Text

Proposed License Amendment Request Consolidated Line Item Improvement Process Technical Specification Improvement Regarding Steam Generator Tube Integrity
	ML061430062
Person / Time
Site:	North Anna
Issue date:	05/22/2006
From:	Grecheck E; Virginia Electric & Power Co (VEPCO)
To:	; Document Control Desk, Office of Nuclear Reactor Regulation
References
	06-403
	Download: ML061430062 (89)
	v • d • e

VIRGINIA ELECTRIC AND POWER COMPANY RIC~MOND, VIRGINIA 23261 May 22, 2006 U.S. Nuclear Regulatory Commission Attention: Document Control Desk Washington, D.C. 20555 Serial No.06-403 NL&OS/ETS RO Docket Nos. 50-3381339 License Nos. NPF-417 NORTH ANNA POWER STATION UNITS 1 AND 2 PROPOSED LICENSE AMENDMENT REQUEST CONSOLIDATED LINE ITEM IMPROVEMENT PROCESS TECHNICAL SPECIFICATION IMPROVEMENT REGARDING STEAM GENERATOR TUBE INTEGRITY Pursuant to 10 CFR 50.90, Virginia Electric and Power Company (Dominion) requests amendments, in the form of changes to the Technical Specifications (TS) to Facility Operating License Numbers NPF-4 and NPF-7 for North Anna Power Station Units 1 and 2, respectively. The proposed amendment would revise the TS requirements related to steam generator tube integrity. The changes are consistent with NRC-approved Revision 4 to Technical Specification Task Force (TSTF) Standard Technical Specification Change Traveler, TSTF-449, "Steam Generator Tube Integrity."

The availability of this TS improvement was announced in the Federal Register on May 6, 2005 (70 FR 24126) as part of the consolidated line item improvement process (CLIIP). A discussion of the proposed TS changes is provided in Attachment 1. The marked-up and proposed TS pages are provided in Attachments 2 and 3, respectively.

The associated Bases changes are provided in Attachments 4 and 5 for information only and will be implemented in accordance with the TS Bases Control Program and 10 CFR 50.59.

The proposed changes have been reviewed and approved by the Station Nuclear Safety and Operating Committee.

Dominion requests approval of the license amendments by March 31, 2007 with a 180-day implementation period.

If you have any questions or require additional information, please contact Mr. Thomas Shaub at (804) 273-2763.

Very truly yours, Eugene S. Grecheck Vice President - Nuclear Support Services

Attachments

1. Description and Assessment

2. Mark-up of Technical Specifications Changes

3. Proposed Technical Specifications Changes

4. Mark-up of Technical Specifications Bases Changes

5. Proposed Technical Specifications Bases Changes Commitments made in this letter: None cc:

U.S. Nuclear Regulatory Commission Region II Sam Nunn Atlanta Federal Center 61 Forsyth Street, SW Suite 237185 Atlanta, Georgia 30303 Mr. J. E. Reasor, Jr.

Old Dominion Electric Cooperative lnr~sbrook Corporate Center 4201 Dominion Blvd.

Suite 300 Glen Allen, Virginia 23060 Commissioner Bureau of Radiological Health 15100 East Main Street Suite 240 Richmond, Virginia 2321 8 Mr. J. T. Reece NFlC Senior Resident Inspector North Anna Power Station Mr. S. R. Monarque NHC Project Manager U. S. Nuclear Regulatory Commission On~e White Flint North 1 1 555 Rockville Pike Mail Stop 8-HI 2 Rockville, MD 20852 Serial No.06-403 Docket Nos. 50-3381339 Page 2 of 3

Serial No.06-403 Docket Nos. 50-3381339 Page 3 of 3 COMMONWEALTH OF VIRGINIA

)

1 COUNTY OF HENRICO 1

The foregoing document was acknowledged before me, in and for the County and Commonwealth aforesaid, today by Eugene S. Grecheck, who is Vice President -

Nuclear Support Services, of Virginia Electric and Power Company. He has affirmed before me that he is duly authorized to execute and file the foregoing document in behalf of that Company, and that the statements in the document are true to the best of his knowledge and belief.

n Acknowledged before me this~~?%'da~ of 2006.

My Commission Expires:

(SEAL)

Serial No.06-403 Docket Nos. 50-3381339 Description and Assessment North Anna Power Station Units 1 and 2 Virginia Electric and Power Company (Dominion)

Serial No.06-403 Docket Nos. 50-3381339 Description and Assessment

1.0 INTRODUCTION

The proposed license amendment revises the requirements in Technical Specifications (TS) related to steam generator tube integrity. The changes are consistent with NRC approved Technical Specification Task Force (TSTF) Standard Technical Specification Change Traveler, TSTF-449, "Steam Generator Tube Integrity," Revision 4.

The availability of this technical specification improvement was announced in the Federal Register on May 6, 2005 as part of the consolidated line item improvement process (CLI I P).

2.0 DESCRIPTION

OF PROPOSED AMENDMENT Consistent with the NRC-approved Revision 4 of TSTF-449, the proposed TS changes include:

Revised TS definition of LEAKAGE Revised TS 3.4.1 3, "RCS [Reactor Coolant System] Operational Leakage" New TS 3.4.20, "Steam Generator (SG) Tube Integrity" Revised TS 5.5.8, "Steam Generator (SG) Program" Revised TS 5.6.7, "Steam Generator Tube Inspection Report" Proposed revisions to the TS Bases are also included in this application. As discussed in the NRC's model safety evaluation, adoption of the revised TS Bases associated with TSTF-449, Revision 4 is an integral part of implementing this TS improvement.

The changes to the affected TS Bases pages will be incorporated in accordance with the TS Bases Control Program after approval of the license amendment.

3.0 BACKGROUND

The back.ground for this application is adequately addressed by the NRC Notice of Availability published on May 6, 2005 (70 FR 24126), the NRC Notice for Comment published1 on March 2, 2005 (70 FR 10298)) and TSTF-449, Revision 4.

4.0 REGULATORY REQUIREMENTS AND GUIDANCE The applicable regulatory requirements and guidance associated with this application are adequately addressed by the NRC Notice of Availability published on May 6, 2005 (70 FR 24126), the NRC Notice for Comment published on March 2, 2005 (70 FR 10298), and TSTF-449, Revision 4.

5.0 TECHNICAL ANALYSIS

Virginia Electric and Power Company (Dominion) has reviewed the safety evaluation (SE) published on March 2, 2005 (70 FR 10298) as part of the CLllP Notice for Comment. This included the NRC staff's SE, the supporting information provided to support TSTF-449, and the changes associated with Revision 4 to TSTF-449.

Page 1 of 3

Serial No.06-403 Docket Nos. 50-3381339 Dominion has concluded that the justifications presented in the TSTF proposal and the SE prepared by the NRC staff are applicable to North Anna Power Station Units 1 and 2 and justify this amendment for the incorporation of the changes to the North Anna Units 1 and 2 TS.

6.0 REGULATORY ANALYSIS

A description of this proposed change and its relationship to applicable regulatory requirements and guidance was provided in the NRC Notice of Availability published on May 6, 2005 (70 FR 24126), the NRC Notice for Comment published on March 2, 2005 (70 FR 10298), and TSTF-449, Revision 4.

6.1 Verification and Commitments The following information is provided to support the NRC staff's review of this amendment application:

Plant Name, Unit No.

Steam Generator Model(s):

Effective Full Power Years (EFPY) of service for currently installed SGs Tubing Material Number of tubes per SG Number and percentage of tubes plugged in each SG Number of tubes repaired in each SG Current primary to secondary leakage limits:

Leakage is evaluated at what temperature condition?

Approved Alternate Tube Repair Criteria (ARC) :

Approved SG Tube Repair Methods Performance criteria for accident leakage North Anna Power Station (NAPS) Units 1 and 2 Westinghouse Model 54F; 3-Loop NAPS 1 11.9 EFPY at last inspection in spring 2006 NAPS 2 9.1 EFPY at last inspection in fall 2005 NAPS 1 NAPS 2 SG A - 0 (0.00%)

SG A - 1 (0.03%)

TS Admin. Control Limit Per SG:

50rgpd 50 gpd Total:

1 gPm 150 gpd At room temperature (~70°F) and normal atmosphere pressure 11 4.7/in2 \\

None None Primary to secondary leak rate values assumed in licensing basis accident analysis, including assumed temperature conditions.

1 gpm total SG leakage at room temgerature (~70°F) and normal atmosphere pressure (l4.7lin )

Page 2 of 3

Serial No.06-403 Docket Nos. 50-3381339 7.0 NO SIGNIFICANT HAZARDS CONSIDERATION Dominion has reviewed the proposed no significant hazards consideration determination published on March 2, 2005 (70 FR 10298) as part of the CLIIP.

Dominior~ has concluded that the proposed determination presented in the notice is applicable to North Anna Power Station Units 1 and 2 and the determination is hereby incorporated by reference to satisfy the requirements of 10 CFR 50.91 (a).

8.0 ENVIRONMENTAL EVALUATION Dominior~ has reviewed the environmental evaluation included in the model SE published on March 2, 2005 (70 FR 10298) as part of the CLIIP.

Dominion has concluded that the staff's findings presented in that evaluation are applicable to North Anna Power Station Units 1 and 2, and the evaluation is hereby incorporated by reference for this application.

9.0 PRECEDENT This application is being made in accordance with the CLIIP. Dominion is not proposing variations or deviations from the TS changes described in TSTF-449, Revision 4, or the NRC staff's model SE published on March 2, 2005 (70 FR 10298).

10.0 REFERENCES

Federal Register Notices:

Notice for Comment published on March 2, 2005 (70 FR 10298)

Notice of Availability published on May 6, 2005 (70 FR 241 26)

Page 3 of 3

Serial No.06-403 Docket Nos. 50-3381339 Mark-up of Technical Specifications Changes North Anna Power Station Units 1 and 2 Virginia Electric and Power Company (Dominion)

CONTAINMENT SYSTEMS................... 3.6.1.1 Containment..................... 3.6.1.1 Containment A i r Locks................ 3.6.2.1 Containment I s o l a t i o n Valves............ 3.6.3.1 Containment Pressure................ 3.6.4.1 Containment A i r Temperature............. 3.6.5.1 Quench Spray (QS) System.............. 3.6.6. 1 Recirculation Spray (RS) System........... 3.6.7.1 Chemical Addition System.............. 3.6.8.1 25 TECHNICAL SPECIFICATIONS TABLE OF CONTENTS 3.4 REACTOR COOLANT SYSTEM (RCS) (continued) 3.4.10 Pressurizer Safety Valves..............3.4.1 0-1 3.4.11 Pressurizer Power Operated Re1 i e f Valves (PORVS).....................3.4.1 1-1 3.4.12 Low Temperature Overpressure Protection (LTOP)

System.....................3.4.1 2.1 3.7 PLANT SYSTEMS 3.7.1.1 3.7.1 Main Steam Safety Valves (MSSVs) 3.7.1.1 3.7.2 Main Steam T r i p Valves (MSTVs) 3.7.2.1 3.7.3 Main Feedwater Is01 a t i o n Valves (MFIVs). Main Feedwater Pump Di scharge Val ves (MFPDVs).

Main Feedwater Regulating Valves (MFRVs).

and Main Feedwater Regul a t i ng Bypass Valves (MFRBVS).................... 3.7.3.1 3.7.4 Steam Generator Power Operated Re1 i e f Valves (SG PORVS)................... 3.7 1 3.7.5 Auxi 1 i a r y Feedwater (AFW) System.......... 3.7.5.1 3.7.6 Emergency Condensate Storage Tank (ECST)...... 3.7.6.1 3.7.7 Secondary Speci fi c A c t i v i ty............. 3.7.7.1 3.7.8 Service Water (SW) System.............. 3.7.8.1 3.7.9 Ultimate Heat Sink (UHS).............. 3.7.9.1 North Anna U n i t s 1 and 2 i i 3.4.13 RCS Operational LEAKAGE...............3.4.1 3-1 3.4.14 RCS Pressure I s o l a t i o n Valve (PIv)

Leakage.....3.4.1 4-1 3.4.15 RCS Leakage Detection Instrumentation........3.4.1 5-1 3.4.16 RCS S p e c i f i c A c t i v i t y................3.4.1 6-1 3.4.17 RCS Loop I s o l a t i o n Valves..............3.4.1 7-1 3.4.18 RCS I s o l a t e d Loop Startup..............3.4.1 8-1 3.4.19 RCS Loops-Test Exceptions..............3.4.1 9-1 V

3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS).......... 3.5.1-1 3.5.1 Accumulators.................... 3.5.1-1 3.5.2 ECCS-Operating................... 3.5.2.1 3.5.3 ECCS-Shutdown.................... 3.5.3.1 3.5.4 Refuel i n g Water Storage Tank (RWST)......... 3.5.4-1 3.5.5 Seal I n j e c t i o n Flow................. 3.5.5-1 3.5.6 Boron I n j e c t i o n Tank (BIT)............. 3.5.6.1

Definitions 1.1 1.1 D e f i n i t i o n s E-AVERAGE DISINTEGRATION E shall be the average (weighted i n proportion t o ENERGY the concentration o f each radi onucl i de i n the reactor coolant a t the time o f sampling) o f the sum o f the average beta and gamma energies per disintegration ( i n MeV) f o r isotopes, other than iodines, with h a l f l i v e s > 15 minutes, making up a t least 95% o f the t o t a l noniodine a c t i v i t y i n the coolant.

ENGINEERED SAFETY The ESF RESPONSE TIME shall be that time i n t e r v a l FEATURE (ESF) RESPONSE from when the monitored parameter exceeds i t s ESF TIME:

actuation setpoint a t the channel sensor u n t i 1 the ESF equipment i s capable o f performing i t s safety function (i

.e.,

the valves travel t o t h e i r required positions, pump discharge pressures reach t h e i r required values, etc.). Times shall include diesel generator s t a r t i n g and sequence 1 oadi ng de1 ays, where appl icabl e. The response time may be measured by means o f any series o f sequential, overlapping, o r t o t a l steps so t h a t the e n t i r e response time i s measured. I n l i e u o f measurement, response time may be v e r i f i e d f o r selected components provided t h a t the components and method01 ogy f o r v e r i f i c a t i o n have been previously reviewed and approved by the NRC.

LEAKAGE LEAKAGE shall be:

a. I d e n t i f i e d LEAKAGE

1. LEAKAGE, such as that from pump seals o r valve packing (except reactor cool ant pump (RCP) seal water i n j e c t i o n o r l e a k o f f j, t h a t i s captured and conducted t o c o l l e c t i o n systems o r a sump o r c o l l e c t i n g tank;

2. LEAKAGE i n t o the containment atmosphere from sources t h a t are both s p e c i f i c a l l y located and known e i t h e r not t o i n t e r f e r e w i t h the operati on o f 1 eakage detection systems o r not t o be pressure boundary LEAKAGE; o r North Anna Units 1 and 2 1.1-3 Amendments mtmb

Definitions 1.1 1.1 Definitions LEAKAGE (continued)

MASTER RELAY TEST MODE PHYSICS TESTS

b. Unidentified LEAKAGE A l l LEAKAGE (except RCP seal water i n j e c t i o n o r leakoff) that i s not i d e n t i f i e d LEAKAGE;

c. Pressure Boundary LEAKAGE LEAKAGE (except&

e e

o z

a EA KA noni sol able f aul t i n an RCS component body, pipe wall, o r vessel wall.

A MASTER RELAY TEST shall consist o f energizing a l l master relays i n the channel required for channel OPERABILITY and v e r i f y i ng the OPERABILITY o f each required master relay. The MASTER RELAY TEST shall include a continuity check of each associated required slave re1 ay. The MASTER RELAY TEST may be performed by means o f any series of sequenti a1, overlapping, o r t o t a l steps.

A MODE shall correspond t o any one inclusive combination o f core r e a c t i v i t y condition, power 1 eve1, average reactor cool ant temperature, and reactor vessel head c l osure b o l t tensioning specified i n Table 1.1-1 w i t h fuel i n the reactor vessel.

A system, subsystem, train, component, o r device shall be OPERABLE o r have OPERABILITY when it i s capabl e o f performing i t s speci f i ed safety function(s) and when a1 1 necessary attendant instrumentation, controls, normal o r emergency e l e r t r i c a l power, cool ing and seal water, lubrication, and other auxi 1 i a r y equipment t h a t are required f o r the system, subsystem, train, component, o r device t o perform i t s specified safety function (s) are a1 so capabl e o f perf ormi ng t h e i r related support function(s).

PHYSICS TESTS shall be those tests performed t o measure the fundamental nuclear characteristics o f the reactor core and related instrumentation.

These tests are:

a. Described i n Chapter 14, I n i t i a l Tests and Operation, o f the UFSAR; (continued)

North Anna Units 1 and 2 1.1-4 Amendments 9STfTTT),

RCS Operati onal LEAKAGE 3.4.13 3.4 REACTOR COOLANT SYSTEM (RCS) 3.4.13 RCS Operati onal LEAKAGE LC0 3.4.13 RCS operational LEAKAGE shall be 1 imited to:

a. No pressure boundary LEAKAGE;

b. 1 gpm unidentified LEAKAGE;

c. 10 gpm i d e n t i f i e d LEAKAGE; d

APPLICABILITY:

MODES 1, 2, 3, and 4.

ACT l ONS A.

RCS d EAKAGEnotwithin 1 imi t s f o r reasons other than pressure boundary LEAKAG B.

Required Action and associated Compl e t i on Time o f Condition A not met.

Pressure boundary LEAKAGE exists.

A.l Reduce LEAKAGE t o w i t h i n l i m i t s.

/ Grr

-b Y

C I

W

~

V

~

L P A E ~ G C T I

6 B.l BeinMODE3.

AND -

8.2 Be i n MODE 5.

North Anna Units 1 and 2 3.4.13-1 COMPLETION TIME 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months 6 hours 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months Amendments --%

RCS Operati onal LEAKAGE

\\

. p a M q G GLL-A SURVEILLANCE REQUIREMENTS

/

SURVEILLANCE -

SR 3.4.13.1 s

NOT

(, o t required t o be performed u n t i l 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months s

f t e r establ i shment offdi.,

s t a t e C,

operation.

