will extend to Class 2 or 3 components for those portions of systems required to operate or support the safety system function, up to and including the first normally closed valve, including a safety or relief valve, or valve capable of automatic closure when the safety function is required.

3. Perform the VT-2 visual inspection on systems after insulation removal. The systems will be pressurized to the nominal operating pressure for at least 10 minutes. The systems will be maintained at nominal operating pressure during application of the bubble solution and performance of the VT-2 visual examination.

4. The VT-2 visual examination will include components within the boundary identified.

These pneumatic test conditions are essentially identical to the hydrostatic test conditions set forth in Code Case N-498-1 for Class 2 and 3 systems except that the systems will be pressurized with air rather than fluid. Code Case N-498-1, Alternative Rules for 10-Year System Hydrostatic Testing for Class 1, 2 and 3 Systems, has been approved for general use in Regulatory Guide 1.147, Revision 12. The licensee will be performing the pneumatic pressure tests at normal operating pressure and applying a bubble solution over the test boundary. The licensee's proposed alternative provides an acceptable level of quality and safety and is authorized pursuant to 10 CFR 50.55a(a)(3)(i) for the second 10-year inspection interval at HNP or until such time as the Code Case is published in Regulatory Guide 1.147. At that time, if the licensee intends to continue to implement Code Case N-534, the licensee must follow all conditions specified in the Regulatory Guide, if any.

Re uest for Relief No. 2RG-006:

ASME Code,Section XI, Paragraph IWA-2432 requires that successive inspection intervals be comprised of 10 years following the previous interval except as modified by Paragraph IWA-2430(d), which allows an interval to be extended or reduced by as much as 1 year to coincide with an outage, thus changing the length of an interval.

Pursuant to 10 CFR 50.55a(a)(3), the licensee proposed to use Code Case N-535 as alternative requirements for scheduling the 10-year inspection interval.

Code Case N-535 consists of four parts which can be summarized as follows:

a) Each inspection interval may be reduced or extended by 1 year. For extended intervals, neither the start or end dates nor the ISI program for the successive interval need be revised. Thus, a successive interval may start prior to the end of the previous interval that was extended.

b) Examinations performed to satisfy the requirements of the extended interval may be performed in conjunction with examinations performed to satisfy the requirements for the successive interval. However, examination's cannot be credited to both intervals.

c) Inspection periods may be extended or reduced to coincide with an outage. This adjustment shall not alter the requirements for scheduling inspection intervals.

d) Examination records must identify which interval the examination was performed in.

Part (a) of Code Case N-535 is the only change from current Section XI philosophy. The 1-year extension is independent of the plant operating cycle and two intervals can be open concurrently during that year. Although slightly different from the current Code requirements, implementation of this Code Case does not change the number of examinations, acceptance criteria, or any other Code requirement, with the possible exception of an insignificant change in the distribution of examinations. Therefore, the staff concludes that Code Case N-535 provides an acceptable level of quality and safety and the use of Code Case N-535 is authorized pursuant to 10 CFR 50.55a(a)(3)(i). The use of this Code Case is authorized for the second 10-year inspection interval at HNP or until such time as the Code, Case is published in Regulatory Guide 1.147. At that time, if the licensee intends to continue to implement Code Case N-535, the licensee must follow all conditions specified in the Regulatory Guide, if any.

Re vest for Relief No. 2RG-007:

ASME Code,Section XI, IWA-2300, requires that personnel performing VT-2 and VT-3 visual examinations be qualified in accordance with comparable levels of competency as defined in ANSI N45.2.6. Additionally, the examination personnel shall have natural or corrected near distance acuity, in at least one eye, equivalent to a Snellen fraction of 20/20. For far vision, personnel shall have natural or corrected far distance visual acuity of 20/30 or'equivalent.

Pursuant to 10 CFR 50.55a(a)(3), the licensee proposed to use Code Case N-546 as an alternative to the ASME Section XI qualification requirements for VT-2 visual examiners.

In addition to meeting the requirements contained in Code Case N-546, the licensee has committed to use procedural guidelines for consistent quality VT-2 visual examinations, verify and maintain records of the qualification of persons selected to perform VT-2 visual

examinations, and perform independent reviews and evaluations of leakage by a person(s) other than those that performed the VT-2 visual examination. Code Case N-546 and the additional commitments made by the licensee provides an acceptable level of quality and safety. The licensee's request to implement Code Case N-546,with the additional commitments is authorized pursuant to 10 CFR 50.55a(a)(3)(i) for the second 10-year inspection interval at HNP or until such time as the Code Case is published in Regulatory Guide 1.147. At that time, if the licensee intends to continue to implement Code Case N-546, the licensee must follow all conditions specified in the Regulatory Guide, if any.

3.0 CONCLUSION

The staff concludes that the licensee's proposed alternatives contained in Requests for Relief ~

2RG-004, 2RG-005, 2RG-006 and 2RG-007 provide an equivalent or acceptable level of quality and safety. The licensee's proposed alternatives are authorized pursuant to 10 CFR 50.55a(a)(3)(i) for the second 10-year inspection interval or or until such time as the Code Cases N-532, N-534, N-535, and N-546 are published in Regulatory Guide 1.147. At that time, if the licensee intends to continue to implement these code cases, the licensee should follow all conditions specified in the Regulatory Guide, if any.

Principal Contributor: T. McLellan Date: December 28, 1999

Attachment:

INEEL Technical Letter Report

TECHNICAL LETTER REPORT ON THE SECOND 10-YEAR INTERVAL INSERVICE INSPECTION REQUESTS FOR RELIEF FOR CAROLINA POWER AND LIGHT COMPANY SHEARON HARRIS NUCLEAR POWER PLANT DOCKET NUMBER: 50-400

1. INTRODUCTION By letter dated January 27, 1998, the licensee, Carolina Power and Light Company, submitted the Shearon Harris Nuclear Power Plant ISI Program Plan containing requests for relief from the requirements of the ASME Code,Section XI, for the second 10-year inservice inspection (ISI) interval. By letter dated August 24, 1998, the licensee withdrew relief requests 2R1-003, 2R1-004, 2R1-006, 2R1-008, 2R1-011, 2R2-001, 2R2-003 and 2R2-005. Additionally, in a "Response to Request For Additional Information" letter dated October 12, 1999, the licensee included the withdrawal of relief requests 2R1-009, 2R2-006, 2R2-007, 2R3-002, 2RG-001, 2RG-002, and 2RG-003. The Idaho National Engineering and Environmental Laboratory (INEEL) staff's evaluation of the subject requests for relief in the Shearon Harris Nuclear Power Plant ISI Program Plan are in the following section.