V e r i f y RCS operational LEAKAGE i s w i t h i n l i m i t s by performance o f RCS water inventory bal ance.

FREQUENCY 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months North Anna Units 1 and 2 3.4.13-2

E w T S 3, 4. z O 3.4 REACTOR COOLANT SYSTEM (RCS) 3.4.20 Steam Generator (SG) Tube Integrity LC0 3.4.20 SG tube integrity shall be maintained.

All SG tubes satisfying the tube repair criteria shall be plugged in accordance with the Steam Generator Program.

APPLICABILITY:

MODES 1, 2,3, and 4.

CONDITION A. One or more SG tubes satisfying the tube repair criteria and not plugged in accordance with the Steam Generator Program.

B. Req~~ired Action and associated Completion Time of Condition A not met.

OR -

SG tube integrity not maintained.

REQUIRED ACTION A.l Verify tube integrity of the affected tube(s) is maintained until the next refueling outage or SG tube inspection.

A.2 Plug the affected tube(s) in accordance with the Steam Generator Program.

B.l Be in MODE 3.

AND B.2 Be in MODE 5.

COMPLETION TIME 7 days Prior to entering MODE 4 following the next refueling outage or SG tube inspection 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months 36 hours 3.4.20-1 Amendments

SURVEILLANCE REQUIREMENTS SURVEILLANCE

(

FREQUENCY SR 3.4.2!0.1 Verify SG tube integrity in accordance with the Steam Generator Program.

In accordance with the Steam Generator Program Amendments SR 3.4.20.2 Verify that each inspected SG tube that satisfies the tube repair criteria is plugged in accordance with the Steam Generator Program.

Prior to entering MODE 4 following a SG tube inspection

Programs and Manuals 5.5 5.5 Proqrams and Manual s 5.5.7 Inservi ce Testing Program This program provides controls for inservice testing of ASME Code Class 1, 2, and 3 components. The program shall include the f 01 1 owi ng :

a.

Testing frequencies specified in the ASME Code for Operation and Mai ntenance of Nuclear Power Pl ants and appl i cabl e Addenda as follows:

ASME Code for Operation and Maintenance of Nuclear Power Plants and appl i cabl e Addenda termi no1 ogy for inservice testing activities Weekly Monthly Quarterly or every 3 months Semiannually or every 6 months Every 9 months Yearly or annual ly Biennially or every 2 years Requi red Frequencies for performing i nservi ce testing activities A t least once per 7 days A t least once per 31 days A t least once per 92 days A t least once per 184 days A t least once per 276 days A t least once per 366 days A t least once per 731 days

b.

The provisions of SR 3.0.2 are applicable t o the above required Frequencies for performing i nservice testing activities;

c. The provisions of SR 3.0.3 are applicable t o inservice testing activities; and

d.

Nothing in the ASME Code for Operation and Maintenance of Nuclear Power Plants shall be construed to supersede the requirements of any TS.

5.5.8 Steam Generator (SG)

Program C

P North Anna Units 1 and 2 5.5-5 Amendments

Programs and Manual s 5.5 5.5 Proarams and Manuals North Anna Uni t s 1 and 2 5.5-6 Amendments

Programs and Manual s 5.5 5.5 Proarams and Manuals North Anna Units 1 and 2 5.5-7 Amendments

Programs and Manuals 5.5 5.5 Programs and Manuals North Anna Units 1 and 2 5.5-8 Amendments +%-

Programs and Manual s 5.5 Norlth Anna Units 1 and 2 5.5-9 Amendments v

Programs and Manuals 5.5 North Anna Units 1 and 2 5.5-10 Amendments v

Programs and Manual s 5.5 North Anna Units 1 and 2 Amendments -Tk

INSERT 5.5.8 A Steam Generator Program shall be established and implemented to ensure that SG tube integrity is maintained. In addition, the Steam Generator Program shall include the following provisions:

Provisions for condition monitoring assessments.

Condition monitoring assessment means an evaluation of the "as found" condition of the tubing with respect to the performance criteria for structural integrity and accident induced leakage. The "as found" condition refers to the condition of the tubing during a SG inspection outage, as determined from the inservice inspection results or by other means, prior to the plugging of tubes. Condition monitoring assessments shall be conducted during each outage during whicli the SG tubes are inspected or plugged to confirm that the performance criteria are being met.

Performance criteria for SG tube integrity. SG tube integrity shall be maintained by meeting the performance criteria for tube structural integrity, accident induced leakage, and operational LEAKAGE.

Structural integrity performance criterion: All in-service steam generator tubes shall retain structural integrity over the full range of normal operating conditions (including startup, operation in the power range, hot standby, and cool down and all anticipated transients included in the design specification) and design basis accidents. This includes retaining a safety factor of 3.0 against burst under normal steady state full power operation primary to secondary pressure differential and a safety factor of 1.4 against burst applied to the design basis accident primary to secondary pressure differentials. Apart from the above requirements, additional loading conditions associated with the design basis accidents, or combination of accidents in accordance with the design and licensing basis, shall also be evaluated to determine if the associated loads contribute significantly to burst or collapse. In the assessment of tube integrity, those loads that do significantly affect burst or collapse shall be determined and assessed in combination with the loads due to pressure with a safety factor of 1.2 on the combined primary loads and 1.0 on axial secondary loads.

2.

Accident induced leakage performance criterion: The primary to secondary accident induced leakage rate for any design basis accident, other than a SG tube rupture, shall not exceed the leakage rate assumed in the accident analysis in terms of total leakage rate for all SGs and leakage rate for an individual SG. Leakage is not to exceed 1 gpm for all SGs.

3.

The operational LEAKAGE performance criterion is specified in LC0 3.4.13, "RCS Operational LEAKAGE."

Page 1

c.

Provisions for SG tube repair criteria. Tubes found by inservice inspection to contain flaws with a depth equal to or exceeding 40% of the nominal tube wall thickness shall be phxled-Provisions for SG tube inspections. Periodic SG tube inspections shall be performed. The number and portions of the tubes inspected and methods of inspection shall be performed with the objective of detecting flaws of any type (e.g., volumetric flaws, axial and circumferential cracks) that may be present along the length of the tube, from the tube-to-tubesheet weld at the tube inlet to the tube-to-tubesheet weld at the tube outlet, and that may satisfy the applicable tube repair criteria. The tube-to-tubesheet weld is not part of the tube. In addition to meeting the requirements of d.1, d.2, and d.3 below, the inspection scope, inspection methods, and inspection intervals shall be such as to ensure that SG tube integrity is maintained until the next SG inspection. An assessment of degradation shall be performed to determine the type and location of flaws to which the tubes may be susceptible and, based on this assessment, to determine which inspection methods need to be employed and at what locations.

1.

Inspect 100% of the tubes in each SG during the first refueling outage following SG replacement.

2.

Inspect 100% of the tubes at sequential periods of 144, 108, 72, and, thereafter, 60 effective full power months. The first sequential period shall be considered to begin after the first inservice inspection of the SGs. In addition, inspect 50% of the tubes by the refueling outage nearest the midpoint of the period and the remaining 50% by the refueling outage nearest the end of the period. No SG shall operate for more than 72 effective full power months or three refueling outages (whichever is less) without being inspected.

3.

If crack indications are found in any SG tube, then the next inspection for each SG for the degradation mechanism that caused the crack indication shall not exceed 24 effective full power months or one refueling outage (whichever is less). If definitive information, such as from examination of a pulled tube, diagnostic non-destructive testing, or engineering evaluation indicates that a crack-like indication is not associated with a crack@), then the indication need not be treated as a crack.

e.

Provisions for monitoring operational primary to secondary LEAKAGE.

Page 2

Reporting Requi rements 5.6 5.6 Reporting Requi rements 5.6.5 CORE OPERATING LIMITS REPORT (COLR)

b.

(continued)

14. BAW-10199P-A, "The BWU C r i t i c a l Heat F l ux Correlations. "

15. BAW-10170P-A, " S t a t i s t i c a l Core Design f o r Mixing Vane Cores."

16. EMF-2103 (P) (A),

"Real i s t i c Large Break LOCA Method01 ogy f o r Pressurized Water Reactors. "

17. EMF-96-029 (P) (A),

"Reactor Analysis System for PWRs."

18. BAW-10168P-A, "RSG LOCA - BWNT Loss-of-Coolant Accident Evaluation Model f o r Recirculating Steam Generator Plants,"

Vol ume I I on1 y (SBLOCA model s).

c.

The core operating 1 i m i t s shall be determined such t h a t a l l appl icabl e 1 i m i t s (e.g.,

fuel thermal mechanical 1 i m i ts, core thermal hydraul i c 1 imi ts, Emergency Core Cool i n g Systems (ECCS) l i m i t s, nuclear l i m i t s such as SDM, transient analysis l i m i t s,

and accident analysis 1 i m i t s ) o f the safety analysis are met.

d.

The COLR, including any midcycle revisions o r supplements, s h a l l be provided upon issuance f o r each reload cycle t o the NRC.

5.6.6 PAM Report When a report i s required by Condition B o f LC0 3.3.3, "Post Accident Monitoring (PAM) Instrumentation," a report shall be submitted w i t h i n the following 14 days. The report shall o u t l i n e the cause o f the inoperabil i t y, and the plans and schedule f o r restoring the instrumentation channels o f the Function t o OPERABLE status.

5.6.7 Steam Generator Tube Inspection ~ e p b r t North" Anna Units 1 and 2 5.6-4 Amendments 239/220

Reporting Requi rements 5.6 5.6 Reporting Requirements North Anna Units 1 and 2 Amendments -EB$Vl+

INSERT 5.6.7 A report shall be submitted within 180 days after the initial entry into MODE 4 following completion of an inspection performed in accordance with the Specification 5.5.8, "Steam Generator (SG) Program." The report shall include:

The scope of inspections performed on each SG, Active degradation mechanisms found, Nondestructive examination techniques utilized for each degradation mechanism, Location, orientation (if linear), and measured sizes (if available) of service induced indications, Number of tubes plugged during the inspection outage for each active degradation mechanism, Tota.1 number and percentage of tubes plugged to date, The results of condition monitoring, including the results of tube pulls and in-situ testing, and The effective plugging percentage for all plugging in each SG.

Serial No.06-403 Docket Nos. 50-3381339 Proposed Technical Specifications Changes North Anna Power Station Units 1 and 2 Virginia Electric and Power Company (Dominion)

TECHNICAL SPECIFICATIONS TABLE OF CONTENTS REACTOR COOLANT SYSTEM (RCS) (continued)

Pressurizer Safety Valves

.3.4.1 0.1 Pressurizer Power Operated R e l i e f Valves (PORVS)

.3.4.1 1.1 Low Temperature Overpressure Protection (LTOP)

System

.3.4.1 2-1 RCS Operational LEAKAGE

.3.4.1 3-1 RCS Pressure I s o l a t i o n Valve (PIV) Leakage.....3.4.1 4.1 RCS Leakage Detection Instrumentation........3.4.1 5-1 RCS S p e c i f i c A c t i v i t y

.3.4.1 6.1 RCS Loop I s o l a t i o n Valves

.3.4.1 7.1 RCS I s o l a t e d Loop Startup

.3.4.1 8.1 RCS Loops-Test Exceptions

.3.4.1 9-1 Steam Generator (SG) Tube I n t e g r i t y.........3.4.2 0.1 1

3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS) 3.5.1. 1 3.5.1 Accumulators 3.5.1-1 3.5.2 ECCS-Operating 3.5.2.1 3.5.3 ECCS-Shutdown 3.5.3-1 3.5.4 Refuel i ng Water Storage Tank (RWST) 3.5.4-1 3.5.5 Seal I n j e c t i o n Flow 3.5.5-1 3.5.6 Boron I n j e c t i o n Tank (BIT) 3.5.6-1 CONTAINMENT SYSTEMS 3.6.1.1 Containment 3.6.1.1 Containment A i r Locks 3.6.2.1 Containment I s o l a t i o n Valves 3.6.3.1 Containment Pressure 3.6.4.1 Containment A i r Temperature 3.6.5.1 Quench Spray (QS) System 3.6.6.1 Recirculation Spray (RS) System 3.6.7.1 Chemical Addition System 3.6.8.1 PLANT SYSTEMS 3.7.1.1 Main Steam Safety Valves (MSSVs).......... 3.7.1.1 Main Steam T r i p Valves (MSTVs)........... 3.7.2.1 Main Feedwater I s o l a t i o n Valves (MFIVs), Main Feedwater Pump Discharge Valves (MFPDVs).

Main Feedwater Regulating Valves (MFRVs).

and Main Feedwater Regulating Bypass Valves (MFRBVs) 3.7.3.1 Steam Generator Power Operated R e l i e f Valves (SG PORVS) 3.7.4.1 Auxi 1 i a r y Feedwater (AFW) System.......... 3.7.5.1 Emergency Condensate Storage Tank (ECST)...... 3.7.6.1 Secondary S p e c i f i c A c t i v i t y............. 3.7.7.1 Servi ce Water (SW) System.............. 3.7.8.1 Ultimate Heat Sink (UHS).............. 3.7.9.1 North Anna Units 1 and 2 i i

D e f i n i t i o n s 1.1 1.1 D e f i n i t i o n s E-AVERAGE DISINTEGRATION E s h a l l be the average (weighted i n proportion t o ENERGY the concentration o f each radionuclide i n t h e reactor coolant a t the time o f sampling) of the sum o f t h e average beta and gamma energies per d i s i n t e g r a t i o n ( i n MeV) f o r isotopes, other than iodines, w i t h h a l f l i v e s > 15 minutes, making up a t l e a s t 95% o f the t o t a l noniodine a c t i v i t y i n t h e coolant.

ENGINEERED SAFETY The ESF RESPONSE TIME s h a l l be t h a t time i n t e r v a l FEATURE (ESF) RESPONSE from when t h e monitored parameter exceeds i t s ESF TIME actuation setpoint a t t h e channel sensor u n t i l t h e ESF equipment i s capable o f performing i t s safety f u n c t i o n ( i.e.,

the valves t r a v e l t o t h e i r requi red positions, pump d i scharge pressures reach t h e i r required values, etc.). Times s h a l l include diesel generator s t a r t i n g and sequence loading delays, where appl i cable. The response time may be measured by means o f any series o f sequential, overlapping, o r t o t a l steps so t h a t the e n t i r e response time i s measured. I n l i e u o f measurement, response time may be v e r i f i e d f o r selected components provided t h a t t h e components and method01 ogy f o r v e r i f i c a t i o n have been previously reviewed and approved by t h e NRC.

LEAKAGE LEAKAGE s h a l l be:

a. I d e n t i f i e d LEAKAGE

1. LEAKAGE, such as t h a t from pump seals o r val ve packing (except reactor cool ant pump (RCP) seal water i n j e c t i o n o r leakoff), t h a t i s captured and conducted t o c o l l e c t i o n systems o r a sump o r c o l l e c t i n g tank;

2. LEAKAGE i n t o t h e containment atmosphere from sources t h a t are both s p e c i f i c a l l y located and known e i t h e r n o t t o i n t e r f e r e w i t h the operation of leakage detection systems o r not t o be pressure boundary LEAKAGE; o r

3. Reactor Coolant System (RCS) LEAKAGE through a steam generator t o t h e Secondary System (primary t o secondary LEAKAGE);

I (continued)

North Anna Units 1 and 2 1.1-3

D e f i n i t i o n s 1.1 1.1 D e f i n i t i o n s LEAKAGE (conti nued)

MASTER RELAY TEST MODE OPERABLE-OPERABILITY PHYSICS TES'TS

b. U n i d e n t i f i e d LEAKAGE A1 1 LEAKAGE (except RCP seal water i n j e c t i o n o r l e a k o f f ) t h a t i s n o t i d e n t i f i e d LEAKAGE;

c. Pressure Boundary LEAKAGE LEAKAGE (except primary t o secondary LEAKAGE)

I through a nonisolable f a u l t i n an RCS component body, pipe wall, o r vessel wall.

A MASTER RELAY TEST s h a l l consist o f energizing a1 1 master r e l a y s i n t h e channel required f o r channel OPERABILITY and v e r i f y i ng the OPERABILITY o f each required master relay. The MASTER RELAY TEST s h a l l include a c o n t i n u i t y check o f each associ ated required s l ave re1 ay. The MASTER RELAY TEST may be performed by means o f any series o f sequential, overlapping, o r t o t a l steps.

A MODE s h a l l correspond t o any one i n c l u s i v e combination o f core r e a c t i v i t y condition, power 1 eve1, average reactor cool ant temperature, and reactor vessel head closure bol t tensioning s p e c i f i e d i n Table 1.1-1 w i t h f u e l i n the r e a c t o r vessel.

A system, subsystem, t r a i n, component, o r device s h a l l be OPERABLE o r have OPERABILITY when i t i s capable o f performing i t s specified safety f u n c t i o n (s) and when a1 1 necessary attendant instrumentation, control s, normal o r emergency e l e c t r i c a l power, cool i n g and seal water, 1 ubrication, and other auxi 1 i a r y equipment t h a t are required f o r t h e system, subsystem, t r a i n,

component, o r device t o perform i t s s p e c i f i e d safety function(s) are a1 so capable o f performing t h e i r re1 ated support function(s).

PHYSICS TESTS s h a l l be those t e s t s performed t o measure the fundamental nuclear c h a r a c t e r i s t i c s o f t h e reactor core and r e l a t e d instrumentation.

These t e s t s are:

a. Described i n Chapter 14, I n i t i a l Tests and Operation, o f t h e UFSAR; (continued)

North Anna Units 1 and 2 1.1-4

RCS Operational LEAKAGE 3.4.13 3.4 REACTOR COOLANT SYSTEM (RCS) 3.4.1.3 RCS Operational LEAKAGE LC0 3.4.13 RCS operational LEAKAGE s h a l l be l i m i t e d to:

a. No pressure boundary LEAKAGE;

b. 1 gpm u n i d e n t i f i e d LEAKAGE;

c. 10 gpm i d e n t i f i e d LEAKAGE;

d. 150 gallons per day primary t o secondary LEAKAGE through any one steam generator (SG).

I APPLICABILITY:

MODES 1, 2, ACTIONS 3, and 4.

CONDITION A.

RCS operational LEAKAGE n o t w i t h i n l i m i t s f o r reasons other than pressure boundary LEAKAGE o r primary t o secondary LEAKAGE.

B.

Required Action and associated Completion Time o f Condition A n o t met.

Pressure boundary LEAKAGE e x i s t s.

Primary t o secondary LEAKAGE n o t w i t h i n l i m i t.

REQUIRED ACTION A. l Reduce LEAKAGE t o w i t h i n 1 imi t s.

B. l Be i n MODE 3.

AND -

B.2 B e i n M O D E 5.

North Anna Units 1 and 2 COMPLETION TIME 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months I

6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months 36 hours

RCS Operational LEAKAGE SURVEILLANCE REQUIREMENTS SURVEILLANCE SR 3.4.13.1

NOTES-------------------

1. Not required t o be performed u n t i 1 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months a f t e r establishment o f steady s t a t e operation.

2. Not applicable t o primary t o secondary LEAKAGE.

V e r i f y RCS operational LEAKAGE i s w i t h i n l i m i t s by performance o f RCS water inventory balance.

SR 3.4.1:1.2

NOTE--------------------

Not required t o be performed u n t i l 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months a f t e r establishment o f steady s t a t e operation.

V e r i f y primary t o secondary LEAKAGE i s I

150 gallons per day through any one SG.

FREQUENCY 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months 72 hours I

North Anna U n i t s 1 and 2

SG Tube Integrity 3.4.20 3.4 REACTOR COOLANT SYSTEM (RCS) 3.4.20 Steam Generator (SG) Tube l ntegr i t y LC0 3.4.20 SG tube i ntegr i t y sha 1 l be ma i nta i ned.

A1 1 SG tubes sati sfyi ng the tube repa i r c r i t e r i a sha l 1 be p l ugged i n accordance with the Steam Generator Program.

APPLICABILITY:

MODES1, 2, 3, and4.

ACT l ONS COND l T l ON A.

One or more SG tubes satisfying the tube repa i r c r i t e r i a and not p l ugged i n accordance with the Steam Generator Program.

REQU l RED ACT l ON A. 1 Verify tube integrity o f the affected tube (s) i s ma i nta i ned unti l the next refuel ing outage or SG tube inspection.

AND -

A. 2 PI ug the affected tube (s) i n accordance with the Steam Generator Program.

COMPLET l ON T l ME 7 days Pr i or t o entering MODE 4 f o l lowing the next refuel i ng outage or SG tube i nspect i on North Anna Units 1 and 2 3.4.20-1

SG Tube l ntegr i t y 3.4.20 ACT l ONS I

COND l T l ON REQU I RED ACT l ON I COMPLETION TIME B.

Required Action and assolc i ated Comp I e t i on Time o f Condition A not met.

SG tube integrity not ma i nta i ned.

B. l Be i n MODE 3.

AND -

B.2 Be inMODE5.

6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months 36 hours SURVE l LLANCE REQU l REMENTS SURVE l LLANCE I

FREQUENCY SR 3.4.20.1 Verify SG tube i ntegr i t y i n accordance with the Steam Generator Program.

I n accordance with the Steam Generator Program SR 3.4.;!0.2 Verify that each inspected SG tube that satisfies the tube repair c r i t e r i a i s p l ugged i n accordance with the Steam Generator Program.

Pr i or t o entering MODE 4 f o l lowing a SG tube i nspect i on North Anna Units 1 and 2 3.4.20-2

Programs and Manual s 5.5 5.5 Proqrams and Manual s 5.5.:7 Inservice Testing Program This program provides controls for inservice testing of ASME Code Class 1, 2, and 3 components. The program shall include the fol 1 owing :

a. Testing frequencies specified in the ASME Code for Operation and Maintenance of Nuclear Power Plants and applicable Addenda as fol 1 ows :

ASME Code for Operation and Maintenance of Nuclear Power Plants and applicable Addenda termi no1 ogy for i nservi ce testina activities Required Frequencies for performing inservice testina activities Weekly Monthly Quarterly or every 3 months Semiannual ly or every 6 months Every 9 months Yearly or annually Biennially or every 2 years A t least once per 7 days A t least once per 31 days A t least once per 92 days A t least once per 184 days A t least once per 276 days A t least once per 366 days A t least once per 731 days

b.

The provisions of SR 3.0.2 are applicable to the above required Frequencies for performing i nservi ce testing activities;

c. The provisions of SR 3.0.3 are applicable to inservice testing activities; and d.

Nothing i n the ASME Code for Operation and Maintenance of Nuclear Power Plants shall be construed to supersede the requirements of any TS.

5.5.8 Steam Generator (SG) Program A Steam Generator Program shall be established and implemented to ensure that SG tube integrity i s maintained. In addition, the Steam Generator Program shall incl ude the fol lowing provisions :

a. Provisions for condition monitoring assessments. Condition monitoring assessment means an evaluation of the "as found" condition of the tubing with respect to the performance criteria for structural integrity and accident induced leakage. The "as found" condition refers to the condition of the t u b i n g during a SG inspection outage, as determined from the inservice (cont i nued)

North Anna Units 1 and 2 5.5-5

Programs and Manual s 5.5 5.5 Programs and Manuals 5.5.8 Steam Generator (SG) Program

a.

(conti nued) inspection results or by other means, prior t o the plugging of tubes. Condition moni tori ng assessments shall be conducted during each outage during which the SG tubes are inspected or plugged t o confirm that the performance c r i t e r i a are being met.

b.

Performance c r i t e r i a for SG tube integrity. SG tube integrity shall be maintained by meeting the performance c r i t e r i a f o r tube structural integrity, accident induced leakage, and operational LEAKAGE.

Structural integrity performance criterion: All in-service steam generator tubes shall retain structural integrity over the full range of normal operati ng condi t i ons ( i ncl udi ng startup, operation in the power range, hot standby, and cool down and a1 1 anticipated transients included in the design specification) and design basis accidents. This includes retaining a safety factor of 3.0 against burst under normal steady s t a t e full power operation primary t o secondary pressure differential and a safety factor of 1.4 against burst applied t o the design basis accident primary t o secondary pressure differentials. Apart from the above requirements, additional loading conditions associated with the design basis accidents, or combination of accidents in accordance with the design and 1 i censi ng basis, shall a1 so be eval uated t o determine i f the associated 1 oads contribute significantly t o burst or collapse. In the assessment of tube integrity, those loads that do significantly affect burst or collapse shall be determined and assessed in combination with the loads due t o pressure with a safety factor of 1.2 on the combined primary loads and 1.0 on axial secondary loads.

2. Accident induced leakage performance criterion: The primary t o secondary accident induced leakage r a t e for any design basis accident, other than a SG tube rupture, shall not exceed the leakage r a t e assumed in the accident analysis in terms of total leakage r a t e f o r a l l SGs and leakage r a t e for an individual SG. Leakage i s not t o exceed 1 gpm f o r a1 1 SGs.

3. The operational LEAKAGE performance criterion i s specified in LC0 3.4.13, "RCS Operational LEAKAGE."

North Anna Units 1 and 2 5.5-6

Programs and Manual s 5.5 5.5 Programs and Manuals 5.5.8 Steam Generator (SG) Program (continued)

c.

Provisions f o r SG tube r e p a i r c r i t e r i a. Tubes found by i n s e r v i c e inspection t o contain flaws w i t h a depth equal t o o r exceeding 40% o f the nominal tube wall thickness s h a l l be plugged.

d.

Provisions f o r SG tube inspections. Periodic SG tube inspections s h a l l be performed. The number and portions o f t h e tubes inspected and methods o f inspection s h a l l be performed w i t h t h e o b j e c t i v e o f detecting flaws o f any type (e.g.,

volumetric flaws, a x i a l and circumferential cracks) t h a t may be present along the length o f the tube, from the tube-to-tubesheet weld a t t h e tube i n l e t t o the tube-to-tubesheet weld a t the tube o u t l e t,

and t h a t may s a t i s f y t h e applicable tube r e p a i r c r i t e r i a. The tube-to-tubesheet weld i s not p a r t o f the tube. I n a d d i t i o n t o meeting the requirements o f d.1, d.2, and d.3 below, t h e inspection scope, inspection methods, and inspection i n t e r v a l s s h a l l be such as t o ensure t h a t SG tube i n t e g r i t y i s maintained u n t i l t h e next SG inspection. An assessment o f degradation s h a l l be performed t o determine t h e type and l o c a t i o n o f flaws t o which t h e tubes may be susceptible and, based on t h i s assessment, t o determine which inspection methods need t o be employed and a t what locations.

1. Inspect 100% o f t h e tubes i n each SG during the f i r s t r e f u e l i ng outage f o l 1 owing SG rep1 acement.

2. Inspect 100% o f the tubes a t sequential periods o f 144, 108, 72, and, thereafter, 60 e f f e c t i v e f u l l power months. The f i r s t sequential period s h a l l be considered t o begin a f t e r t h e f i r s t i n s e r v i c e inspection o f the SGs. I n addition, inspect 50% o f t h e tubes by the r e f u e l i n g outage nearest the midpoint o f the period and the remaining 50% by t h e r e f u e l i n g outage nearest the end o f t h e period. No SG s h a l l operate f o r more than 72 e f f e c t i v e f u l l power months o r three r e f u e l i n g outages (whichever i s 1 ess) without being inspected.

3. I f crack i n d i c a t i o n s are found i n any SG tube, then t h e next inspection f o r each SG f o r the degradation mechanism t h a t caused the crack i n d i c a t i o n s h a l l not exceed 24 e f f e c t i v e f u l l power months o r one r e f u e l i n g outage (whichever i s less). I f d e f i n i t i v e information, such as from examination o f a p u l l e d tube, diagnostic non-destructive t e s t i n g, o r engineering evaluation i n d i c a t e s t h a t a crack-1 i ke i n d i c a t i o n i s not associated w i t h a crack(s), then t h e i n d i c a t i o n need not be t r e a t e d as a crack.

North Anna Units 1 and 2 5.5-7

Programs and Manual s 5.5 5.5 Programs and Manuals 5.5.8 Steam Generator (SG) Program (continued)

e.

Provisions for monitoring operational primary t o secondary LEAKAGE.

5.5.9 Secondary Water Chemistry Program This program provides controls f o r monitoring secondary water chemistry t o inhibit SG tube degradation and low pressure turbine disc s t r e s s corrosion cracking. The program shall include:

a.

Identification of a sampl ing schedule f o r the c r i t i c a l variables and control points f o r these variables; Identification of the procedures used t o measure the values of the c r i t i c a l variables; c.

Identification of process sampling points, which shall include monitoring the discharge of the condensate pumps f o r evidence of condenser i n 1 eakage; d.

Procedures f o r the recording and management of data;

e.

Procedures defining corrective actions f o r a1 1 off control point chemistry conditions; and

f.

A procedure identifying the authority responsible for the interpretation of the data and the sequence and timing of administrative events, which i s required t o i n i t i a t e corrective action.

5.5.10 Ventilation F i l t e r Testing Program (VFTP)

A program shall be established t o implement the following required testing of Engineered Safety Feature (ESF) f i l t e r venti 1 ation systems in general conformance with the frequencies and requirements of Regulatory Positions C.5.a, C.5.c, C.5.d, and C.6.b of Regulatory Guide 1.52, Revision 2, March 1978, and ANSI N510-1975.

a.

Demonstrate f o r each of the ESF systems that an inplace t e s t of the high efficiency particulate a i r (HEPA) f i l t e r s shows a penetration and system bypass < 1.0% when tested i n accordance (continued)

North Anna Units 1 and 2 5.5-8

Programs and Manuals 5.5 5.5 Prosrams and Manuals 5.5.10 V e n t i l a t i o n F i l t e r Testing Program (VFTP)

a.

(cont i nued) w i t h Regulatory Positions C.5.a and C.5.c o f Regulatory Guide 1.52, Revision 2, March 1978, and ANSI N510-1975 a t the system f l owrate s p e c i f i e d be1 ow.

ESF Venti 1 a t i on System F l owrate Main Control Room/Emergency Switchgear 1000 + 10% cfm Room (MCRIESGR) Emergency Vent i 1 a t i on System (EVS)

Emergency Core Cool i ng System (ECCS)

Nominal Pump Room Exhaust A i r Cleanup System accident f l o w (PREACS) f o r a s i n g l e t r a i n actuation Nominal accident f l o w f o r a s i n g l e t r a i n actuation i s greater than the minimum required cool i n g flow f o r ECCS equipment operation, and I 39,200 cfrn, which i s the maximum flow r a t e providing an adequate residence time w i t h i n the charcoal adsorber.

b.

Demonstrate f o r each o f the ESF systems t h a t an inplace t e s t o f the charcoal adsorber shows a penetration and system bypass

< 1.0% when tested i n accordance w i t h Regulatory Positions C.5.a and C.5.d o f Regulatory Guide 1.52, Revision 2, March 1978, and ANSI N510-1975 a t t h e system f l o w r a t e s p e c i f i e d below.

ESF Venti 1 a t i o n System F l owrate MCRIESGR EVS 1000 + 10% cfm ECCS PREACS Nominal accident flow f o r a s i n g l e t r a i n actuation Nominal accident f l o w f o r a s i n g l e t r a i n actuation i s greater than the minimum required cooling f l o w f o r ECCS equipment operation, and 5 39,200 cfm, which i s the maximum flow r a t e providing an adequate residence time w i t h i n the charcoal adsorber.

c.

Demonstrate f o r each o f the ESF systems t h a t a laboratory t e s t o f a sample o f the charcoal adsorber, when obtained as described i n Regulatory P o s i t i o n C.6. b o f Regulatory Guide 1.52, Revision 2, March 1978, shows t h e methyl i o d i d e penetration less than the (cont i nued)

North Anna Units 1 and 2 5.5-9

Programs and Manual s 5.5 5.5 Programs and Manuals 5.5.10 V e n t i l a t i o n F i l t e r Testing Program (VFTP)

c.

(conti w e d )

val ue speci f i ed be1 ow when tested i n accordance w i t h ASTM D3803-1989 a t a temperature o f 30°C (86°F) and re1 a t i v e humi d i t y speci f i ed be1 ow.

ESF V e n t i l a t i o n System Penetration RH MCR/ESGR EVS 2.5%

7 0%

ECCS PREACS 5%

7 0%

d.

Demonstrate f o r each of the ESF systems t h a t the pressure drop across the combined HEPA f i l t e r s, t h e p r e f i l t e r s, and the charcoal adsorbers i s l e s s than the value s p e c i f i e d below when tested i n accordance w i t h ANSI N510-1975 a t the system flowrate s p e c i f i e d below.

ESF V e n t i l a t i o n System Delta P F l owrate MCRIESGR EVS 4 inches W.G.

1000 + 10% cfm ECCS PREACS 5inchesW.G.

5 3 9, 2 0 0 c f m

e.

Demonstrate t h a t the heaters f o r each o f t h e ESF systems d i s s i p a t e > t h e value s p e c i f i e d below when tested i n accordance w i t h ASME N510-1975.

ESF V e n t i l a t i o n System Wattaqe MCR/ESGR EVS 3.5 kW The provisions o f SR 3.0.2 and SR 3.0.3 are applicable t o the VFTP t e s t frequencies.

5.5.11 Explosive Gas and Storage Tank R a d i o a c t i v i t y Monitoring Program This program provides c o n t r o l s f o r p o t e n t i a l l y explosive gas mixtures contained i n t h e Gaseous Waste System, the q u a n t i t y o f r a d i o a c t i v i t y contained i n gas storage tanks, and the q u a n t i t y o f r a d i o a c t i v i t y contained i n unprotected outdoor 1 i q u i d storage tanks.

The gaseous r a d i o a c t i v i t y q u a n t i t i e s s h a l l be determined f o l 1 owing the methodology i n Branch Technical P o s i t i o n (BTP) ETSB 11-5, "Postulated Radioactive Release due t o Waste Gas System Leak o r (continued)

North Anna U n i t s 1 and 2 5.5-10

Programs and Manuals 5.5 5.5 Proqrams and Manuals 5.5.11 Explosive Gas and Storage Tank R a d i o a c t i v i t y Monitoring Program (conti nued)

F a i l u r e ". The l i q u i d radwaste q u a n t i t i e s s h a l l be determined i n accordance w i t h Standard Review Plan, Section 15.7.3, "Postulated Radioactive Re1 ease due t o Tank Fai 1 ures".

The program s h a l l include:

a.

The 1 imi t s f o r concentrations o f hydrogen and oxygen i n t h e Gaseous Waste System and a surveillance program t o ensure the l i m i t s are maintained. Such l i m i t s s h a l l be appropriate t o the system's design c r i t e r i a ( i.e.,

whether o r n o t the system i s designed t o withstand a hydrogen explosion) ;

b.

A surveillance program t o ensure t h a t t h e q u a n t i t y o f r a d i o a c t i v i t y contained i n each gas storage tank i s l e s s than t h e amount t h a t would r e s u l t i n a whole body exposure o f L 0.5 rem t o any i n d i v i d u a l i n an u n r e s t r i c t e d area, i n the event o f an uncontrol 1 ed re1 ease o f the tanks ' contents; and

c.

A surveillance program t o ensure t h a t the q u a n t i t y o f r a d i o a c t i v i t y contained i n each o f t h e f o l l o w i n g outdoor tanks t h a t are not surrounded by 1 iners, dikes, o r wall s, capable o f holding t h e tanks' contents and t h a t do n o t have tank overflows and surroundi ng area drains 1 i qui d radwaste i o n exchanger system i s less than t h e amount t h a t would r e s u l t i n concentrations greater than t h e l i m i t s o f 10 CFR 20, Appendix B, Table 2, Column 2, excluding t r i t i u m, a t t h e nearest potable water supply and t h e nearest surface water supply i n an u n r e s t r i c t e d area, i n the event o f an uncontrolled release o f t h e tanks' contents:

1. Refueling Water Storage Tank;

2. Casing Cooling Storage Tank;

3. PG Water Storage Tank;

4. Boron Recovery Test Tank; and

5. Any Outside Temporary Tank.

The provisions o f SR 3.0.2 and SR 3.0.3 are applicable t o t h e Explosive Gas and Storage Tank R a d i o a c t i v i t y Monitoring Program surveillance frequencies.