EVALUATION The information provided by Carolina Power and Light Company in support of the requests for relief from Code requirements have been evaluated and the bases for disposition are documented below. The Code of record for the Shearon Harris Nuclear Power Plant, second 10-year ISI interval, which began February 2, 1998, is the 1989 Edition of Section XI of the ASME Boiler and Pressure Vessel Code.

A. Re uest for Relief No. 2RG-004 Use of Code Case N-532 Alternative Re uirements to Re air and Re lacement Documentation Re uirements and Inservice Summa Re ort Pre aration and Submission as Re uired b IWA-4000 and I WA-6000 Code Re uirement: Subarticles IWA-4800, -6200, and -7500 require the Owner to prepare preservice and inservice inspection summary reports for Class 1 and Class 2 pressure retaining components and their supports. Paragraph IWA-6230 also requires that these summary reports be submitted to the enforcement and regulatory authorities having jurisdiction at the plant site within 90 days of the completion of the inservice inspections conducted each refueling outage.

Licensee's Pro osed Alternative: In accordance with 10 CFR 50.55a(a)(3), the licensee proposed to use Code Case N-532 as alternative requirements to repair and replacement documentation requirements and inservice summary report preparation and submission as required by IWA-4000, and IWA-6000. The licensee stated:

Attachment

I' "Code Case N-532 is to be applied as alternative rules for summary reports of ASME Class 1 and 2 Repair/Replacement and Inservice Inspection activities. The reports to be filed at the end of each Period rather than each refueling outage."

Licensee's Basis for Pro osed Alternative (as stated):

"Code Case N-532 has already been approved by the Section XI Code Committee, thus providing an alternative for routine reporting criteria. Filing of reports each outage has proven to be time-consuming, expensive, and of questionable value.

Per 10CFR50 requirements, all documentation associated with either Repair/Replacement or Inservice Inspection are maintained as Quality Assurance documents for the duration of the life of the plant. Any information needed by either the regulatory body or by plant personnel are easily retrievable. The Code Case simplifies reporting criteria, particularly on Repair/Replacement activities, and reduces the frequency of reports to once per Period instead of once per outage.

The reduced reporting requirements aid both the writers and reviewers of the reports, thus reducing the costs of compliance with the ASME Code while still providing quality controls on these safety-related activities."

Justification "The proposed alternative provides an acceptable level of quality and safety since the summary reports are still filed with the enforcement and regulatory authorities having jurisdiction at the plant site while reducing the costs associated with ASME Code Compliance."

Evaluation: The INEEL staff reviewed the proposed alternative documentation requirements of Code Case N-532 and determined that although the required forms have changed, the information required by the Code will be provided by the alternative forms. Code Case N-532 requires preparation of the Repair/Replacement Certification Record, Form NIS-2A with endorsement by an Authorized Nuclear Inservice Inspector (ANII) as defined in ASME Code,Section XI, IWA-2130 and shall be maintained by the Owner. Furthermore, this Code Case requires Owner's Activity Report Form, OAR-1 preparation and certification by an ANII upon completion of each refueling outage. The OAR-1 form contains an abstract of applicable examinations and tests, a list of item(s) with flaws or relevant conditions that require evaluation to determine acceptability for continued service, and an abstract of repairs, replacements and corrective measures performed as a result of unacceptable flaws or relevant conditions. Hence, the information provided in the documentation pertaining to the use of Code Case N-532, can be used in the same manner to assess the safety implications of Code activities performed during an outage.

A review using the information as prescribed by the Code Case will, therefore, provide the same or improved level of quality and safety as reviews that may be conducted using the present Code reporting requirements. In addition, more detailed information may be requested by the staff if it is deemed necessary.

Therefore, the use of this alternative should be authorized pursuant to 10 CFR 50.55a(a)(3)(i). The use of this Code Case should be authorized for the current

interval or until such time as the Code Case is published in Regulatory Guide 1.147. At that time, if the licensee intends to continue to implement Code Case N-532, the licensee should follow all conditions specified in the Regulatory Guide, if present.

B. Re uest for Relief No. 2RG-005 Use of Code Case N-534 Alternative Re uirements for Pneumatic Pressure Testin Code Re uirement: IWA-5000, IWC-5000, and IWD-5000, requires hydrostatic tests for Class 2 and 3 components. IWA-5211(e) allows a system pneumatic test to be conducted in lieu of a hydrostatic test for components within the scope of IWC and IWD.

Licensee's Pro osed Alternative: In accordance with 10 CFR 50.55a(a)(3), the licensee proposed to use,Code Case N-534 as alternative requirements for pneumatic pressure testing. The licensee stated:

"As an alternative to the pneumatic testing at hydrostatic pressure levels, the following is to be used, as applicable:

1) "A system pneumatic pressure test will be conducted at or near the end of the inspection interval or during the same inspection period as previously performed in the First 10-Year Interval.

2) "The boundary subject to pressurization during the system test will extend to Class 2 or 3 components for those portions of systems required to operate or support the safety system function, up to and including the first normally-closed valve, including a safety or relief valve, or valve capable of automatic closure when the safety function is required.

3) "Before performing the VT-2 visual inspection, the system will be uninsulated and pressurized to nominal operating pressure for at least 10 minutes. The system will be maintained at nominal operating pressure during application of the bubble solution and performance of the VT-2 visual examination.

4) "The VT-2 visual examination will include components within the boundary identified above."

Licensee's Basis for Pro osed Alternative (as stated):

"The most common causes of system pressure-boundary failures are flow-accelerated corrosion (FAC), microbiologically induced corrosion (MIC), and general corrosion. Harris Plant has in place programs to monitor both FAC and MIC. Leakage from general corrosion is readily apparent to inspectors when performing a VT-2 inspection during system pressure tests.

"The burdens imposed by Class 2 and 3 pneumatic tests at hydrostatic pressure levels are as follows:

1) "High-pressure tests are historically difficult to perform.

2) Testing at higher-than-nominal-operating pressure requires unique lineups, special equipment installation, and the removal or gagging of pressure relief devices.

3) The time required to complete the testing, as compared to system pressure tests, results in a significant increase in work scope and required resources, and a potentially extended outage.