North Anna Units 1 and 2 5.5-11

Programs and Manuals 5.5 5.5 Proqrams and Manuals 5.5.12 Cliesel Fuel O i l Testing Program A diesel f u e l o i l t e s t i n g program t o implement required t e s t i n g o f both new f u e l o i l and stored fuel o i l s h a l l be established. The program s h a l l i n c l ude sampl i ng and t e s t i n g requi rements, and acceptance c r i t e r i a, a l l i n accordance w i t h applicable ASTM Standards. The purpose o f the program i s t o e s t a b l i s h the following:

a.

A c c e p t a b i l i t y o f new f u e l o i l f o r use p r i o r t o a d d i t i o n t o storage tanks by determining t h a t t h e f u e l o i l has:

1. an API g r a v i t y o r an absolute s p e c i f i c g r a v i t y w i t h i n l i m i t s,

2. a f l a s h p o i n t and kinematic v i s c o s i t y w i t h i n l i m i t s f o r ASTM 2D f u e l o i 1, and

3. water and sediment 5 0.05%.

b.

Within 31 days f o l l o w i n g a d d i t i o n o f t h e new f u e l o i l t o storage tanks v e r i f y t h a t t h e properties o f t h e new f u e l o i l, other than those addressed i n a. above, are w i t h i n l i m i t s f o r ASTM 2D f u e l o i l ;

c.

Total p a r t i c u l a t e concentration o f t h e stored f u e l o i l i s I 10 mg/l when tested every 92 days i n accordance w i t h ASTM D-2276, Method A-2 o r A-3; and cl.

The provisions o f SR 3.0.2 and SR 3.0.3 are applicable t o the Diesel Fuel O i 1 Testing Program t e s t i n g Frequencies.

5.5.13 Techni cal Speci f i cations (TS) Bases Control Program This program provides a means f o r processing changes t o t h e Bases o f these Technical Specifications.

a,.

Changes t o t h e Bases o f the TS s h a l l be made under appropriate administrative controls and reviews.

b.

Licensees may make changes t o Bases without p r i o r NRC approval provided the changes do not r e q u i r e e i t h e r o f t h e following:

1. a change i n t h e TS incorporated i n t h e license; o r (cont i nued)

North Anna Units 1 and 2 5.5-12

Programs and Manual s 5.5 5.5 Programs and Manuals 5.5.1.3 Technical Specifications (TS) Bases Control Program (continued)

b.

(continued)

2. a change t o the UFSAR o r Bases t h a t requires NRC approval pursuant t o 10 CFR 50.59.

c.

The Bases Control Program s h a l l contain provisions t o ensure t h a t t h e Bases are maintained consistent w i t h t h e UFSAR.

d.

Proposed changes t h a t meet the c r i t e r i a o f S p e c i f i c a t i o n 5.5.13b above s h a l l be reviewed and approved by t h e NRC p r i o r t o implementation. Changes t o t h e Bases implemented without p r i o r NRC approval s h a l l be provided t o the NRC on a frequency consistent w i t h 10 CFR 5O.7l(e).

5.5.1.4 Safety Function Determination Program (SFDP)

This program ensures loss o f safety f u n c t i o n i s detected and appropriate actions taken. Upon e n t r y i n t o LC0 3.0.6, an evaluation s h a l l be made t o determine i f 1 oss o f safety f u n c t i o n e x i s t s.

A d d i t i o n a l l y, other appropriate actions may be taken as a r e s u l t o f t h e support system i n o p e r a b i l i t y and corresponding exception t o entering supported system Condition and Required Actions. This program implements the requirements o f LC0 3.0.6.

The SFDP s h a l l contain t h e following:

a.

Provisions f o r cross t r a i n checks t o ensure a loss o f t h e c a p a b i l i t y t o perform t h e safety f u n c t i o n assumed i n t h e accident analysis does n o t go undetected;

b.

Provisions f o r ensuring the p l a n t i s maintained i n a safe c o n d i t i o n i f a loss o f f u n c t i o n condition exists;

c.

Provisions t o ensure t h a t an inoperable supported system's Completion Time i s not inappropriately extended as a r e s u l t o f m u l t i p l e support system i n o p e r a b i l i t i e s ; and

d.

Other appropriate 1 i m i t a t i o n s and remedi a1 o r compensatory actions.

A loss o f safety function e x i s t s when, assuming no concurrent s i n g l e f a i l u r e, no concurrent loss o f o f f s i t e power o r l o s s o f o n s i t e diesel generator(s), a safety f u n c t i o n assumed i n the accident (continued)

North Anna Units 1 and 2 5.5-13

Programs and Manual s 5.5 5.5 Progra.ms and Manuals 5.5.14 Safety Function Determi n a t i o n Program (SFDP) (continued) analysis cannot be performed. For the purpose o f t h i s program, a l o s s o f safety f u n c t i o n may e x i s t when a support system i s i noperabl e, and:

a.

A required system redundant t o t h e system(s) supported by the inoperable support system i s also inoperable; o r

b.

A required system redundant t o t h e system(s) i n t u r n supported by t h e inoperable supported system i s also inoperable; o r

c.

A required system redundant t o t h e support system(s) f o r t h e supported systems (a) and (b) above i s also inoperable.

The SFDP i d e n t i f i e s where a loss o f safety function e x i s t s. I f a l o s s o f safety f u n c t i o n i s determined t o e x i s t by t h i s program, the a.ppropriate Conditions and Required Actions o f the LC0 i n which the l o s s o f safety f u n c t i o n e x i s t s are required t o be entered. When a loss o f safety f u n c t i o n i s caused by t h e i n o p e r a b i l i t y o f a s i n g l e Technical S p e c i f i c a t i o n support system, the appropriate Conditions a.nd Required Actions t o enter are those o f the support system.

5.5.15

<:ontainment Leakage Rate Testing Program

a.

A program s h a l l e s t a b l i s h the leakage r a t e t e s t i n g o f the containment as required by 10 CFR 50.54(0) and 10 CFR 50, Appendix J, Option B, as modified by approved exemptions. This program s h a l l be i n accordance w i t h the guidelines contained i n Regul a t o r y Guide 1.163, "Performance-Based Contai nment Leak-Test Program," dated September 1995 as modified by the f o l l o w i n g except i on :

N E I 94-01-1995, Section 9.2.3:

The f i r s t U n i t 1 Type A t e s t -

performed a f t e r t h e A p r i l 3, 1993 Type A t e s t s h a l l be performed no l a t e r than A p r i l 2, 2008.

bf.

The calculated peak containment i n t e r n a l pressure f o r t h e design basis loss o f coolant accident, Pa, i s 44.1 psig. The containment design pressure i s 45 psig.

c.

The maximum allowable containment leakage rate, La, a t Pa, s h a l l be 0.1% o f containment a i r weight per day.

(continued)

North Anna U n i t s 1 and 2 5.5-14

Programs and Manual s 5.5 5.5 Programs and Manuals 5.5.15 Containment Leakage Rate Testing Program (continued)

d.

Leakage Rate acceptance c r i t e r i a are:

1. P r i o r t o e n t e r i n g a MODE where containment OPERABILITY i s required, t h e containment leakage r a t e acceptance c r i t e r i a are:

< 0.60 La f o r t h e Type B and Type C t e s t s on a Maximum Path Basis and I 0.75 La f o r Type A t e s t s.

During operation where containment OPERABILITY i s required, t h e containment leakage r a t e acceptance c r i t e r i a are:

I 1.0 La f o r o v e r a l l containment leakage r a t e and < 0.60 La f o r t h e Type B and Type C t e s t s on a Minimum Path Basis.

2. Overall a i r l o c k leakage r a t e t e s t i n g acceptance c r i t e r i o n i s I 0.05 La when tested a t > Pa.

e.

The provisions o f SR 3.0.3 are applicable t o t h e Containment Leakage Rate Testing Program.

f.

Nothing i n these Technical S p e c i f i c a t i o n s s h a l l be construed t o modify t h e t e s t i n g Frequencies required by 10 CFR 50, Appendix J.

North Anna U n i t s 1 and 2

Report i ng Requ i rements 5.6 5.6 Reporting Requirements CORE OPERAT l NG L l M l TS REPORT (COLR) b.

(cont i nued)

14. BAW-10199P-A, "The BWU C r i t i ca l Heat F l ux Correl a t i ons. "

15. BAW-10170P-A, "Stat i s t i ca l Core Des i gn f o r M i x i ng Vane Cores. "

16. EMF-2103 (P) (A), "Rea l i s t i c Large Break LOCA Methodo l ogy f o r Pressur i zed Water Reactors. "

17. EMF-96-029 (P) (A), "Reactor Ana l ys i s System f o r PWRs. "

18. BAW-10168P-A, "RSG LOCA - BWNT Loss-of-Coolant Accident Eva l uat i on Model f o r Rec i rcu l a t i ng Steam Generator P l ants, "

Vol ume I I on l y (SBLOCA model s).

c. The core operating limits shall be determined such that a l l applicable limits (e.g., fuel thermal mechanical limits, core therma l hydrau l i c l i m i t s, Emergency Core Cool i ng Systems (ECCS) l imits, nuclear limits such as SDM, transient analysis limits, and acc i dent ana l ysi s l i m i ts) o f the safety ana l ys i s are met.

d. The COLR, including any midcycle revisions or supplements, shall be provided upon issuance f o r each re1 oad cycle t o the NRC.

PAM Report When a report i s required by Condition B o f LC0 3.3.3, "Post Acc i dent Mon i t o r i ng (PAM) I nstrumentat i on, " a report sha l l be submitted within the following 14 days. The report shall outline the cause o f the inoperability, and the plans and schedule f o r restoring the instrumentation channels o f the Function t o OPERABLE status.

Steam Generator Tube l nspect i on Report A report shall be submitted within 180 days after the i n i t i a l entry into MODE 4 followin completion o f an inspection performed i n accordance w i t h the 8 pec i f i cat i on 5.5.8, "Steam Generator (SG)

Program. " The report sha l l i nc l ude :

a. The scope o f i nspect i ons performed on each SG, b.

Act i ve degradat i on mechan i sms found, North Anna Units 1 and 2 5.6-4

Reporting Requirements 5.6 5.6 Reporting Requirements 5.6.;7 Steam Generator Tube Inspection Report (continued)

c.

Nondestructive examination techniques u t i l i z e d f o r each degradation mechanism,

d.

Location, o r i e n t a t i o n ( i f 1 inear), and measured sizes ( i f avai 1 able) o f service induced indications,

e.

Number o f tubes plugged during t h e inspection outage f o r each a c t i v e degradation mechanism,

f. Total number and percentage o f tubes plugged t o date,

g.

The r e s u l t s o f condition monitoring, i n c l u d i n g the r e s u l t s o f tube p u l l s and i n - s i t u testing, and

h.

The e f f e c t i v e plugging percentage f o r a l l plugging i n each SG North Anna Units 1 and 2

Serial No.06-403 Docket Nos. 50-3381339 Mark-up of Technical Specifications Bases Changes (For Information Only)

North Anna Power Station Units 1 and 2 Virginia Electric and Power Company (Dominion)

REACTOR COOLANT SYSTEM (RCS)

(conti nued)

Low Temperature Overpressure Protection (LTOP) System B 3.4.12.1 RCS Operational LEAKAGE B 3.4.13.1 RCS Pressure I s o l a t i o n Valve (PIV) Leakage B 3.4.14.1 RCSLeakageDetection Instrumentation.......B3.4.1 5.1 RCS Specific A c t i v i t y B 3.4.16.1 RCS Loop I s o l a t i o n Valves B 3.4.17.1 RCS Isolated Loop Startup B 3.4.18.1 RCS Loops-Test Exceptions B 3.4.19.1 EMERGENCY CORE COOLING SYSTEMS (ECCS)

B 3.5.1.1 Accumulators B 3.5.1.1 ECCS-Operati ng B 3.5.2.1 ECCS-Shutdown B 3.5.3.1 Refuel i ng Water Storage Tank (RWST)

B 3.5.4.1 Seal I n j e c t i o n Flow B 3.5.5.1 Boron I n j e c t i o n Tank (BIT)

B 3.5.6.1 CONTAINMENT SYSTEMS B 3.6.1.1 Containment B 3.6.1.1 Containment A i r Locks B 3.6.2.1 Containment I s o l a t i o n Valves B 3.6.3.1 Containment Pressure B 3.6.4.1 Containment A i r Temperature B 3.6.5.1 Quench Spray (QS) System B 3.6.6.1 Recirculation Spray (RS) System B 3.6.7.1 Chemical Addition System B 3.6.8.1 Y

PLANT SYSTEMS Main Steam Safety Valves (MSSVs).......

Main Steam T r i p Valves (MSTVs)

Main Feedwater Is01 a t i on Valves (MFIVs). Main Feedwater Pump Discharge Valves (MFPDVs).

Main Feedwater Regul ating Valves (MFRVs).

and Main Feedwater Regulating Bypass Val ves (MFRBVs)

Steam Generator Power Operated R e l i e f Valves (SG PORVS)...............

A u x i l i a r y Feedwater (AFW) System Emergency Condensate Storage Tank (ECST)..

Secondary Speci f i c A c t i v i t y Service Water (SW) System..........

Ultimate Heat Sink (UHS)..........

Main Control Room/Emergency Swi tchgear Room (MCR ESGR) Emergency Vent i 1 a t i on System (EVS I -MODES 1. 2. 3. and 4.......

Mai n Control Room/Emergency Swi tchgear Room (MCRIESGR) A i r Conditioning System (ACS)

North Anna Units 1 and 2 i i Revision-

RCS Loops-MODES 1 and 2 B 3.4.4 BASES APPLICABLE Both transient and steady state analyses have been performed SAFETY ANALYSES t o establish the effect of flow on the departure from (continued) nucleate boi 1 ing (DNB). The transient and accident analyses for the unit have been performed assuming three RCS loops are in operation. The majority of the unit safety analyses are based on initial conditions at high core power or zero power.

The accident analyses that are most important to RCP operation are the complete loss of forced reactor flow, single reactor coolant pump locked rotor, partial loss of forced reactor flow, and rod withdrawal events (Ref. 1).

The DNB analyses assume normal three loop operation.

Uncertainties in key unit operating parameters, nuclear and thermal parameters, and fuel fabrication parameters are considered statistically such that there i s a t least a 95 percent probability that DNB will not occur for the 1 imi ting power rod. Key unit parameter uncertainties are used to determine the unit departure from nucleate boi 1 i ng rati o (DNBR) uncertainty. This DNBR uncertainty, combined with the DNBR limi t, establishes a design DNBR value which must be met in unit safety analyses and i s used to determine the pressure and temperature Safety Limit (SL). Since the parameter uncertainties are considered in determining the design DNBR value, the unit safety analyses are performed using values of i n p u t parameters without uncertainties. Therefore, nominal operating values for reactor coolant flow are used in the accident analyses.

The unit i s designed to operate with all RCS loops in operation t o maintain DNBR above the 1 imit during all normal operations and anticipated transients. By ensuring heat transfer in the nucleate boiling region, adequate heat transfer i s provided between the fuel cladding and the reactor coolant.

RCS Loops-MODES 1 and 2 satisfy Criterion 2 of 10 CFR 50.36(c) (2) (i i).

The purpose of this LC0 i s to require an adequate forced flow rate for core heat removal. Flow i s represented by the number of RCPs in operation for removal of heat by the SGs. To meet safety anal ysi s acceptance criteria for DNBR, three pumps are required at rated power.

An OPERABLE RCS loop consists of an OPERABLE RCP in operation providing forced flow for heat transport and an OPERABLE SG,

+ h Generator Survpi 11-North Anna Units 1 and 2 B 3.4.4-2 Revision-

RCS LOOPS-MODE 3 B 3.4.5 e

BASES LC0 U t i l i z a t i o n o f the Note i s permitted provided t h e f o l l o w i n g (cont i nued) conditions are met, along w i t h any other conditions imposed by i n i t i a l startup t e s t procedures:

a. No operations are permitted t h a t would d i l u t e the RCS boron concentration w i t h coolant a t boron concentrations l e s s than required t o ensure the SDM o f LC0 3.1.1, thereby maintaining t h e margin t o c r i t i c a l i t y. Boron reduction w i t h cool ant a t boron concentrations 1 ess than required t o assure the SDM i s maintained i s prohibited because a uni form concentration d i s t r i b u t i on throughout t h e RCS cannot be ensured when i n natural c i r c u l a t i o n ;

and

b. Core o u t l e t temperature i s maintained a t l e a s t 10°F below saturation temperature, so t h a t no vapor bubble may form and possibly cause a natural c i r c u l a t i o n flow obstruction.

An OPERABLE RCS loop consists o f one OPERABLE RCP and one OPERABLE SGj 9 which has the minimum water l e v e l specified i n SR 3.4.5.2.

An RCP i s OPERABLE i f i t i s capable o f being powered and i s able t o provide forced flow i f required.

APPLICABILITY I n MODE 3, t h i s LC0 ensures forced c i r c u l a t i o n o f the reactor coolant t o remove decay heat from the core and t o provi de proper boron mi x i ng.

Operation i n other MODES i s covered by:

LC0 3.4.4, "RCS Loops-MODES 1 and 2" ;

LC0 3.4.6, "RCS LOOPS-MODE 4";

LC0 3.4.7, "RCS Loops-MODE 5, Loops F i l l e d " ;

LC0 3.4.8, "RCS Loops-MODE 5, Loops Not F i l l e d " ;

LC0 3.9.5, "Residual Heat Removal (RHR) and Coolant C i r c u l at ion-High Water Level " (MODE 6) ; and LC0 3.9.6, "Residual Heat Removal (RHR) and Cool ant C i r c u l a t i on-Low Water Level " (MODE 6).

North Anna Units 1 and 2 3 3.4.5-3

RCS Loops-MODE 4 B 3.4.6 BASES LC0 I 280°F. This r e s t r a i n t i s t o prevent a low temperature (cont i nued) overpressure event due t o a thermal t r a n s i e n t when an RCP i s started.

An OPERABLE RCS loop i s comprised o f an OPERABLE RCP and an S i m i l a r l y f o r t h e RHR System, an OPERABLE RHR loop i s comprised o f an OPERABLE RHR pump capable o f providing forced f l o w t o an OPERABLE RHR heat exchanger. RCPs and RHR pumps are OPERABLE i f they are capable o f beirig powered and are able t o provide forced f l o w i f required.

APPLICABILITY I n MODE 4, t h i s LC0 ensures forced c i r c u l a t i o n o f t h e r e a c t o r coolant t o remove decay heat from t h e core and t o provide proper boron mixing. One loop o f e i t h e r RCS o r RHR provides s u f f i c i e n t c i r c u l a t i o n f o r these purposes. However, two loops c o n s i s t i n g o f any combination o f RCS and RHR loops are required t o be OPERABLE t o provide redundancy f o r heat removal.

Operation i n other MODES i s covered by:

LC0 3.4.4, "RCS Loops-MODES 1 and 2";

LC0 3.4.5, "RCS Loops-MODE 3";

LC0 3.4.7, "RCS Loops-MODE 5, Loops F i l l e d " ;

LC0 3.4.8, "RCS Loops-MODE 5, Loops Not F i l l e d " ;

LC0 3.9.5, "Residual Heat Removal (RHR) and Coolant C i r c u l ation-High Water Level " (MODE 6) ; and LC0 3.9.6, "Residual Heat Removal (RHR) and Coolant C i r c u l ation-Low Water Level " (MODE 6).

ACTIONS I f one required loop i s inoperable, redundancy f o r heat removal i s l o s t. Action must be i n i t i a t e d t o r e s t o r e a second RCS o r RHR loop t o OPERABLE status. The immediate Completion Time r e f l e c t s t h e importance o f maintaining t h e a v a i l a b i 1 i t y o f two paths f o r heat removal.

North Anna U n i t s 1 and 2 B 3.4.6-3 Revision +Q-

RCS Loops-MODE 5, Loops Fi1 l e d B 3.4.7 BASES LC0 U t i l i z a t i o n o f Note 1 i s permitted provided the following (cont i nued) conditions are met, along w i t h any other conditions imposed by i n i t i a l s t a r t u p t e s t procedures:

a. No operations are permitted t h a t would d i l u t e the RCS boron concentration w i t h coolant a t boron concentrations less than required t o meet the SDM o f LC0 3.1.1, therefore maintaining the margin t o c r i t i c a l i t y. Boron reduction w i t h cool ant a t boron concentrations 1 ess than required t o assure the SDM i s maintained i s prohibited because a uniform concentration d i s t r i b u t i o n throughout the RCS cannot be ensured when i n natural circulation; and

b. Core o u t l e t temperature i s maintained a t l e a s t 10°F below saturation temperature, so t h a t no vapor bubble may form and possibly cause a natural c i r c u l a t i o n flow obstruction.

Note 2 allows one RHR loop t o be inoperable f o r a period o f up t o 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months , provided t h a t the other RHR loop i s OPERABLE and i n operation. This permits periodic survei 1 lance t e s t s t o be performed on the inoperable loop during the only time when such t e s t i n g i s safe and possible.

Note 3 requires t h a t the secondary side water temperature o f each SG be I 50°F above each o f the RCS cold l e g temperatures before the s t a r t o f a reactor coolant pump (RCP) w i t h an RCS cold l e g temperature I 280°F. This r e s t r i c t i o n i s t o prevent I a low temperature overpressure event due t o a thermal transient wnen an RCP i s started.

Note 4 provides f o r an orderly t r a n s i t i o n from MODE 5 t o MODE 4 during a planned heatup by permi t t i n g removal o f RHR loops from operation when a t l e a s t one RCS loop i s i n operation. This Note provides f o r the t r a n s i t i o n t o MODE 4 where an RCS loop i s permitted t o be i n operation and replaces the RCS c i r c u l a t i o n function provided by the RHR loops w i t h c i r c u l a t i o n provided by an RCP.

RHR pumps are OPERABLE if they are capable o f being powered and are able t o provide flow i f required. Al+ fPHMtE SG can perform as a heat sink v i a natural c i r c u l a t i o n when i t has an adequate water l e v e l and i s 0PERABLE.i-North Anna Units 1 and 2 B 3.4.7-3 Revision.Pe?Y

RCS Operational LEAKAGE B 3.4.13 BASES APPLICABLE Except f o r primary t o secondary LEAKAGE, the safety analyses SAFETY ANALYSES do not address operational LEAKAGE. However, other operational LEAKAGE i s related t o the safety analyses f o r LOCA; the amount of leakage can a f f e c t the p r o b a b i l i t y o f such an event. The safety analysis f o r an event r e s u l t i n g i n secondary steam release t o the atmosphere, such as a steam generator tube rupture (SGTR). The 1 eakage contaminates the I

secondary f l u i d.

The UFSAR (Ref. 3) analysis f o r SGTR assumes the contaminated secondary f l u i d i s released v i a power operated re1 i e f valves o r safety valves. The source term i n the primary system coolant i s transported t o the affected (ruptured) steam generator by the break flow. The affected steam generator discharges steam t o the environment f o r 30 minutes u n t i l the generator i s manually isolated. The 1 gpm primary t o secondary LEAKAGE transports the source term t o the unaffected steam generators. Releases continue throush the unaffected steam senerators u n t i 1 the Residual Heat Removal System i s placed-i n service.

The MSLB i s less l i m i t i n g f o r s i t e radiation releases than the SGTR. The safety analysis f o r the MSLB accident assumes 1 gpm primary t o secondary LEAKAGE as an i n i t i a l condition.

The dose consequences r e s u l t i n g from the MSLB and SGTR accidents are within the l i m i t s defined i n the s t a f f approved 1 i censi ng basi s.

The RCS operational LEAKAGE s a t i s f i e s C r i t e r i o n 2 o f 10 CFR 50.36(c) (2) (i i).

LC0 RCS operational LEAKAGE shall be 1 imi ted to:

a. Pressure Boundary LEAKAGE No pressure boundary LEAKAGE i s a1 1 owed, being. i n d i c a t i v e o f material deterioration. LEAKAGE o f t h i s type i s unacceptable as the leak i t s e l f could cause f u r t h e r deterioration, r e s u l t i n g i n higher LEAKAGE. Viol a t i o n o f (continued)

North Anna Units 1 and 2 B 3.4.13-2 revision^

RCS Operational LEAKAGE B 3.4.13 BASES LC0

a.

(continued)

Pressure Boundary LEAKAGE (continued) t h i s LC0 could r e s u l t i n continued degradation o f the RCPB. LEAKAGE past seals and gaskets i s not pressure boundary LEAKAGE.

Unidentified LEAKAGE One gallon per minute (gpm) o f unidentified LEAKAGE i s a1 1 owed as a reasonabl e mi nimum detectabl e amount t h a t the containment a i r monitoring and containment sump 1 eve1 monitoring equipment can detect w i t h i n a reasonable time period. Violation o f t h i s LC0 could r e s u l t i n continued degradation o f the RCPB, i f the 'LEAKAGE i s from the pressure boundary.

I d e n t i f i e d LEAKAGE Up t o 10 gpm o f i d e n t i f i e d LEAKAGE i s considered a1 lowable because LEAKAGE i s from known sources t h a t do not i n t e r f e r e w i t h detection o f unidenti f i e d LEAKAGE and i s well w i t h i n the capability o f the RCS Makeup System.

I d e n t i f i e d LEAKAGE includes LEAKAGE t o the containment from s p e c i f i c a l l y known and 1 ocated sources, but does not include pressure boundary LEAKAGE o r control 1 ed reactor coolant pump (RCP) seal leakoff (a normal function not considered LEAKAGE). V i 01 a t i on o f t h i s LC0 could resul t i n continued degradation o f a component o r system.

@ Primary t o Secondary LEAKAGE through Any One SG -

U North Anna Units 1 and 2 B 3.4.13-3 Revision %

RCS Operati onal LEAKAGE B 3.4.13 BASES APPLICABILITY I n MODES 1, 2, 3, and 4, the potential f o r RCPB LEAKAGE i s greatest when the RCS i s pressurized.

I n MODES 5 and 6, LEAKAGE l i m i t s are not required because the reactor coolant pressure i s f a r lower, r e s u l t i n g i n 1 ower stresses and reduced potenti a1 s f o r LEAKAGE.

LC0 3.4.14, "RCS measures 1 eakage t h i s LCO. O f the 1 eakage measured LEAKAGE when the r e s u l t i n a loss i

ncl uded i n the a1 lowabl e i d e n t i f i e d LEAKAGE.

Pressure I s o l a t i o n Valve ( P I V ) Leakage,"

through each individual PIV and can impact two PIVs i n series i n each isolated l i n e,

through one PIV does not r e s u l t i n RCS other i s leak t i g h t. I f both valves leak and of mass from the RCS, the loss must be ACTIONS A. 1 Unidentified LEAKAGE p i d e n t i f i e d LEAKAGEi w-p&my tc

-in excess o f the LC0 l i m i t s must be reduced t o w i t h i n l i m i t s w i t h i n 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months . This Completion Time allows time t o v e r i f y leakage rates and either i d e n t i f y unidentified LEAKAGE o r reduce LEAKAGE t o w i t h i n l i m i t s before the reactor must be shut down. This action i s necessary t o prevent further deterio B. l and B.2 F If any p essure boundary LEAKAGE, i d e n t i f i e d LEAKAGE, r. r n r ; n ; r r \\ r r y LEAW&

cannot be reduced t o w i t h i n l i m i t s w i t h i n 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months , the reactor must be brought t o lower pressure conditions t o reduce the severity o f the LEAKAGE and i t s potential consequences. It should be noted t h a t LEAKAGE past seals and gaskets i s not pressure boundary LEAKAGE. The reactor must be brought t o MODE 3 w i t h i n 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and MODE 5 w i t h i n 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months . This action reduces the LEAKAGE and a1 so reduces the factors that tend t o degrade the pressure boundary.

The a1 1 owed Completion Times are reasonabl e, based on operating experience, t o reach the required u n i t conditions from f u l l power conditions i n an orderly manner and without challenging u n i t systems. I n MODE 5, the pressure stresses acting on the RCPB are much lower, and f u r t h e r deterioration i s much less l i k e l y.

North Anna Units 1 and 2 B 3.4.13-4 Revision-

RCS Operati onal LEAKAGE B 3.4.13 BASES SURVEILLANCE SR 3.4.13.1 REOU IREMENTS Verifying RCS LEAKAGE to be within the LC0 limits ensures the integrity of the RCPB i s maintained. Pressure boundary LEAKAGE would at f i r s t appear as unidentified LEAKAGE and can only be positively identified by inspection. I t should be noted that LEAKAGE past seals and gaskets i s not pressure boundary LEAKAGE. Unidentified LEAKAGE and identified LEAKAGE are determined by performance of an RCS water inventory balance. f4wmy t c V E

' s ;? s+

The RCS water inventory balance must be met with the reactor a t steady state operating conditions (stab1 e temperature, pressurizer and makeup tank 1 evel s, makeup RCP seal injection and return flows).

Note#-

that this SR i s not k e performed until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after establishing operation. The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months allowance provides t o collect and process all necessary data after stable plant conditions are established.

Steady state operation i s required to perform a proper inventory balance since calculations during maneuvering are not useful. For RCS operational LEAKAGE determination by water inventory balance, steady state i s defined as stable RCS pressure, temperature, power level, pressurizer and makeup tank levels, makeup and 1 etdown, and RCP seal injection and return flows.

An early warning of pressure boundary LEAKAGE or ur~identified LEAKAGE i s provided by the automatic systems that monitor the containment atmosphere radioactivity and the containment sump level. I t should be noted that LEAKAGE past seals and gaskets i s not pressure boundary LEAKAGE.

These leakage detection systems are specified in LC0 3.4.15, "RCS Leakage Detection Instrumentation."

The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Frequency i s a reasonable interval t o trend LEAKAGE and recognizes the importance of early leakage detection in the prevention of accidents.

'North Anna Units 1 and 2 B 3.4.13-5 Revision p

RCS Operational LEAKAGE B 3.4.13 BASES SURVEILLANCE SR 3.4.13.2 REFERENCES

1. UFSAR, Section 3.1.26.

2. -Regulatory Guide 1.45, May 1973.

3. UFSAR, Chapter 15.

/

's North Anna Units 1 and 2 Revision 0

INSERT B 3.4.13 A that primary to secondary LEAKAGE from all steam generators (SGs) is one gallon per minute or increases to one gallon per minute as a result of accident induced conditions. The LC0 requirement to limit primary to secondary LEAKAGE through any one SG to less than or equal to 150 gallons per day is significantly less than the conditions assumed in the safety analysis.

INSERT B 3.4.13 B The limit of 150 gallons per day per SG is based on the operational LEAKAGE performance criterion in NEI 97-06, Steam Generator Program Guidelines (Ref. 4). The Steam Generator Program operational LEAKAGE performance criterion in NEI 97-06 states, The RCS operational primary to secondary leakage through any one SG shall be limited to 150 gallons per day." The limit is based on operating experience with SG tube degradation mechanisms that result in tube leakage. The operational leakage rate criterion in conjunction with the implementation of the Steam Generator Program is an effective measure for minimizing the frequency of steam generator tube ruptures.

INSERT B 3.4.13 C Note 2 states that this SR is not applicable to primary to secondary LEAKAGE because LEAKAGE of 150 gallons per day cannot be measured accurately by an RCS water inventory balance.

INSERT B 3.4.13 D This SR verifies that primary to secondary LEAKAGE is less than or equal to 150 gallons per day through any one SG. Satisfying the primary to secondary LEAKAGE limit ensures that the operational LEAKAGE performance criterion in the Steam Generator Program is met. If this SR is not met, compliance with LC0 3.4.20, "Steam Generator Tube Integrity," should be evaluated.

The 150 gallons per day limit is measured at room temperature as described in Reference 5.

The operational LEAKAGE rate limit applies to LEAKAGE through any one SG. If it is not practical to assign the LEAKAGE to an individual SG, all the primary to secondary LEAKAGE should be conservatively assumed to be ftom one SG.

The Surveillance is modified by a Note, which states that the Surveillance is not required to be performed until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after establishment of steady state operation. For RCS primary to secondary LEAKAGE determination, steady state is defined as stable RCS pressure, temperature, power level, pressurizer and makeup tank levels, makeup and letdown, and RCP sea! injection and return flows.

The Surveillance Frequency of 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months is a reasonable interval to trend primary to secondary LEAKAGE and recognizes the importance of early leakage detection in the prevention of accidents. The primary to secondary LEAKAGE is determined using continuous process radiation monitors or radiochemical grab sampling in accordance with the EPRI guidelines (Ref.

5).

INSERT B 3.4.13 E

4.

NEI 97-06, "Steam Generator Program Guidelines."

5.

EPRI, "Pressurized Water Reactor Primary-to-Secondary Leak Guidelines."

SG Tube lntegr B 3.4.

B 3.4 REACTOR COOLANT SYSTEM (RCS)

B 3.4.20 Steam Generator (SG) Tube l ntegr i t y BASES BACKGROUND Steam generator (SG) tubes are sma l l d i ameter, t h in wa l l ed tubes that carry primary coolant through the primary t o secondary heat exchangers. The SG tubes have a number o f important safety functions. SG tubes are an integral part o f the reactor coolant pressure boundary (RCPB) and, as such, are relied on t o maintain the primary system's pressure and i nventory. The SG tubes i sol ate the rad i oact i ve f i ss i on products i n the primary cool ant from the secondary system.

In addition, as part of the RCPB, the SG tubes are unique i n that they act as the heat transfer surface between the primary and secondary systems t o remove heat from the pr i mary system. Th i s Spec i f i cat i on addresses on l y the RCPB i ntegr i t y functi on of the SG. The SG heat remova l funct i on i s addressed by LC0 3.4.4, "RCS Loops-MODES 1 and 2,"

LC0 3.4.5, "RCS Loops-MODE 3," LC0 3.4.6, "RCS Loops-MODE 4, " and LC0 3.4.7, "RCS Loops-MODE 5, Loops Fi I led."

SG tube integrity means that the tubes are capable o f performi ng the i r i ntended RCPB safety funct i on cons i stent with the licensing basis, including applicable regulatory requ i rements.

SG tubing i s subject t o a variety o f degradation mechani sms.

SG tubes may experience tube degradation related t o corrosion phenomena, such as wastage, pi tt i ng, i ntergranu l ar attack, and stress corrosion cracking, along with other mechanically induced phenomena such as denting and waar.

These degradat i on mechan i sms can i mpa i r tube i ntegr i t y i f they are not managed effectively. The SG performance criteria are used t o manage SG tube degradation.

Spec i f i cat i on 5.5.8, "Steam Generator (SG) Program, "

requires that a program be established and implemented t o ensure that SG tube integrity i s maintained. Pursuant t o Spec i f i cat i on 5.5.8, tube i ntegr i t y i s ma i nta i ned when the SG performance c r i t e r i a are met. There are three SG performance c r i t e r i a : structura l i ntegr i t y, acc i dent i nduced l eakage, and operat i ona l LEAKAGE. The SG performance criteria are described i n Specification 5.5.8. Meeting the (cont i nued)

North Anna Units 1 and 2 B 3.4.20-1

SG Tube I n t e g r i t y B 314.20 BASES BACKGROUND SG performance c r i t e r i a provi des reasonable assurance o f (continued) maintaining tube i n t e g r i t y a t normal and accident conditions.

The processes used t o meet the SG performance c r i t e r i a are defined by the Steam Generator Program Gui del i nes (Ref. 1).