4) The increase in time, scope, and resources results in additional operational doses, contrary to ALARAprinciples.

"Carolina Power & Light Company considers this request to use ASME Code Case N-534 to be a regulatory burden reduction item for the Harris Plant."

Justification "The proposed alternative provides an acceptable level of quality and safety since any leaks would still be detected. Code Case N-534 requires that the systems still receive a pressure test and visual (VT-2) examination."

Evaluation: The Code requires the performance of a system hydrostatic or pneumatic (in lieu of hydrostatic for air filled systems) test once per interval in accordance with the requirements of IWA-5000 for Class 1, 2, and 3 pressure-retaining systems. In lieu of the Code-required hydrostatic/pneumatic testing requirements, the licensee has requested authorization to use Code Case N-534, Alternative Requirements for Pneumatic Pressure Testing. Code Case N-534 states that

"...an alternative to the hydrostatic test pressure requirements of IWA-5211, IWA-5212 and IWC-5000 or IWD-5000, the test pressure for a pneumatic test in accordance with IWA-5211(e) [IWA-5211(c) in the 1993 Addenda]

shall be normal operating pressure."

The system hydrostatic/pneumatic test, as stipulated in Section XI, is not a test of the structural integrity of the system but rather an enhanced leakage pressure testing per IWA-5211(e) only subjects the piping test.'ydrostatic/pneumatic components to a small increase in pressure over the design pressure; therefore, piping dead weight, thermal expansion, and seismic loads present far greater challenges to the structural integrity of a system. In addition, the industry experience indicates that leaks are not being discovered as a result of test

1. S. H. Bush and R. R. Maccary, "Development of In-Service Inspection Safety Philosophy for U.S.A. Nuclear Power Plants,"ASME, 1971 Consequently, the Section XI hydrostatic/pneumatic pressure test is primarily regarded as a means to enhance leak detection during the examination of components under pressure, rather than as a method to determine the structural integrity of the components.

pressures causing a preexisting flaw to propagate through the wall. In most cases leaks are being found when the system is at normal operating pressure.

In addition to the requirements specified in Code Case N-534 the licensee has committed to;

1. Conduct the system pneumatic pressure test at or near the end of the inspection interval or during the same inspection period as previously performed in the First 10-Year Interval.

Pressurize the boundaries such that the system test will extend to Class 2 or 3 components for those portions of systems required to operate or support the safety system function, up to and including the first normally-closed valve, including a safety or relief valve, or valve capable of automatic closure when the safety function is required.

Perform the VT-2 visual inspection on systems after insulation removal. The systems will be pressurized to the nominal operating pressure for at least 10 minutes. The systems will be maintained at nominal operating pressure during application of the bubble solution and performance of the VT-2 visual examination.

4. The VT-2 visual examination will include components within the boundary identified.

These pneumatic test conditions are essentially identical to the hydrostatic test conditions set forth in Code Case N-498-1 for Class 2 and 3 systems except that the systems will be pressurized with air rather than fluid. Code Case N-498-1, Alternative Rules for 70-Year System Hydrostatic Testing for Class 1, 2 and 3 Systems, has been approved for general use in Regulatory Guide 1.147, Revision

12. Therefore, considering the minimal amount of increased assurance provided by the increased pressure associated with a pneumatic test, that the licensee will be performing the pneumatic pressure tests at normal operating pressure (as allowed by Code Case N-498-1 for systems tested hydrostatically), and will be applying a bubble solution over the test boundary, it is concluded that the licensees proposed alternative provides an acceptable level of quality and safety. Therefore, it is recommended that the use of Code Case N-534 be authorized pursuant to 10 CFR 50.55a(a)(3)(i) for the second interval at Shearon Harris. The use of this Code Case should be authorized for the current interval or until such time as the Code Case is published in Regulatory Guide 1.147. At that time, if the licensee intends to continue to implement Code Case N-534, the licensee should follow all conditions specified in the Regulatory Guide, if present.

C. Re uest for Relief No. 2RG-006 Use of Code Case N-535 Alternative Re uirements for Inservice Ins ection Inter vals Code Re uirement: Paragraph IWA-2432 requires that successive inspection intervals be comprised of 10 years following the previous interval except as

modified by Paragraph IWA-2430(d), which allows an interval to be extended or reduced by as much as one year to coincide with an outage, thus changing the length of an interval.

Licensee's Pro osed Alternative: In accordance with 10 CFR 50.55a(a)(3), the licensee proposed to use Code Case N-535 as alternative requirements for scheduling the 10-year inspection interval. The licensee stated:

"Code Case N-535 is to be applied as an alternative for Interval extensions and modifications."

Licensee's Basis for Pro osed Alternative (as stated):

"ASME Section XI allows Interval extensions. Code Case N-535 simply provides additional guidance and clarification for a variety of situations that could arise at an operating plant."

Justification "The proposed alterrlative provides an acceptable level of quality and safety since Code Case N-535 simply provides additional guidance in order to clarify situations that are not explicitly described in the ASME Code Section XI."

Evaluation: Inspection Program B of the Code requires inspection intervals of 10 years in length, except as modified by IWA-2430(d), which allows an interval to be extended or reduced by as much as one year to coincide with an outage. The licensee proposes to apply the requirements of Code Case N-535 for the scheduling of intervals and examinations of Code Class 1, 2, and 3 piping and components.

Code Case N-535 consists of four parts which can be summarized as follows:

a) Each inspection interval may be reduced or extended by one-year. For extended intervals, neither the start or end dates nor the inservice inspection program for the successive interval need be revised. Thus, a successive interval may start prior to the end of the previous interval that was extended.

b) Examinations performed to satisfy the requirements of the extended interval may be performed in conjunction with examinations performed to satisfy the requirements for the successive interval. However, examinations cannot be credited to both intervals.

c) Inspection periods may be extended or reduced to coincide with an outage.

This adjustment shall not alter the requirements for scheduling inspection intervals.

d) Examination records must identify which interval the examination was performed in.

Part (a) of Code Case N-535 is the only change from current Section XI philosophy.