APPLICABLE The steam generator tube rupture (SGTR) accident i s the SAFETY ANALYSES l i m i t i n g basis event f o r SG tubes and avoiding a SGTR i s the basis f o r t h i s Specification. The analysis o f a SGTR event assumes a bounding primary t o secondary LEAKAGE r a t e o f 1 gpm, which i s conservative w i t h respect t o the operational LEAKAGE r a t e l i m i t s i n LC0 3.4.13, "RCS Operational LEAKAGE,"

plus the leakage r a t e associated with a double-ended rupture o f a single tube. The UFSAR analysis f o r SGTR assumes the contaminated secondary f l u i d i s re1 eased v i a power operated re1 i e f valves o r safety valves.

The source term i n the primary system coolant i s transported t o the affected (ruptured) steam generator by the break flow. The affected steam generator discharges steam t o the environment f o r 30 minutes u n t i l the generator i s manually isolated. The 1 gpm primary t o secondary LEAKAGE transports the source term t o the unaffected steam generators. Releases continue through the unaffected steam generators u n t i l the Residual Heat Removal System i s placed i n service.

The analysis f o r design basis accidents and transients other than a SGTR assume the SG tubes r e t a i n t h e i r structural i n t e g r i t y (i

.e.,

they are assumed not t o rupture.) I n these analyses, the steam djscharge t o the atmosphere i s based on the t o t a l primary t o secondary LEAKAGE from a1 1 SGs o f 1 gallon per minute o r i s assumed t o increase t o 1 gallon per minute as a r e s u l t o f accident induced conditions. For accidents that do not involve fuel damage, the primary coolant a c t i v i t y level o f DOSE EQUIVALENT 1-131 i s assumed t o be equal t o the LC0 3.4.16, "RCS Specific Activity,"

l i m i t s. For accidents that assume fuel damage, the primary coolant a c t i v i t y i s a function o f the amount o f a c t i v i t y released from the damaged fuel. The dose consequences o f these events are w i t h i n the 1 i m i t s o f GDC 19 (Ref. 2),

10 CFR 50.67 (Ref. 3) o r RG 1.183 (Ref. 4), as appropriate.

SG tube i n t e g r i t y s a t i s f i e s Criterion 2 o f 10 CFR 50.36 (c) (2) (i i ).

North Anna Units 1 and 2 B 3.4.20-2

SG Tube lntearitv B 3y4.26 BASES LC0 The LC0 requires t h a t SG tube integrity be maintained. The LC0 also requ i res t h a t a I I SG tubes t h a t satisfy the repa i r c r i t e r i a be plugged i n accordance with the Steam Generator Program.

During an SG inspection, any inspected tube that satisfies the Steam Generator Program repair c r i t e r i a i s removed from service by plugging. I f a tube was determined t o satisfy the repair c r i t e r i a but was not plugged the tube may s t i l l have tube i ntegr i t y.

I n the context o f t h i s Spec i f i cat i on, a SG tube i s def i ned as the entire length o f the tube, including the tube wal l between the tube-to-tubesheet weld a t the tube i n l e t and the tube-to-tubesheet weld a t the tube outlet. The tube-to-tubesheet weld i s not considered part o f the tube.

A SG tube has tube integrity when it satisfies the SG performance c r i t e r i a. The SG performance c r i t e r i a are defined in Specification 5.5.8, "Steam Generator Program,"

and describe acceptable SG tube performance. The Steam Generator Program a l so provides the eva I uat i on process f o r determ i n i ng conformance with the SG performance c r i t e r i a.

There are three SG performance c r i t e r i a : structura I integrity, accident induced leakage, and operationa LEAKAGE. Fa i lure t o meet any one o f these c r i t e r i a considered f a i l u r e t o meet the LCO.

The structural integrity performance c r i t e r i o n provi marg i n o f safety against tube burst o r cot lapse under and acc i dent cond i t i ons, and ensures structura I i ntegr i t y o f the SG tubes under a i I anticipated transients included i n the design specification. Tube burst i s defined as, "The gross structural f a i l u r e o f the tube wall. The condition typical l y corresponds t o an unstable opening displacement (e. g., o en i ng area i ncreased i n response t o constant pressure 7 accompan i ed by duct i I e (p l ast i c) tear i ng o f the tube material a t the ends o f the degradation. " Tube cot lapse i s defined as, "For the load displacement curve f o r a given structure, cot lapse occurs a t the top o f the load versus displacement curve where the slope o f the curve becomes zero." The structural integrity performance c r i t e r i o n provides guidance on assessing loads t h a t have a sign i f icant effect on burst o r col lapse. I n that context, the term "significant" i s defined as "An accident loading condition other than d i f f e r e n t i a l pressure i s considered significant (cont i nued)

S des a

. norma I North Anna Units 1 and 2 B 3.4.20-3

SG Tube I n t e g r i t y B 3.4.20 BASES LC0 when the addition o f such loads i n the assessment o f the (continued) s t r u c t u r a l i n t e g r i t y performance c r i t e r i o n could cause a 1 ower s t r u c t u r a l 1 imi t o r 1 imi t i n g burst/col lapse condition t o be established." For tube i n t e g r i t y evaluations, except f o r circumferential degradation, a x i a l thermal loads are c l a s s i f i e d as secondary loads. For c i rcumferenti a1 degradation, the c l a s s i f i c a t i o n o f a x i a l thermal 1 oads as primary o r secondary loads w i l l be evaluated on a case-by-case basis. The d i v i s i o n between primary and secondary c l a s s i f i c a t i o n s w i l l be based on detai 1 ed analysis and/or testing.

Structural i n t e g r i t y requires t h a t the primary membrane stress i n t e n s i t y i n a tube not exceed the y i e l d strength f o r a l l ASME Code, Section 111, Service Level A (normal operating conditions) and Service Level B (upset o r abnormal conditions) transients included i n the design specification.

Thi s i ncl udes safety factors and appl i cab1 e design basis loads based on ASME Code, Section 111, Subsection NB (Ref. 5) and D r a f t Regulatory Guide 1.121 (Ref. 6).

The accident induced 1 eakage performance c r i t e r i o n ensures t h a t the primary t o secondary LEAKAGE caused by a design basis accident, other than a SGTR, i s w i t h i n the accident analysis assumptions. The accident analysis assumes t h a t accident induced leakage does not exceed 1 gpm. The accident induced leakage r a t e includes any primary t o secondary LEAKAGE e x i s t i n g p r i o r t o the accident i n a d d i t i o n t o primary t o secondary LEAKAGE induced during the accident.

The operational LEAKAGE performance c r i t e r i o n provides an observable i n d i c a t i o n o f SG tube conditions duri ng p l a n t operation. The l i m i t on operational LEAKAGE i s contained i n LC0 3.4.13, "RCS Operational LEAKAGE," and 1 i m i t s primary t o secondary LEAKAGE through any one SG t o 150 gallons per day.

This l i m i t i s based on the assumption t h a t a s i n g l e crack leaking t h i s amount would not propagate t o a SGTR under t h e stress conditions o f a LOCA o r a main steam l i n e break. I f t h i s amount o f LEAKAGE i s due t o more than one crack, the cracks are very small, and the above assumption i s conservative.

APPLICABILITY SG tube i n t e g r i t y i s challenged when the pressure d i f f e r e n t i a 1 across the tubes i s 1 arge. Large d i f f e r e n t i a1 pressures across SG tubes can only be experienced i n MODE 1, 2, 3, o r 4.

(continued)

North Anna Units 1 and 2 B 3.4.20-4

SG Tube Integrity B 3.4.20 BASES APPLl CAB1 Ll TY SG integrity l i m i t s are not provided i n MODES 5 and 6 s i nce (cont i nued)

RCS conditions are f a r less challenging than in MODES 5 and 6 than during MODES 1, 2, 3, and 4. In MODES 5 and 6, primary t o secondary differential pressure i s low, resulting i n lower stresses and reduced potential f o r LEAKAGE.

ACT l ONS The ACTIONS are modified by a Note clarifying that separate Conditions entry i s permitted f o r each SG tube. This i s acceptable because the Required Actions provide appropriate compensatory act i ons f o r each affected SG tube. Comply i ng with the Requ i red Act i ons may a l l ow f o r cont i nued operat i on, and subsequent affected SG tubes are governed by subsequent Cond i t i on entry and app l i cat i on o f assoc i ated Requ i red Act i ons.

A.l and A.2 Condition A applies i f i t i s discovered that one or more SG tubes examined in an inservice inspection satisfy the tube repair c r i t e r i a but were not plugged i n accordance with the Steam Generator Program as required by SR 3.4.20.2. An eva I uat i on o f SG tube i ntegr i t y o f the affected tube(s) must be made. Steam generator tube integrity i s based on meeting the SG performance c r i t e r i a described in the Steam Generator Program. The SG repa i r c r i t e r i a def i ne I i m i t s on SG tube degradation that allow f o r flaw growth between inspections while s t i l l providing assurance that the SG performance c r i t e r i a w i l l continue t o be met. In order t o determine i f a SG tube that shou Id have been plugged has tube integrity, an eva l uat i on must be completed that demonstrates that the SG performance c r i t e r i a w i l l continue t o be met u n t i l the next refuel i ng outage or SG tube inspect ion. The tube integrity determination i s based on the estimated condition o f the tube a t the time the situation i s discovered and the estimated growth o f the degradation prior t o the next SG tube inspection. I f i t i s determined that tube integrity i s not being maintained, Condition 6 applies.

A Completion Time of 7 days i s sufficient t o complete the evaluation while minimizing the r i s k o f plant operation with a SG tube that may not have tube integrity.

I f the eva l uat i on determ i nes that the affected tube(s) have tube i ntegr i t y, Requ i red Action A. 2 a l lows p l ant operat i on t o continue u n t i l the next refueling outage or SG inspection provided the inspection interval continues t o be supported (cont i nued)

North Anna Units I and 2 B 3.4.20-5

SG Tube 1 ntegr i t y B 3.4.20 BASES ACT l ONS A. 1 and A. 2 (continued) by an operational assessment t h a t reflects the affected tubes. However, the affected tube(s) must be plugged p r i o r t o entering MODE 4 f o l lowing the next refuel i ng outage or SG i nspect ion. Th i s Comp l e t i on Ti me i s acceptab 1 e s i nce operation u n t i l the next inspection i s supported by the operational assessment.

B. l and B.2 If the Requ i red Actions and assoc i ated Completion Times o f Condition A are not met or if SG tube integrity i s not being maintained, the reactor must be brought t o MODE 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and MODE 5 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months .

The allowed Completion Times are reasonable, based on operating experience, t o reach the desired plant cond from f u l l power conditions i n an orderly manner and w challenging plant systems.

itions i thout SURVEILLAN REQU l REMEN During shutdown periods the SGs are inspected as required by t h i s SR and the Steam Generator Program. NEI 97-06, Steam Generator Program Guide 1 i nes (Ref. 1 ), and i t s referenced EPRl Guide l i nes, estab l i sh the content o f the Steam Generator Program. Use o f the Steam Generator Program ensures that the inspection i s appropriate and consistent with accepted industry practices.

During SG inspectims a condition monitoring assessment o f the SG tubes i s performed. The condition monitoring assessment determines the "as found" condition o f the SG tubes. The purpose o f the condition monitoring assessment i s t o ensure that the SG performance c r i t e r i a have been met f o r the previous operating period.

The Steam Generator Program determines the scope o f the inspection and the methods used t o determine whether the tubes contain flaws satisfying the tube repair c r i t e r i a.

l nspect i on scope ( i. e., wh i ch tubes or areas o f tub i ng within the SG are t o be inspected) i s a function o f existing and potential degradation locations. The Steam Generator Program also specifies the inspection methods t o be used t o f i n d potential degradation. Inspection methods are a North Anna Units I and 2 B 3.4.20-6

SG Tube Integrity B 3.4.20 BASES SURVE l LLANCE SR 3.4.20.1 (continued)

REQU l REMENTS function o f degradation morphology, non-destructive exam i nat i on (NDE) techn i que capab i l i ti es, and i nspect i on locations.

The Steam Generator Program defines the Frequency o f SR 3.4.20.1. The Frequency i s determined by the operational assessment and other l i m i t s i n the SG examination guide l i nes (Ref. 7). The Steam Generator Program uses i nformat i on on existing degradations and growth rates t o determine an i nspect i on Frequency that prov i des reasonable assurance t h a t the tubing w i l l meet the SG performance c r i t e r i a a t the next scheduled inspection. In addition, Specification 5.5.8 contains prescriptive requirements concerning inspection intervals t o provide added assurance that the SG performance c r i t e r i a w i l l be met between scheduled inspections.

Dur i ng an SG i nspect i on, any i nspected tube that sat i s f i es the Steam Generator Program repair c r i t e r i a i s removed from service by plugging. The tube repair c r i t e r i a delineated i n Specification 5.5.8 are intended t o ensure that tubes accepted f o r cont i nued serv i ce sat i sfy the SG performance c r i t e r i a with allowance f o r error in the flaw size measurement and f o r future flaw growth. In addition, the tube repair criteria, in conjunction with other elements o f the Steam Generator Program, ensure that the SG performance c r i t e r i a w i I l cont i nue t o be met unt i l the next i nspect i on o f the subject tube(s). Reference I provi des gu idance f o r performing operational assessments t o v e r i f y that the tubes rema i n i ng i n service w i l l cont i nue t o meet the SG performance c r i t e r i a.

The Frequency o f prior t o entering MODE 4 following a SG inspection ensures that the Surveillance has been completed and a l l tubes meeting the repair c r i t e r i a are plugged p r i o r t o subjecting the SG tubes t o significant primary t o secondary pressure differential.

REFERENCES 1. NE I 97-06, "Steam Generator Program Gu i del i nes. "

2. 10 CFR 50 Appendix A, GDC 19.

3. 10 CFR 50.67.

North Anna Units 1 and 2 B 3.4.20-7

SG Tube Integrity B 3.4.20 BASES REFERENCES

4. RG 1.183, July 2000.

(cont i nued)

5. ASME Bo i I er and Pressure Vessel Code, Sect i on I I I,

Subsect i on NB.

6. Draft Regulatory Guide 1.121, "Basis f o r Plugging Degraded Steam Generator Tubes," August 1976.

7. EPRI, "Pressurized Water Reactor Steam Generator Examination Guidelines."

North Anna Units 1 and 2 B 3.4.20-8

Serial No.06-403 Docket Nos. 50-3381339 Proposed Technical Specifications Bases Changes (For Information Only)

North Anna Power Station Units 1 and 2 Virginia Electric and Power Company (Dominion)

TECHNICAL SPECIFICATIONS BASES TABLE OF CONTENTS REACTOR COOLANT SYSTEM (RCS) (continued)

Low Temperature Overpressure P r o t e c t i o n (LTOP) System B 3.4.12.1 RCS Operational LEAKAGE B 3.4.13.1 RCS Pressure I s o l a t i o n Valve (PIV) Leakage B 3.4.14.1 RCS Leakage Detection Instrumentation.......

B 3.4.15.1 RCS S p e c i f i c A c t i v i t y B 3.4.16.1 RCS Loop I s o l a t i o n Valves.............

B 3.4.17.1 RCS I s o l a t e d Loop Startup B 3.4.18.1 RCS Loops-Test Exceptions B 3.4.19.1 Steam Generator (SG) Tube I n t e g r i t y........

B 3.4.20.1

(

EMERGENCY CORE COOLING SYSTEMS (ECCS)

B 3.5.1.1 Accumulators B 3.5.1.1 ECCS-Operating B 3.5.2.1 ECCS-Shutdown B 3.5.3.1 Refuel i n g Water Storage Tank (RWST)........ B 3.5.4.1 Seal I n j e c t i o n Flow B 3.5.5.1 Boron I n j e c t i o n Tank (BIT)

B 3.5.6.1 CONTAINMENT SYSTEMS B 3.6.1.1 Containment B 3.6.1.1 Containment A i r Locks B 3.6.2.1 Containment I s o l a t i o n Valves B 3.6.3.1 Containment Pressure B 3.6.4.1 Containment A i r Temperature B 3.6.5.1 Quench Spray (QS) System B 3.6.6.1 Reci r c u l a t i on Spray (RS) System B 3.6.7.1 Chemical A d d i t i o n System B 3.6.8.1 PLANT SYSTEMS..................... B 3.7.1.1 Main Steam Safety Valves (MSSVs)......... B 3.7.1.1 Main Steam T r i p Valves (MSTVs).......... B 3.7.2.1 Main Feedwater I s o l a t i o n Valves (MFIVs), Main Feedwater Pump D i scharge Val ves (MFPDVs).

Main Feedwater Regulating Valves (MFRVs).

and Main Feedwater Regulating Bypass Valves (MFRBVs)................ B 3.7.3.1 Steam Generator Power Operated R e l i e f Valves (SG PORVs).................. B 3.7.4.1 Auxi 1 i a r y Feedwater (AFW) System......... B 3.7.5.1 Emergency Condensate Storage Tank (ECST)..... B 3.7.6.1 Secondary S p e c i f i c A c t i v i t y............ B 3.7.7.1 Service Water (SW) System............. B 3.7.8.1 Ultimate Heat Sink (UHS)............. B 3.7.9.1 Main Control Room/Emergency Swi tchgear Room (MCR ESGR) Emergency V e n t i l a t i o n System (EVS I

-MODES 1, 2, 3, and 4..........

B 3.7.10.1 Main Control Room/Emergency Swi tchgear Room (MCR/ESGR) A i r Conditioning System (ACS)...

B 3.7.11.1 North Anna U n i t s 1 and 2 i i

RCS Loops-MODES 1 and 2 B 3.4.4 BASES APPLICABLE Both t r a n s i e n t and steady s t a t e analyses have been performed SAFETY ANALYSES t o e s t a b l i s h the e f f e c t o f flow on t h e departure from (continued) nucleate boi 1 i ng (DNB). The t r a n s i e n t and accident analyses f o r t h e u n i t have been performed assuming three RCS loops are i n operation. The m a j o r i t y o f t h e u n i t safety analyses are based on i n i t i a l conditions a t high core power o r zero power.

The accident analyses t h a t are most important t o RCP operation are t h e complete l o s s o f forced reactor flow, s i n g l e r e a c t o r coolant pump locked r o t o r, p a r t i a l loss o f forced r e a c t o r flow, and rod withdrawal events (Ref. 1).

The DNB analyses assume normal three loop operation.

Uncertainties i n key u n i t operating parameters, nuclear and thermal parameters, and f u e l f a b r i c a t i o n parameters are considered s t a t i s t i c a l l y such t h a t there i s a t l e a s t a 95 percent p r o b a b i l i t y t h a t DNB w i l l not occur f o r the l i m i t i n g power rod. Key u n i t parameter u n c e r t a i n t i e s are used t o determine t h e u n i t departure from nucleate b o i l i n g r a t i o (DNBR) uncertainty. Thi s DNBR uncertainty, combined w i t h t h e DNBR 1 imi t, establishes a design DNBR value which must be met i n u n i t safety analyses and i s used t o determine the pressure and temperature Safety L i m i t (SL). Since the parameter u n c e r t a i n t i e s are considered i n determining the design DNBR value, t h e u n i t safety analyses are performed using values o f i n p u t parameters without uncertainties. Therefore, nominal operating values f o r r e a c t o r coolant flow are used i n t h e accident analyses.

The u n i t i s designed t o operate w i t h a l l RCS loops i n operation t o maintain DNBR above the 1 i m i t during a1 1 normal operations and a n t i c i p a t e d transients. By ensuring heat t r a n s f e r i n t h e nucleate b o i l i n g region, adequate heat t r a n s f e r i s provided between the f u e l cladding and the r e a c t o r cool ant.

RCS Loops-MODES 1 and 2 s a t i s f y C r i t e r i o n 2 o f 10 CFR 50.36 (c) (2) ( i i ).

The purpose o f t h i s LC0 i s t o r e q u i r e an adequate forced flow r a t e f o r core heat removal. Flow i s represented by t h e number o f RCPs i n operation f o r removal o f heat by t h e SGs. To meet safety analysis acceptance c r i t e r i a f o r DNBR, three pumps are required a t rated power.

An OPERABLE RCS loop consists o f an OPERABLE RCP i n operation providing forced flow f o r heat transport and an OPERABLE SG. I North Anna Units 1 and 2 B 3.4.4-2

RCS Loops-MODE 3 B 3.4.5 BASES LC0 U t i l i z a t i o n o f t h e Note i s permitted provided t h e f o l l o w i n g (conti nued) conditions are met, along w i t h any other conditions imposed by i n i t i a l s t a r t u p t e s t procedures:

a. No operations are permitted t h a t would d i l u t e the RCS boron concentration w i t h coolant a t boron concentrations less than required t o ensure the SDM o f LC0 3.1.1, thereby maintaining the margin t o c r i t i c a l i t y. Boron reduction w i t h cool ant a t boron concentrations 1 ess than required t o assure the SDM i s maintained i s p r o h i b i t e d because a uniform concentration d i s t r i b u t i o n throughout the RCS cannot be ensured when i n natural c i r c u l a t i o n ;

and

b. Core o u t l e t temperature i s maintained a t l e a s t 10°F below s a t u r a t i o n temperature, so t h a t no vapor bubble may form and possibly cause a natural c i r c u l a t i o n flow obstruction.

An OPERABLE RCS loop consists o f one OPERABLE RCP and one OPERABLE SG, which has t h e minimum water l e v e l s p e c i f i e d i n I SR 3.4.5.2.

An RCP i s OPERABLE i f i t i s capable o f being powered and i s able t o provide forced flow i f required.

APPLICABILITY I n MODE 3, t h i s LC0 ensures forced c i r c u l a t i o n o f the reactor coolant t o remove decay heat from t h e core and t o provide proper boron mixing.

Operation i n other MODES i s covered by:

LC0 3.4.4, "RCS Loops-MODES 1 and 2";

LC0 3.4.6, "RCS Loops-MODE 4";

LC0 3.4.7, "RCS Loops-MODE 5, Loops F i l l e d " ;

LC0 3.4.8, "RCS Loops-MODE 5, Loops Not F i l l e d " ;

LC0 3.9.5, "Residual Heat Removal (RHR) and Coolant Circulation-High Water Level" (MODE 6); and LC0 3.9.6, "Residual Heat Removal (RHR) and Coolant C i r c u l ation-Low Water Level " (MODE 6).

ACTIONS I f one required RCS loop i s inoperable, redundancy f o r heat removal i s l o s t. The Required Action i s r e s t o r a t i o n o f the required RCS loop t o OPERABLE status w i t h i n t h e Completion (continued)

North Anna Units 1 and 2 B 3.4.5-3

RCS Loops-MODE 3 B 3.4.5 BASES ACTIONS A.1 (cont i nued)

Time o f 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . This time a1 lowance i s a j u s t i f i e d period t o be without the redundant, nonoperating loop because a single loop i n operation has a heat t r a n s f e r c a p a b i l i t y greater than t h a t needed t o remove the decay heat produced i n the reactor core and because o f the low p r o b a b i l i t y o f a f a i l u r e i n the remaining loop occurring during t h i s period.

I f r e s t o r a t i o n i s not possible w i t h i n 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months , the u n i t must be brought t o MODE 4. I n MODE 4, the u n i t may be placed on the Residual Heat Removal System. The additional Completion Time o f 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months i s compatible w i t h required operations t o achieve cool down and depressurization from the e x i s t i n g u n i t conditions i n an o r d e r l y manner and without challenging u n i t systems.

C. l,

C.2, and C.3 If two required RCS loops are inoperable o r a required RCS loop i s not i n operation, except as during conditions permitted by the Note i n the LC0 section, place the Rod Control System i n a condition incapable o f rod withdrawal (e. g.,

a1 1 CRDMs must be de-energi zed by opening the RTBs o r de-energi z i ng the MG sets). A1 1 operations i nvol v i ng introduction o f coolant i n t o the RCS w i t h boron concentration l e s s than required t o meet the minimum SDM o f LC0 3.1.1 must be suspended, and action t o restore one o f the RCS loops t o OPERABLE status and operation must be i n i t i a t e d. Boron d i 1 u t i o n requires forced c i r c u l a t i o n f o r proper mixing, and opening the RTBs o r de-energizing the MG sets removes the p o s s i b i l i t y o f an inadvertent rod withdrawal. Suspending the i n t r o d u c t i o n o f coolant i n t o the RCS o f cool ant w i t h boron concentration 1 ess than requi red t o meet the minimum SDM o f LC0 3.1.1 i s required t o assure continued safe operation. With coolant added without forced c i r c u l ation, unmixed cool ant could be introduced t o the core, however coolant added w i t h boron concentration meeting the minimum SDM maintains acceptable margin t o s u b c r i t i c a l operations. The immediate Completion Time r e f l e c t s the importance o f maintaining operation f o r heat removal. The action t o restore must be continued u n t i l one loop i s restored t o OPERABLE status and operation.

North Anna Units 1 and 2 B 3.4.5-4

RCS Loops-MODE 4 B 3.4.6 BASES LC0 5280°F. This r e s t r a i n t i s t o prevent a low temperature (continued) overpressure event due t o a thermal t r a n s i e n t when an RCP i s started.

An OPERABLE RCS loop i s comprised o f an OPERABLE RCP and an OPERABLE SG, which has t h e minimum water l e v e l s p e c i f i e d i n I SR 3.4.6.2.

S i m i l a r l y f o r the RHR System, an OPERABLE RHR loop i s comprised o f an OPERABLE RHR pump capable o f providing forced f l o w t o an OPERABLE RHR heat exchanger. RCPs and RHR pumps are OPERABLE i f they are capable o f being powered and are able t o provide forced f l o w i f required.

APPLICABILITY I n MODE 4, t h i s LC0 ensures forced c i r c u l a t i o n o f t h e r e a c t o r coolant t o remove decay heat from the core and t o provide proper boron mixing. One loop o f e i t h e r RCS o r RHR provides s u f f i c i e n t c i r c u l a t i o n f o r these purposes. However, two loops consisting o f any combination o f RCS and RHR loops are required t o be OPERABLE t o provide redundancy f o r heat removal.

Operation i n other MODES i s covered by:

LC0 3.4.4, "RCS Loops-MODES 1 and 2";

LC0 3.4.5, "RCS Loops-MODE 3";

LC0 3.4.7, "RCS Loops-MODE 5, Loops F i l l e d " ;

LC0 3.4.8, "RCS Loops-MODE 5, Loops Not F i l l e d " ;

LC0 3.9.5, "Residual Heat Removal (RHR) and Cool ant C i r c u l ation-High Water Level " (MODE 6) ; and LC0 3.9.6, "Residual Heat Removal (RHR) and Coolant C i r c u l ation-Low Water Level " (MODE 6).

ACTIONS I f one required loop i s inoperable, redundancy f o r heat removal i s l o s t. Action must be i n i t i a t e d t o r e s t o r e a second RCS o r RHR loop t o OPERABLE status. The immediate Completion Time r e f l e c t s t h e importance o f maintaining the a v a i l a b i l i t y o f two paths f o r heat removal.

North Anna Units 1 and 2 B 3.4.6-3

RCS Loops-MODE 5, Loops F i l l e d B 3.4.7 BASES LC0 U t i l i z a t i o n o f Note 1 i s permitted provided the f o l l o w i n g (cont i nued) conditions are met, along w i t h any other conditions imposed by i n i t i a l s t a r t u p t e s t procedures:

a. No operations are permitted t h a t would d i l u t e the RCS boron concentration w i t h coolant a t boron concentrations l e s s than required t o meet t h e SDM o f LC0 3.1.1, t h e r e f o r e maintaining the margin t o c r i t i c a l i t y. Boron reduction w i t h coolant a t boron concentrations l e s s than required t o assure the SDM i s maintained i s p r o h i b i t e d because a uniform concentration d i s t r i b u t i o n throughout t h e RCS cannot be ensured when i n natural c i r c u l a t i o n ;

and

b. Core o u t l e t temperature i s maintained a t l e a s t 10°F below s a t u r a t i o n temperature, so t h a t no vapor bubble may form and possibly cause a natural c i r c u l a t i o n flow obstruction.

Note 2 allows one RHR loop t o be inoperable f o r a period o f up t o 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months , provided t h a t the o t h e r RHR loop i s OPERABLE and i n operation. This permits p e r i o d i c s u r v e i l 1 ance t e s t s t o be performed on the inoperable loop during the o n l y time when such t e s t i n g i s safe and possible.

Note 3 requires t h a t the secondary side water temperature o f each SG be 5 50°F above each o f t h e RCS c o l d l e g temperatures before the s t a r t o f a reactor coolant pump (RCP) w i t h an RCS c o l d l e g temperature 5 280°F. This r e s t r i c t i o n i s t o prevent a low temperature overpressure event due t o a thermal t r a n s i e n t when an RCP i s started.

Note 4 provides f o r an o r d e r l y t r a n s i t i o n from MODE 5 t o MODE 4 during a planned heatup by p e r m i t t i n g removal o f RHR loops from operation when a t l e a s t one RCS loop i s i n operation. This Note provides f o r t h e t r a n s i t i o n t o MODE 4 where an RCS loop i s permitted t o be i n operation and replaces t h e RCS c i r c u l a t i o n f u n c t i o n provided by t h e RHR loops w i t h c i r c u l a t i o n provided by an RCP.

RHR pumps are OPERABLE i f they are capable o f being powered and are able t o provide f l o w i f required. A SG can perform as I a heat s i n k v i a natural c i r c u l a t i o n when i t has an adequate water l e v e l and i s OPERABLE.

I North Anna Units 1 and 2 B 3.4.7-3

RCS Operational LEAKAGE B 3.4.13 BASES APPLICABLE Except f o r primary t o secondary LEAKAGE, t h e safety analyses SAFETY ANALYSES do n o t address operational LEAKAGE. However, other operational LEAKAGE i s r e l a t e d t o the safety analyses f o r LOCA; t h e amount o f leakage can a f f e c t t h e p r o b a b i l i t y o f such an event. The safety analysis f o r an event r e s u l t i n g i n steam discharge t o t h e atmosphere assumes t h a t primary t o secondary LEAKAGE from a1 1 steam generators (SGs) i s one gal l o n per minute o r increases t o one gal l o n per minute as a r e s u l t o f accident induced conditions. The LC0 requirement t o l i m i t primary t o secondary LEAKAGE through any one SG t o less than o r equal t o 150 gallons per day i s s i g n i f i c a n t l y l e s s than the conditions assumed i n t h e safety analysis.

Primary t o secondary LEAKAGE i s a f a c t o r i n t h e dose releases outside containment r e s u l t i n g from a main steam l i n e break (MSLB) accident. Other accidents o r t r a n s i e n t s i n v o l v e secondary steam release t o t h e atmosphere, such as a steam generator tube rupture (SGTR). The leakage contaminates the secondary f 1 u i d.

The UFSAR (Ref. 3) analysis f o r SGTR assumes t h e contaminated secondary f l u i d i s released v i a power operated re1 i e f valves o r safety valves. The source term i n t h e primary system coolant i s transported t o the a f f e c t e d (ruptured) steam generator by t h e break flow. The a f f e c t e d steam generator discharges steam t o t h e environment f o r 30 minutes u n t i l the generator i s manually isolated. The 1 gpm primary t o secondary LEAKAGE transports the source term t o t h e unaffected steam generators. Re1 eases continue through the unaffected steam generators u n t i l t h e Residual Heat Removal System i s placed i n service.

The MSLB i s l e s s l i m i t i n g f o r s i t e r a d i a t i o n releases than the SGTR. The safety analysis f o r the MSLB accident assumes 1 gpm primary t o secondary LEAKAGE as an i n i t i a l condition.

The dose consequences r e s u l t i n g from the MSLB and SGTR accidents are w i t h i n the l i m i t s defined i n the s t a f f approved l i c e n s i n g basis.

The RCS operational LEAKAGE s a t i s f i e s C r i t e r i o n 2 o f 10 CFR 50.36 (c) (2) ( i i ).

North Anna Units 1 and 2 B 3.4.13-2

RCS Operational LEAKAGE B 3.4.13 BASES RCS operational LEAKAGE s h a l l be l i m i t e d to:

a. Pressure Boundary LEAKAGE No pressure boundary LEAKAGE i s a1 1 owed, being i n d i c a t i v e o f material d e t e r i o r a t i o n. LEAKAGE o f t h i s type i s unacceptable as t h e leak i t s e l f could cause f u r t h e r d e t e r i o r a t i o n, r e s u l t i n g i n higher LEAKAGE. V i o l a t i o n o f t h i s LC0 could r e s u l t i n continued degradation o f t h e RCPB. LEAKAGE past seals and gaskets i s not pressure boundary LEAKAGE.

b. U n i d e n t i f i e d LEAKAGE One gal l o n per minute (gpm) o f u n i d e n t i f i e d LEAKAGE i s allowed as a reasonable minimum detectable amount t h a t t h e containment a i r monitoring and containment sump 1 eve1 monitoring equipment can detect w i t h i n a reasonable time period. V i o l a t i o n o f t h i s LC0 could r e s u l t i n continued degradation o f t h e RCPB, i f the LEAKAGE i s from the pressure boundary.

c. I d e n t i f i ed LEAKAGE Up t o 10 gpm o f i d e n t i f i e d LEAKAGE i s considered allowable because LEAKAGE i s from known sources t h a t do not i n t e r f e r e w i t h detection o f u n i d e n t i f i e d LEAKAGE and i s well w i t h i n t h e c a p a b i l i t y o f the RCS Makeup System.

I d e n t i f i e d LEAKAGE includes LEAKAGE t o the containment from speci f i cal l y known and 1 ocated sources, b u t does not include pressure boundary LEAKAGE o r c o n t r o l l e d r e a c t o r coolant pump (RCP) seal l e a k o f f (a normal f u n c t i o n n o t considered LEAKAGE). V i o l a t i o n o f t h i s LC0 could r e s u l t i n continued degradation o f a component o r system.

d. Primary t o Secondary LEAKAGE through Any One SG The l i m i t o f 150 gallons per day per SG i s based on t h e operational LEAKAGE performance c r i t e r i o n i n NEI 97-06, Steam Generator Program Guide1 i nes (Ref. 4). The Steam Generator Program operational LEAKAGE performance c r i t e r i o n i n NEI 97-06 states, "The RCS operational primary t o secondary leakage through any one SG s h a l l be l i m i t e d t o 150 gallons per day." The l i m i t i s based on operating experience w i t h SG tube degradation mechanisms t h a t r e s u l t i n tube leakage. The operational leakage (continued)

North Anna Units 1 and 2 B 3.4.13-3

RCS Operational LEAKAGE B 3.4.13 BASES

d. Primary t o Secondary LEAKAGE through Any One SG (cont i nued) r a t e c r i t e r i o n i n conjunction w i t h t h e implementation of t h e Steam Generator Program i s an e f f e c t i v e measure f o r minimizing the frequency of steam generator tube ruptures.

APPLICABILITY I n MODES 1, 2, 3, and 4, t h e p o t e n t i a l f o r RCPB LEAKAGE i s greatest when the RCS i s pressurized.

I n MODES 5 and 6, LEAKAGE l i m i t s are not required because t h e r e a c t o r coolant pressure i s f a r lower, r e s u l t i n g i n lower stresses and reduced p o t e n t i a l s f o r LEAKAGE.

LC0 3.4.14, "RCS Pressure Is01 a t i o n Valve (PIV) Leakage,"

measures leakage through each i n d i v i d u a l PIV and can impact t h i s LCO. O f the two PIVs i n s e r i e s i n each i s o l a t e d l i n e,

leakage measured through one PIV does n o t r e s u l t i n RCS LEAKAGE when the o t h e r i s leak t i g h t. I f both valves leak and r e s u l t i n a l o s s o f mass from t h e RCS, t h e l o s s must be i

n c l uded i n t h e a1 1 owabl e i d e n t i f i e d LEAKAGE.

ACTIONS U n i d e n t i f i e d LEAKAGE o r i d e n t i f i e d LEAKAGE i n excess o f t h e 1

LC0 l i m i t s must be reduced t o w i t h i n l i m i t s w i t h i n 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months .