The one-year extension is independent of the plant operating cycle and two intervals can be open concurrently during that year. Although slightly different from the current Code requirements, implementation of this Code Case does not change the number of examinations, acceptance criteria, or any other Code requirement, with the possible exception of an insignificant change in the distribution of examinations. Therefore, the INEEL staff concludes that Code Case N-535 provides an acceptable level of quality and safety and recommends that the use of Code Case N-535 be authorized pursuant to 10 CFR 50.55a(a)(3)(i) for the second interval at Shearon Harris. The use of this Code Case should be authorized for the current interval or until such time as the Code Case is published in Regulatory Guide 1.147. At that time, if the licensee intends to continue to implement Code Case N-535, the licensee should follow all conditions specified in the Regulatory Guide, if present.

D. Re uest for Relief No. 2RG-007 Use of Code Case N-546 Alternative Re uirements for Qualification of VT-2 Examination Personnel Code Re uirement: Section XI, IWA-2300, requires that personnel performing VT-2 and VT-3 visual examinations be qualified in accordance with comparable levels of competency as defined in ANSI N45.2.6. Additionally, the examination personnel shall have natural or corrected near distance acuity, in at least one eye, equivalent to a Snellen fraction of 20/20. For far vision, personnel shall have natural or corrected far distance visual acuity of 20/30 or equivalent.

Licensee's Pro osed Alternative: In accordance with 10 CFR 50.55a(a)(3), the licensee proposed to use Code Case N-546 as an alternative to the ASME Section XI qualification requirements for VT-2 visual examiners. The licensee stated:

"Code Case N-546 is to be applied as an alternative for qualification of VT-2 personnel."

Licensee's Basis for Pro osed Alternative (as stated):

"Code Case N-546 has already been approved by the ASME Section XI Code Committee, thus providing an alternative to the qualification requirements contained in Section XI. In the Code Case, the Committee stated that the following alternative requirements apply:

(a) At least 40 hours4.62963e-4 days 0.0111 hours 6.613757e-5 weeks 1.522e-5 months plant walkdown experience, such as that gained by licensed and nonlicensed operators, local leak rate personnel, system engineers, and inspection and nondestructive examination personnel."

(b) At least 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months of training on Section XI requirements and plant specific procedures for VT-2 visual examination.

(c) Vision test requirements of IWA-2321, 1995 Edition of ASME Section XI.

"Implementation of the alternative qualification requirements provides an organized approach to ensure that VT-2 examinations are performed by personnel with an adequate knowledge base to consistently locate system leakage."

Justification "The proposed alternative provides an acceptable level of quality and safety since any system or component leakage would still be detected by trained, experienced, and qualified VT-2 personnel.

In the licensee's response to request for additional information, the licensee stated:

"1) CP8 L's Non-Destructive Examination (NDE) program is governed by the CPBL Corporate Nuclear NDE Manual. The Manual addresses the aspects of performance of NDE at HNP, including qualification, certification, training, examination procedures, etc.. Any person performing NDE at HNP must abide by the requirements of the Manual. This includes the requirements for performing VT-2 visual examinations. Plant Program procedures and Engineering Surveillance Test procedures delineate the ASME Section XI pressure test requirements of HNP.

"2) Records for persons qualified to perform VT-2 visual examinations at HNP are document and maintained in accordance with the CP8 L NDE program discussed in answer 1) above.

"3) Plant Program procedures and Engineering Surveillance Test procedures address the corrective action process for any. detected leakage at HNP. In accordance with these procedures, leakage detected during VT-2 examination is reviewed by the ISI pressure test coordinator and approved by the Authorized Nuclear Inservice Inspector."

Per telephone conversation on November 15, 1999, the licensee clarified/confirmed that an independent review and evaluation of detected leakage by persons other than those that performed the VT-2 visual examinations will be performed.

Evaluation: The Code requires that VT-2 visual examination personnel be qualified and certified in accordance with SNT-TC-1A. The Code also requires that the examination personnel be qualified for near and far distance vision acuity. In lieu of the Code requirements, the licensee proposed to implement Code Case N-546 for personnel performing VT-2 visual examinations, this Code Case includes the following requirements:

At least 40 hours4.62963e-4 days 0.0111 hours 6.613757e-5 weeks 1.522e-5 months plant walkdown experience, such as that gained by licensed and nonlicensed operators, local leak rate personnel, system engineers, and inspection and nondestructive examination personnel.

2. At least four hours of training on Section XI requirements and plant specific procedures for VT-2 visual examination.

3. Vision test requirements of IWA-2321, 1995 Edition.

The qualification requirements in Code Case N-546 are not significantly different from those for VT-2 visual examiner certification. Licensed and nonlicensed operators, local leak rate personnel, system engineers, and inspection and nondestructive examination personnel typically have a sound working knowledge of plant components and piping layouts. This knowledge makes them acceptable candidates for performing VT-2 visual examinations.

The NRC staff has determined that in order to find this Code Case acceptable for use, licensees must meet the following conditions:

1) Develop procedural guidelines for obtaining consistent, quality VT-2 visual examinations,

2) Document and maintain records to verify the qualification of persons selected to perform VT-2 visual examinations, and

3) Implement independent review and evaluation of detected leakage by persons other than those that performed the VT.-2 visual examinations.

In addition to meeting the requirements contained in Code Case N-546, the licensee has committed to use procedural guidelines for consistent, quality VT-2 visual examinations, verify and maintain records of the qualification of persons selected to perform VT-2 visual examinations, and perform independent reviews and evaluations of leakage by a person(s) other than those that performed the VT-2 visual examination. Based on a review of Code Case N-546 and the additional commitments made by the licensee, the INEEL staff believes that the proposed alternative to the Code requirements will provide an acceptable level of quality and safety. Therefore, it is recommended that the licensee's request to implement Code Case N-546 with the additional commitments be authorized pursuant to 10 CFR 50.55a(a)(3)(i) for the second interval at Shearon Harris. The use of this Code Case should be authorized for the current interval or until such time as the Code Case is published in Regulatory Guide 1.147. At that time, if the licensee intends to continue to implement Code Case N-546, the licensee should follow all conditions specified in the Regulatory Guide, if present.

CONCLUSION The INEEL staff evaluated the licensee's submittal and concludes that for Requests for Relief 2RG-004, 2RG-005, 2RG-006 and 2RG-007 the licensee's proposed alternatives, to implement Code Cases N-532, N-534, N-535 and N-546, will provide an acceptable level of quality and safety. Therefore, it is recommended that these proposed alternatives be authorized for the second interval pursuant to 10 CFR 50.55a(a)(3)(i).

The use of these Code Case should be authorized for the current interval or until such time as they are published in Regulatory Guide 1.147. At that time, if the licensee intends to continue to implement the subject Code Cases, the licensee should follow all conditions specified in the Regulatory Guide, if present.

'0 T

Mr. James Scarola Shearon Hai is Nuclear Power Plant Carolina Power 8 Light Company Unit 1 CC:

Mr. William D. Johnson Mr. Chris L. Burton Vice President and Corporate Secretary Director of Site Operations Carolina Power & Light Company Carolina Power & Light Company Post Office Box 1551 Shearon Harris Nuclear Power Plant Raleigh, North Carolina 27602 Post Office Box 165, MC: Zone 1 New Hill, North Carolina 27562-0165 Resident Inspector/Harris NPS c/o U.S. Nuc1ear Regulatory Commission Mr. Robert P. Gruber 5421 Shearon Harris Road Executive Director New Hill, North Carolina 27562-9998 Public Staff NCUC Post Office Box 29520 Ms. Karen E. Long Raleigh, North Carolina 27626 Assistant Attorney General State of North Carolina Chairman of the North Carolina Post Office Box 629 Utilities Commission Raleigh, North Carolina 27602 Post Office Box 29510 Raleigh, North Carolina 27626-0510 Public Service Commission State of South Carolina Post Office Drawer Columbia, South Carolina 29211 Mr. Vernon Malone, Chairman Board of County Commissioners of Wake County P. O. Box 550 Mr. Mel Fry, Director Raleigh, North Carolina 27602 Division of Radiation Protection N.C. Department of Environment and Natural Resources 3825 Barrett Dr. Mr. Richard H. Givens, Chairman Raleigh, North Carolina 27609-7721 Board of County Commissioners of Chatham County P. O. Box 87 Mr. Terry C. Morton Pittsboro, North Carolina 27312 Manager Performance Evaluation and Ms. Donna B. Alexander, Manager Regulatory Affairs CPB 7 Regulatory Affairs Carolina Power 8 Light Company Carolina Power 8 Light Company Post Office Box 1551 Shearon Harris Nuclear Power Plant Raleigh, North Carolina 27602-1551 P.O. Box 165, Mail Zone 1 New Hill, NC 27562-0165 Mr. Bo Clark Plant General Manager - Harris Plant Mr. Johnny H. Eads, Supervisor Carolina Power & Light Company Licensing/Regulatory Programs Shearon Harris Nuclear Power Plant Carolina Power & Light Company P.O. Box 165 Shearon Harris Nuclear Power Plant New Hill, North Carolina 27562-0165 P. O. Box165, Mail Zone 1 New Hill, NC 27562-0165 Mr. John H. O'eill, Jr.

Shaw, Pittman, Potts 8 Trowbridge 2300 N Street, NW.

Washington, DC 20037-1128

0 0 h

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'otal Copies:

Item: ADAMS Document Library: ML ADAMS"HQNTAD01 ID: 993210046

Subject:

SHEARON HARRIS NUCLEAR POWER PLANT, UNIT 1 - REVISIONS TO THE UFSAR - PA ST AND FUTURE, COMPLIANCE WITH 10 CFR 50.71(e)(4)

Body:

PDR ADOCK 05000400 P Docket: 05000400, Notes: Application for permit renewal filed.

Page 1

II RECII (4gpR Cg A, UNITED STATES n

p I- 0 NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001

~O November 4, 1999

+>>*<<<<

Mr. James Scarola, Vice President Shearon Harris Nuclear Power Plant Carolina Power 8 Light Company Post Office Box 165, Mail Code: Zone 1 New Hill, North Carolina 27562-0165

SUBJECT:

SHEARON HARRIS NUCLEAR POWER PLANT, UNIT 1 - REVISIONS TO THE UFSAR - PAST AND FUTURE COMPLIANCE WITH 10 CFR 50.71(e)(4)

Dear Mr. Scarola:

Title 10 of the Code of Federal Regulations (10 CFR), Subsection 50.71(e)(4) specifies the schedular requirements whereby licensees are to submit revisions to their Updated Final Safety Analysis Reports (UFSARs). It requires revisions to be made "....annually or 6 months after each refueling outage provided the interval between successive updates does not exceed 24 months." In a 1997 survey we found numerous incidents of noncompliance by licensees of both single- and multi-unit plants with this schedular requirement. In many cases, licensees for multi-unit sites were basing their UFSAR submissions on the outage schedule of one unit.

We understand that some confusion about the proper interpretation of 10 CFR 50.71(e)(4) may have been caused by an NRC staff letter to Commonwealth Edison Company (ComEd) dated June 15, 1993, which endorsed a submission schedule proposed by ComEd for its plants.

Neither ComEd's proposed schedule nor the staff's endorsement were in literal compliance with 10 CFR 50.71(e)(4). Nevertheless, many licensees adopted the staff position expressed in the June 15, 1993, letter and thus deviated from the schedular requirements of this regulation.

Recently, the staff granted exemptions to the ComEd plants. The transmittal letter (D. Skay to O. D. Kingsley, dated July 27, 1999) states that "this [Skay] letter and the enclosed exemptions supersede our letter of June 15, 1993."

We note that you have not requested a schedular exemption to 10 CFR 50.71(e)(4) for the Harris Nuclear Plant (HNP). This may indicate that either you intend to comply with the correct interpretation of the regulation, or you may have incorrectly interpreted the regulation in the past. The purpose of this letter is to clarify any misunderstanding of this regulation. We will exercise enforcement discretion, in accordance with Section VII.B.6 of the NRC Enforcement Policy, for any incidents of past violation of 10 CFR 50.71(e)(4). In the future we will enforce the schedular requirements as prescribed, or as modified by an exemption for HNP.

PDR c [e, gag Ql oo A zoo

J. Scarola r There is no need to respond to this letter. If you have any questions, please call me at 301-415-1373.

Sincerely, Or iginal signed by:

Richard J. Laufer, Project Manager, Section 2 Project Directorate II Division of Licensing Project Management Office of Nuclear Reactor Regulation Docket No. 50-400 cc: See next page Distribution Docket File . EDunnington PUBLIC HBerkow PTam (email)

PD II:2 Rdg OGC JZwolinski/SBlack ACRS BBonser, Rll FILENAME - G:hPDII-2EHARRIS55071eLTR.w d OFFICE PM:PDII/S2 LA:PDII/S2 A SC:PDII/S2 NAME RLaufer W EDunnn fon KJabbour DATE Ii/ t /99 b/G/99 I 7/k/99 / /99 COPY e /No es/ o Yes/No Yes/No OFFICIAL RECORD COPY

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J. Scarola There is no need to respond to this letter. If you have any questions, please call me at 301-415-1373.

Sincerely, Richard J. Laufer, Project Manager, Section 2 Project Directorate II Division of Licensing Project Management Office of Nuclear Reactor Regulation Docket No. 50-400 cc: See next page

Mr. James Scarola Shearon Harris Nuclear Power Plant Garolink Power 8 Light Company Unit 1 CC: I Mr. William D. Johnson Mr. Chris L. Burton Vice President and Corporate Secretary Director of Site Operations Carolina Power 8 Light Company Carolina Power 8 Light Company Post Office Box 1551 Shearon Harris Nuclear Power Plant Raleigh, North Carolina 27602 Post Office Box 165, MC: Zone 1 New Hill, North Carolina 27562-0165 Resident Inspector/Harris NPS c/o U.S. Nuclear Regulatory Commission Mr. Robert P. Gruber 5421 Shearon Harris Road Executive Director NewiHill, North Carolina 27562-9998 Public Staff NCUC Post Office Box 29520 Ms. Karen E. Long Raleigh, North Carolina 27626 Assistant Attorney General State 'of North Carolina Chairman of the North Carolina Post Office Box 629 Utilities Commission Raleigh, North Carolina 27602 Post Office Box 29510 Raleigh, North Carolina 27626-0510 Public Service Commission State of South Carolina Post Office Drawer Columbia, South Carolina 29211 Mr. Vernon Malone, Chairman Board of County Commissioners of Wake County P. O. Box 550 Mr. Mel Fry, Director Raleigh, North Carolina 27602 Division of Radiation Protection N.C. Department of Environment and Natural Resources 3825 Barrett Dr. Mr. Richard H. Givens, Chairman Raleigh, North Carolina 27609-7721 Board of County Commissioners of Chatham County P. O. Box 87 Mr. Terry C. Morton Pittsboro, North Carolina 27312 Manager Performance Evaluation and Ms. Donna B. Alexander, Manager Regulatory Affairs CPB 7 Regulatory Affairs Carolina Power 8 Light Company Carolina Power 8 Light Company Post Office Box 1551 Shearon Harris Nuclear Power Plant Raleigh, North Carolina 27602-1551 P.O. Box 165, Mail Zone 1 New Hill, NC 27562-0165 Mr. Bo Clark Plant General Manager - Harris Plant Mr. Johnny H. Eads, Supervisor Carolina Power 8 Light Company Licensing/Regulatory Programs Shearon Harris Nuclear Power Plant Carolina Power & Light Company P.O. Box 165 Shearon Harris Nuclear Power Plant New Hill, North Carolina 27562-0165 P. O. Box165, Mail Zone 1 New Hill, NC 27562-0165 Mr. John H. O'eill, Jr.

Shaw, Pittman, Potts 8 Trowbridge 2300 N Street, NW.

Washington, DC 20037-1128

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Body:

Docket: 05000400, Notes: Application for permit renewal filed.

Page 1

November 999 Ivlr. James Scarola, Vice President Shearon Harris Nuclear Power Plant Carolina Power 8 Light Company PostOffice Box165, Mail Code: Zone1 New Hill, North Carolina 27562-0165

SUBJECT:

EVALUATIONOF RELIEF REQUEST 2R2-008 RELATED TO CLASS 2 BOLTED CONNECTIONS IN BORATED SYSTEMS - SHEARON HARRIS NUCLEAR POWER PLANT (TAC NO. MA6453)

Dear Mr. Scarola:

By letter dated September 8, 1999, you submitted relief request 2R2-008 for relief from certain requirements of the 1989 Edition of the American Society of Mechanical Engineers (ASME)

Code,Section XI for the Harris Nuclear Plant (HNP). Specifically, you requested relief from the Section XI, IWA-5242(a) requirement to remove insulation from pressure-retaining bolted connections in borated systems for VT-2 visual examination during the performance of system pressure testing.

The staff has reviewed and evaluated relief request 2R2-008 as documented in the enclosed Safety Evaluation. The staff has determined that the proposed alternative will provide a reasonable assurance of operational readiness,"and that compliance with the existing requirement would result in hardship or unusual difficultywithout a compensating increase in the level of safety. Accordingly, the request for relief is authorized pursuant to 10 CFR 50.55a(a)(3)(ii) for the second 10-year inspection interval.

Sincerely, Original, signed by:

Kahtan N'. Jabbour, Acting 'Chief, Section 2 Project Directorate II Division of Licensing Project Management Office of'Nuclear Reactor Regulation Docket No. 50-400

Enclosure:

Safety Evaluation

~

cc: See next page @j(AV Distribution:

~ Docket File, 'D PUBLIC HBerkow BBonser, Rll II Rdg OGC JZwolinskilSBIack ACRS FILENAME-G:KPDII-2KHARRISLRRMA6453.WPD *see revious concurrence OFFICE PM:PDII/S2 LA:PDII/S2 EMCB QGG A SC:PDII/S2 D:PB 0 /

NAME RLaufer EDunn on Esullivan RBachm KJabbour HBe w

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l O NUCLEAR REGULATORY COMMISSION lh WASHINGTON, D.C. 20555-0001 November 1, 1999

++*++

Mr. James Scarola, Vice President Shearon Harris Nuclear Power Plant Carolina Power & Light Company Post Office Box 165, Mail Code: Zone 1 New Hill, North Carolina 27562-0165

SUBJECT:

EVALUATIONOF RELIEF REQUEST 2R2-008 RELATED TO CLASS 2 BOLTED CONNECTIONS IN BORATED SYSTEMS - SHEARON HARRIS NUCLEAR POWER PLANT (TAC NO. MA6453)

Dear Mr. Scarola:

By letter dated September 8, 1999, you submitted relief request 2R2-008 for relief from certain requirements of the 1989 Edition of the American Society of Mechanical Engineers (ASME)

Code,Section XI for the Harris Nuclear Plant (HNP). Specifically, you requested relief from the Section XI, IWA-5242(a) requirement to remove insulation from pressure-retaining bolted connections in borated systems for VT-2 visual examination during the performance of system pressure testing.

The staff has reviewed and evaluated relief request 2R2-008 as documented in the enclosed Safety Evaluation. The staff has determined that the proposed alternative will provide a reasonable assurance of operational readiness, and that compliance with the existing requirement would result in hardship or unusual difficultywithout a compensating increase in the level of safety. Accordingly, the request for relief is authorized pursuant to 10 CFR 50.55a(a)(3)(ii) for the second 10-year inspection interval.

Sincerely, Kahtan N. Jabbour, Acting Chief, Section 2 Project Directorate II Division of Licensing Project Management Office of Nuclear Reactor Regulation Docket No. 50-400

Enclosure:

Safety Evaluation cc: See next page

'Mr. James Scarola Shearon Harris Nuclear Power Plant Carolina Power 8 Light Company Unit 1 CC Mr. William D. Johnson Mr. Chris L. Burton Vice President and Corporate Secretary Director of Site Operations Carolina Power 8 Light Company Carolina Power & Light Company Post Office Box 1551 Shearon Harris Nuclear Power Plant Raleigh, North Carolina 27602 Post Office Box 165, MC: Zone 1 New Hill, North Carolina 27562-0165 Resident Inspector/Harris NPS c/o U.S. Nuclear Regulatory Commission Mr. Robert P. Gruber 5421 Shearon Harris Road Executive Director New Hill, North Carolina 27562-9998 Public Staff NCUC Post Office Box 29520 Ms. Karen E. Long Raleigh, North Carolina 27626 Assistant Attorney General State of North Carolina Chairman of the North Carolina Post Office Box 629 Utilities Commission Raleigh, North Carolina 27602 Post Office Box 29510 Raleigh, North Carolina 27626-0510 Public Service Commission State of South Carolina Post Office Drawer Columbia, South C'arolina 29211 Mr. Vernon Malone, Chairman Board of County Commissioners of Wake County P. O. Box 550 Mr. Mel Fry, Director Raleigh, North Carolina 27602 Division of Radiation Protection N.C. Department of Environment and Natural Resources 3825 Barrett Dr. Mr. Richard H. Givens, Chairman Raleigh, North Carolina 27609-7721 Board of County Commissioners of Chatham County P. O. Box 87 Mr. Terry C. Morton Pittsboro, North Carolina 27312 Manager Performance Evaluation and Ms. Donna B. Alexander, Manager Regulatory Affairs CPB 7 Regulatory Affairs Carolina Power & Light Company Carolina Power 8 Light Company Post Office Box 1551 Shearon Harris Nuclear Power Plant Raleigh, North Carolina 27602-1551 P.O. Box 165, Mail Zone 1 New Hill, NC 27562-0165 Mr. Bo Clark Plant General Manager - Harris Plant Mr. Johnny H. Eads, Supervisor Carolina Power 8 Light Company Licensing/Regulatory Programs Shearon Harris Nuclear Power Plant Carolina Power 8 Light Company P.O. Box 165 Shearon Harris Nuclear Power Plant New Hill, North Carolina 27562-0165 P. O. Box165, Mail Zone1 New Hill, NC 27562-0165 Mr. John H. O'eill, Jr.

Shaw, Pittman, Potts 8 Trowbridge 2300 N Street, NW.

Washington, DC 20037-1128

r

,, UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON> D.C. 20555-0001 "

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+~ ~0

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SAFETY EVALUATIONBY THE OFFICE OF NUCLEAR REACTOR REGULATION RELIEF RE VEST 2R2-008 RELATED TO CLASS 2 BOLTED CONNECTIONS IN BORATED SYSTEMS CAROLINA POWER 8 LIGHT COMPANY SHEARON HARRIS NUCLEAR POWER PLANT DOCKET NO. 50-400

1.0 INTRODUCTION

The Technical Specifications (TS) for the Shearon Harris Nuclear Power Plant (HNP) state that the inservice inspection (ISI) of the American Society of Mechanical Engineers (ASME) Code Class 1, 2, and 3 components will be performed in accordance with Section XI, "Rules for Inservice Inspection of Nuclear Power Plant Components," of the ASME Boiler and Pressure Vessel Code (ASME Code) -nd applicable addenda as required by Title 10 of the Code of Federal Regulations (10 CFR) Section 50.55a(g), except where specific written relief has been granted by the Commission pursuant to 10 CFR 50.55a(g)(6)(i). Section 50.55a(a)(3) states that alternatives to the requirements of paragraph (g) may be used, when authorized by the NRC, if: (i) the proposed alternatives would provide an acceptable level of quaJity and safety, or (ii) compliance with the specified requirements would result in hardship or unusual difficulty without a compensating. increase in the level of quality and safety.

Pursuant to 10 CFR 50.55a(g)(4), ASME Code Class 1, 2, and 3 components (including supports) will meet the requirements, except the design and access provisions and the preservice examination requirements, set forth in the ASME Code,Section XI, to the extent practical within the limitations of design, geometry, and materials of construction of the components. The regulations require that inservice examination of components and system pressure tests conducted during the first 10-year interval and subsequent intervals comply with the requirements in the latest edition and addenda of Section XI of the ASME Code incorporated by reference in 10 CFR 50.55a(b) 12 months prior to the'start of the 120-month interval, subject to the limitations and modifications listed therein. The applicable edition of Section XI of the ASME Code for HNP's 2nd 10-year ISI interval is the 1989 Edition.

Pursuant to 10 CFR 50.55a(g)(5), if the licensee determines that conformance with an examination requirement of Section XI of the ASME Code is not practical for its facility, information will be submitted to the Commission in support of that determination and a request must be made for relief from the ASME Code requirement. After evaluation of the determination, pursuant to 10 CFR 50.55a(g)(6)(i), the Commission may grant. relief and/or may impose alternative requirements that are determined to be authorized by law, will not endanger life, property, or the common defense and security, and are otherwise in the public interest, giving due consideration to the burden upon the licensee that could result if the requirements were imposed.

Enclosure Q '330 ao54

By letter dated September 8, 1999, Carolina Power 8 Light Company (CPB L), the HNP licensee, requested relief from the requirements of ASME Code, 1989 Edition,Section XI, Article IWA-5242(a) with regard to removing insulation from Class 2 pressure-retaining bolted connections in borated systems for VT-2 visual examination during the performance of system pressure testing.

2.0 EVALUATION 2.1 Code Re uirement The ASME Code Section XI, 1989 Edition with no Addenda, IWA-5242(a) requires that for systems borated for the purpose of controlling reactivity, the insulation must be removed from pressure-retaining bolted connections in order to perform VT-2 visual examinations during system pressure testing.

2.2 Code Re uirement from which relief is re uested as stated Relief is requested from the Code Section XI, IWA-5242(a) requirement for Class 2 pressure retaining bolted connections in borated systems.

2.3 Com onents for which relief is re uested as stated Class 2 pressure retaining bolted connections in systems borated for the purpose of controlling reactivity that are located inside containment.

2.4 Basis for Relief as stated Pursuant to 10 CFR 50.55a(a)(3)(ii), relief is requested on the basis that compliance with the original examination requirements would result in hardship or unusual difficulty without a compensating increase in the level of quality and safety.

Inside containment, the referenced systems are tested in an environment that is hazardous to personnel. Removing and reinstalling insulation under these conditions is difficult to perform and is not consistent with the ALARA[as low as reasonably achievable] concept when compared to the alternate approach. In addition, the removal and reinstallation of insulation is often a critical path activity which directly affects the duration of refueling outages, therefore placing a financial hardship on the plant.

The concern that led to the Section XI requirement for removal of insulation on bolted connections, while performing pressure testing and VT-2 examinations, is that a borated-water leak from a bolted connection could cause corrosion of the bolting materials. The weakening of the bolting could be hidden by the insulation if it were not removed. Thus, the structural integrity of a safety-related system could be compromised by a small leak that could be unnoticed if the insulation remains in place during the pressure testing and VT-2 examination.

This relief request addresses the structural integrity concerns while mitigating the personnel hazards and reducing the critical path impact of the testing. It divides the pressure testing and

the VT-2 examination into two activities that need not be performed at the same time. The =

proposed alternate examination is supported by the follow'ing:

(a) ASME Code Case N-533 was approved by the Section XI Code Committee, thus providing an alternative to the similar requirement for examination of insulated Class 1 pressure retaining bolted connections.

(b) By letter dated November 4, 1998 (TAC No. MA0989), the NRC approved HNP relief request 2R1-010 for Class 1 bolted connections.

(c) Similar relief requests have been approved by the NRC for other nuclear power plants (Virgil C. Summer Nuclear Station and Surry Power Station).

(d) Pre-existing boric acid leaks will be detected at atmospheric or static pressures due to residue deposits.

(e) The alternative test will not be applied to post repair/replacement activities on bolted connections.

2.5 Alternative Examinations as stated The following alternate rules for the pressure testing and VT-2 visual examination of Class 2 pressure retaining bolted connections will be used:

(a) A system pressure test and VT-2 visual examination shall be performed each inspection period without removal of insulation.

(b) The insulation shall be removed from the bolted connections each inspection period, and a VT-2 visual examination shall be performed. The connections are not required to be pressurized. Any evidence of leakage shall be evaluated in accordance with the requirements specified in HNP relief request 2RG-009, which was approved by the NRC by letter dated November 4, 1998.

[Specifically, relief request 2RG-009 states: "The source of leakage at bolted connections detected by VT-2 examination during system pressure tests shall be located and evaluated for corrective measures. This evaluation will consider the following variables at a minimum: (1)

Location of leakage, (2) History of leakage, (3) Fastener materials, (4) Evidence of corrosion, with the connection assembled, (5) Corrosiveness of the process fluid, and (6) Other components in the vicinity that may be degraded due to the leakage.

"When the evaluation of the above variables is concluded and the evaluation determines that the leaking condition has not degraded the fasteners, then no further action is necessary. However, reasonable attempts to stop the leakage shall be taken.

"If the evaluation of the variables above indicates the need for further evaluation, or no evaluation is performed, then a bolt closest to the source of leakage shall be removed. The bolt will receive a VT-1 examination and be evaluated for corrosion in accordance with IWA-3100(a) and dispositioned in accordance with IWB-3140. When the removed bolting shows evidence of

4 rejectable degradation, all remaining bolts shall be removed and receive a VT-1 examination and evaluation in accordance with IWB-3140. If the leakage is identiTied when the bolted connection is in service, and the information in the evaluation is supportive, the removal of the bolt for VT-1 examination may be deferred to the next refueling outage."J 2.6 Staff Evaluation The Code requires the removal of all insulation from pressure-retaining bolted connections in systems borated for the purpose of controlling reactivity when performing VT-2 visual examinations during system pressure tests: For Class 1 systems, the Code requires this examination each refueling outage, while Class 2 systems are required to receive this examination each inspection period. As an alternative to the Code requirements, the licensee has proposed separating the requirements for a VT-2 examination with insulation removed from the pressure test requirement. The proposed alternative mitigates the safety hazard due to elevated temperatures and excess radiation exposure to plant personnel encountered when adhering to the Code requirement. The proposed alternative is consistent with the requirements of Code Case N-533, "Alternative Requirements for VT-2 Visual Examination of Class 1 Insulated Pressure Retaining Bolted Connections,"Section XI, Division 1. The NRC approved the use of this Code Case at HNP for Class 1 systems in relief request 2R1-010 issued on.

November 4, 1998.

The licensee's proposed alternative for Class 2 systems provides an acceptable approach to ensuring the leaktight integrity of systems borated for the purpose of controlling reactivity. The two-step approach will provide an acceptable level of quality and safety for bolted connections in Class 2 borated systems. The insulated Class 2 bolted connections will still receive pressure testing and VT-2 visual examinations each inspection period. No changes are being made to the areas that are inspected, the inspection criteria, or the VT-2 personnel qualifications. The staff, therefore, finds the proposed alternative acceptable.

3.0 CONCLUSION

Based on the information provided, the staff has determined that the licensee has presented an adequate justification for the relief request from the requirements of ASME Code 1989 Edition,Section XI, Article IWA-5242(a) with regard to removing insulation from Class 2 pressure-retaining bolted connections in borated systems for VT-2 visual examination during the performance of system pressure testing. The staff has determined that compliance with the original examination requirements would result in hardship or unusual difficulty for the licensee without'a compensating increase in the level of quality and safety. Therefore, the licensee's relief request 2R2-008 is authorized, pursuant to 10 CFR 50.55a(a)(3)(ii), for the second 10-year interval of the HNP ISI program.

Principal Contributor: R. Laufer Date: November 1, 1999

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ML18016B013

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