This Completion Time a1 lows time t o v e r i f y leakage r a t e s and e i t h e r i d e n t i f y u n i d e n t i f i e d LEAKAGE o r reduce LEAKAGE t o w i t h i n l i m i t s before t h e r e a c t o r must be shut down. This a c t i o n i s necessary t o prevent f u r t h e r d e t e r i o r a t i o n o f t h e RCPB.

B. l and B.2 I f any pressure boundary LEAKAGE e x i s t s, o r primary t o secondary LEAKAGE i s n o t w i t h i n 1 i mi t, o r i f uni denti f i ed LEAKAGE, o r i d e n t i f i e d LEAKAGE, cannot be reduced t o w i t h i n l i m i t s w i t h i n 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months , t h e r e a c t o r must be brought t o lower pressure conditions t o reduce t h e s e v e r i t y o f t h e LEAKAGE and i t s p o t e n t i a l consequences. It should be noted t h a t LEAKAGE past seals and gaskets i s n o t pressure boundary LEAKAGE. The r e a c t o r must be brought t o MODE 3 w i t h i n

( c o n t i nued)

North Anna /Inits 1 and 2 B 3.4.13-4

RCS Operati onal LEAKAGE B 3.4.13 BASES ACTIONS B. 1 and 0.2 (continued) 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and MODE 5 w i t h i n 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months . This a c t i o n reduces t h e LEAKAGE and a l s o reduces the f a c t o r s t h a t tend t o degrade the pressure boundary.

The a1 1 owed Completion Times are reasonable, based on operating experience, t o reach the required u n i t conditions from f u l l power conditions i n an o r d e r l y manner and without challenging u n i t systems. I n MODE 5, the pressure stresses a c t i n g on t h e RCPB are much lower, and f u r t h e r d e t e r i o r a t i o n i s much l e s s l i k e l y.

SURVEILLANCE SR 3.4.13.1 REQUIREMENTS Veri f y i ng RCS LEAKAGE t o be w i t h i n t h e LC0 1 imi t s ensures t h e i n t e g r i t y o f t h e RCPB i s maintained. Pressure boundary LEAKAGE would a t f i r s t appear as u n i d e n t i f i e d LEAKAGE and can only be p o s i t i v e l y i d e n t i f i e d by inspection. It should be noted t h a t LEAKAGE past seals and gaskets i s n o t pressure boundary LEAKAGE. U n i d e n t i f i e d LEAKAGE and i d e n t i f i e d LEAKAGE are determined by performance o f an RCS water inventory bal ance.

The RCS water inventory balance must be met w i t h the reactor a t steady s t a t e operating conditions (stab1 e temperature, power 1 evel, pressurizer and makeup tank 1 evel s, makeup and letdown, and RCP seal i n j e c t i o n and r e t u r n flows). The surveillance i s modified by two Notes. Note 1 states t h a t t h i s SR i s n o t required t o be performed u n t i l 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months a f t e r I establishing steady s t a t e operation. The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months allowance provides s u f f i c i e n t time t o c o l l e c t and process a l l necessary data a f t e r s t a b l e p l a n t conditions are establ i shed.

Steady s t a t e operation i s required t o perform a proper inventory balance since cal cul a t i ons during maneuvering are n o t useful. For RCS operational LEAKAGE determination by water inventory balance, steady s t a t e i s defined as stable RCS pressure, temperature, power 1 evel, pressuri zer and makeup tank levels, makeup and letdown, and RCP seal i n j e c t i o n and r e t u r n flows.

An e a r l y warning o f pressure boundary LEAKAGE o r u n i d e n t i f i e d LEAKAGE i s provided by t h e automatic systems t h a t monitor t h e containment atmosphere r a d i o a c t i v i t y and (conti nued)

North Anna Units 1 and 2 B 3.4.13-5

RCS Operat i ona l LEAKAGE B 3.4.13 BASES SURVE l LLANCE SR 3.4.13.1 (continued)

REQU I REMENTS the conta i nment sump l eve l. I t shou l d be noted that LEAKAGE past seals and gaskets i s not pressure boundary LEAKAGE.

These l eakage detect i on systems are spec i f i ed i n LC0 3.4.15, "RCS Leakage Detection Instrumentation."

Note 2 states that t h i s SR i s not applicable t o primary t o secondary LEAKAGE because LEAKAGE o f 150 gal l ons per day cannot be measured accurately by an RCS water inventory ba l ance.

The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Frequency i s a reasonable interval t o trend LEAKAGE and recognizes the importance o f early leakage detection i n the prevention o f accidents.

This SR verifies that primary t o secondary LEAKAGE i s less than or equal t o 150 gal l ons per day through any one SG.

Sat i sfy i ng the pr i mary t o secondary LEAKAGE l i m i t ensures that the operat i ona l LEAKAGE performance c r i t e r i on i n the Steam Generator Program i s met. I f t h i s SR i s not met, comp l i ance w i t h LC0 3.4.20, "Steam Generator Tube I ntegr i ty, " shou l d be eva l uated. The 150 gal l ons per day l i m i t i s measured a t room temperature as described i n Reference 5. The operat i ona l LEAKAGE rate l i m i t app l i es t o LEAKAGE through any one SG. I f i t i s not practical t o assign the LEAKAGE t o an i nd i vi dua l SG, a l l the pr i mary t o secondary LEAKAGE should be conservatively assumed t o be from one SG.

The Surve i l lance i s modified by a Note, which states that the Surveillance i s not required t o be performed u n t i l 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after establ i shment o f steady state operation. For RCS pr i mary t o secondary LEAKAGE determ i nat i on, steady state i s defined as stable RCS pressure, temperature, power level, pressurizer and makeup tank levels, makeup and letdown, and RCP seal injection and return flows.

The Surveillance Frequency o f 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months i s a reasonable interval t o trend primary t o secondary LEAKAGE and recognizes the importance o f early leakage detection i n the prevent i on o f acci dents. The pr i mary t o secondary LEAKAGE i s determined using continuous process radiation monitors or rad i ochem i ca l grab sampl i ng i n accordance with the EPR l guidelines (Ref. 5).

North Anna Units 1 and 2 B 3.4.13-6

RCS Operational LEAKAGE B 3.4.13 BASES REFERENCES

1. UFSAR, Section 3.1.26.

2. Regulatory Guide 1.45, May 1973.

3. UFSAR, Chapter 15.

4. NEI 97-06, "Steam Generator Program Guide1 i nes. "

5. EPRI, "Pressurized Water Reactor Primary-to-Secondary Leak Gui del i nes. "

North Anna U n i t s 1 and 2

SG Tube I n t e q r i t y B 3.4 REACTOR COOLANT SYSTEM (RCS)

B 3.4.20 Steam Generator (SG) Tube I n t e g r i t y BASES BACKGROUND Steam generator (SG) tubes are small diameter, t h i n walled tubes t h a t c a r r y primary coolant through t h e primary t o secondary heat exchangers. The SG tubes have a number o f important safety functions. SG tubes are an i n t e g r a l p a r t o f t h e reactor coolant pressure boundary (RCPB) and, as such, are r e l i e d on t o maintain the primary system's pressure and inventory. The SG tubes i s o l a t e t h e r a d i o a c t i v e f i s s i o n products i n t h e primary cool ant from t h e secondary system.

I n addition, as p a r t o f t h e RCPB, t h e SG tubes are unique i n t h a t they a c t as t h e heat t r a n s f e r surface between t h e primary and secondary systems t o remove heat from the primary system. This S p e c i f i c a t i o n addresses only t h e RCPB i n t e g r i t y f u n c t i o n o f t h e SG. The SG heat removal f u n c t i o n i s addressed by LC0 3.4.4, "RCS Loops-MODES 1 and 2,"

LC0 3.4.5, "RCS Loops-MODE 3," LC0 3.4.6, "RCS Loops-MODE 4," and LC0 3.4.7, "RCS Loops-MODE 5, Loops F i l l e d. "

SG tube i n t e g r i t y means t h a t the tubes are capable o f performing t h e i r intended RCPB safety f u n c t i o n consistent w i t h the 1 icensing basis, i n c l uding appl i c a b l e regulatory requi rements.

SG tubing i s subject t o a v a r i e t y o f degradation mechanisms.

SG tubes may experience tube degradation r e l a t e d t o corrosion phenomena, such as wastage, p i t t i n g, i n t e r g r a n u l a r attack, and stress corrosion cracking, along w i t h other mechanically induced phenomena such as denting and wear.

These degradation mechanisms can impair tube i n t e g r i t y i f they are n o t managed e f f e c t i v e l y. The SG performance c r i t e r i a are used t o manage SG tube degradation.

S p e c i f i c a t i o n 5.5.8, "Steam Generator (SG) Program,"

requires t h a t a program be establ ished and implemented t o ensure t h a t SG tube i n t e g r i t y i s maintained. Pursuant t o S p e c i f i c a t i o n 5.5.8, tube i n t e g r i t y i s maintained when the SG performance c r i t e r i a are met. There are three SG performance c r i t e r i a : s t r u c t u r a l i n t e g r i t y, accident induced leakage, and operational LEAKAGE. The SG performance c r i t e r i a are described i n S p e c i f i c a t i o n 5.5.8.

Meeting the (cont i nued)

North Anna Units 1 and 2 B 3.4.20-1

SG Tube I n t e g r i t y BACKGROUND SG performance c r i t e r i a provides reasonable assurance o f (continued) maintaining tube i n t e g r i t y a t normal and accident conditions.

The processes used t o meet the SG performance c r i t e r i a are defined by the Steam Generator Program Guidelines (Ref. 1).

APPLICABLE The steam generator tube rupture (SGTR) accident i s t h e SAFETY ANALYSES 1 imi t i n g basis event f o r SG tubes and avoiding a SGTR i s t h e basis f o r t h i s Specification. The analysis o f a SGTR event assumes a bounding primary t o secondary LEAKAGE r a t e o f 1 gpm, which i s conservative w i t h respect t o the operational LEAKAGE r a t e l i m i t s i n LC0 3.4.13, "RCS Operational LEAKAGE,"

plus the leakage r a t e associated w i t h a double-ended rupture o f a s i n g l e tube. The UFSAR analysis f o r SGTR assumes the contaminated secondary f l u i d i s released v i a power operated r e l i e f valves o r safety valves.

The source term i n the primary system cool ant i s transported t o t h e a f f e c t e d (ruptured) steam generator by the break flow. The a f f e c t e d steam generator discharges steam t o the environment f o r 30 minutes u n t i l the generator i s manually i s o l a t e d. The 1 gpm primary t o secondary LEAKAGE transports the source term t o t h e unaffected steam generators. Releases continue through the unaffected steam generators u n t i l t h e Residual Heat Removal System i s placed i n service.

The analysis f o r design basis accidents and t r a n s i e n t s other than a SGTR assume t h e SG tubes r e t a i n t h e i r s t r u c t u r a l i n t e g r i t y ( i.e.,

they are assumed not t o rupture.) I n these analyses, the steam discharge t o the atmosphere i s based on t h e t o t a l primary t o secondary LEAKAGE from a l l SGs o f 1 gal l o n per minute o r i s assumed t o increase t o 1 gal 1 on per minute as a r e s u l t o f accident induced conditions. For accidents t h a t do not i n v o l v e f u e l damage, t h e primary coolant a c t i v i t y l e v e l o f DOSE EQUIVALENT 1-131 i s assumed t o be equal t o t h e LC0 3.4.16, "RCS S p e c i f i c A c t i v i t y, "

1 i m i t s. For accidents t h a t assume f u e l damage, the primary coolant a c t i v i t y i s a f u n c t i o n o f the amount o f a c t i v i t y released from the damaged f u e l. The dose consequences o f these events are w i t h i n t h e l i m i t s o f GDC 19 (Ref. 2),

10 CFR 50.67 (Ref. 3) o r RG 1.183 (Ref. 4), as appropriate.

SG tube i n t e g r i t y s a t i s f i e s C r i t e r i o n 2 o f 10 CFR 50.36 (c) (2) (i i ).

North Anna Units 1 and 2 B 3.4.20-2

SG Tube Inteqrity BASES The LC0 requires that SG tube integrity be maintained. The LC0 also requires that all SG tubes that satisfy the repair criteria be plugged in accordance with the Steam Generator Program.

During an SG inspection, any inspected tube that satisfies the Steam Generator Program repair criteria i s removed from service by plugging. If a tube was determined to satisfy the repair criteria b u t was not plugged the tube may s t i l l have tube integrity.

I n the context of this Specification, a SG tube i s defined as the entire length of the tube, including the tube wall between the tube-to-tubesheet weld a t the tube inlet and the tube-to-tubesheet weld a t the tube outlet. The tube-to-tubesheet weld i s not considered part of the tube.

A SG tube has tube integrity when i t satisfies the SG performance criteria. The SG performance criteria are defined in Specification 5.5.8, "Steam Generator Program,"

and describe acceptable SG tube performance. The Steam Generator Program also provides the evaluation process for determining conformance with the SG performance criteria.

There are three SG performance criteria: structural integrity, accident induced 1 eakage, and operational LEAKAGE. Failure to meet any one of these criteria i s considered failure to meet the LCO.

The structural integrity performance criterion provides a margin of safety against tube burst or collapse under normal and accident conditions, and ensures structural integrity of the SG tubes under all anticipated transients included in the design specification. Tube burst i s defined as, "The gross structural fai 1 ure of the tube wall. The condition typically corresponds to an unstable opening displacement (e.g., opening area increased in response to constant pressure) accompanied by ductile (plastic) tearing of the tube material a t the ends of the degradation." Tube col lapse i s defined as, "For the load displ acernent curve for a given structure, collapse occurs a t the top of the load versus displacement curve where the slope of the curve becomes zero. " The structural integrity performance criterion provides guidance on assessing loads that have a significant effect on burst or collapse. In that context, the term "significant" i s defined as "An accident loading condition other than differential pressure i s considered significant (continued)

North Anna Units 1 and 2 B 3.4.20-3

SG Tube Integrity B 3.4.20 BASES L CO when the addition of such loads in the assessment of the (continued) structural integrity performance criterion could cause a l ower structural l imi t o r 1 imi t i ng burst/col 1 apse condition t o be established." For tube integrity evaluations, except for ci rcumferenti a1 degradation, axi a1 thermal 1 oads are cl assi f ied as secondary 1 oads. For ci rcumferenti a1 degradation, the classification of axial thermal loads as primary o r secondary loads will be evaluated on a case-by-case basis. The division between primary and secondary classifications wi 11 be based on detailed analysis and/or t e s t i ng.

Structural integrity requires t h a t the primary membrane s t r e s s intensity in a tube not exceed the yield strength f o r a1 1 ASME Code, Section 111, Service Level A (normal operating conditions) and Service Level B (upset o r abnormal conditions) transients included i n the design specification.

Thi s i ncl udes safety factors and appl i cab1 e design basi s loads based on ASME Code, Section 111, Subsection NB (Ref. 5) and Draft Regulatory Guide 1.121 (Ref. 6).

The accident induced leakage performance criterion ensures t h a t the primary t o secondary LEAKAGE caused by a design basis accident, other than a SGTR, i s within the accident analysis assumptions. The accident analysis assumes t h a t accident induced leakage does not exceed 1 gpm. The accident induced leakage r a t e includes any primary t o secondary LEAKAGE existing prior t o the accident i n addition t o primary t o secondary LEAKAGE induced during the accident.

The operational LEAKAGE performance criterion provides an observable indication of SG tube conditions during plant operation. The limit on operational LEAKAGE i s contained in LC0 3.4.13, "RCS Operational LEAKAGE," and limits primary t o secondary LEAKAGE through any one SG t o 150 gallons per day.

This limit i s based on the assumption t h a t a single crack leaking t h i s amount would not propagate t o a SGTR under the s t r e s s conditions of a LOCA o r a main steam l i n e break. If t h i s amount of LEAKAGE is due t o more than one crack, the cracks are very small, and the above assumption i s conservative.

APPLICABILITY SG tube integrity i s challenged when the pressure differential across the tubes i s large. Large differential pressures across SG tubes can only be experienced in MODE 1, 2, 3, o r 4.

(conti nued)

North Anna Units 1 and 2 B 3.4.20-4

SG Tube I n t e g r i t y BASES APPLICABILITY SG i n t e g r i t y l i m i t s are n o t provided i n MODES 5 and 6 since (continued)

RCS conditions are f a r l e s s challenging than i n MODES 5 and 6 than during MODES 1, 2, 3, and 4. I n MODES 5 and 6, primary t o secondary d i f f e r e n t i a l pressure i s low, r e s u l t i n g i n lower stresses and reduced p o t e n t i a l f o r LEAKAGE.

ACTIONS The ACTIONS are modified by a Note c l a r i f y i n g t h a t separate Conditions e n t r y i s permitted f o r each SG tube. This i s acceptable because t h e Required Actions provide appropriate compensatory actions f o r each a f f e c t e d SG tube. Complying w i t h the Required Actions may allow f o r continued operation, and subsequent a f f e c t e d SG tubes are governed by subsequent Condition e n t r y and a p p l i c a t i o n o f associated Required Actions.

A. l and A.2 Condition A applies i f i t i s discovered t h a t one o r more SG tubes examined i n an i n s e r v i c e inspection s a t i s f y t h e tube r e p a i r c r i t e r i a but were n o t plugged i n accordance w i t h the Steam Generator Program as required by SR 3.4.20.2.

An evaluation o f SG tube i n t e g r i t y o f the a f f e c t e d tube(s) must be made. Steam generator tube i n t e g r i t y i s based on meeting t h e SG performance c r i t e r i a described i n t h e Steam Generator Program. The SG r e p a i r c r i t e r i a define l i m i t s on SG tube degradation t h a t allow f o r f l a w growth between inspections w h i l e s t i l l providing assurance t h a t t h e SG performance c r i t e r i a w i l l continue t o be met. I n order t o determine i f a SG tube t h a t should have been plugged has tube i n t e g r i t y, an evaluation must be completed t h a t demonstrates t h a t the SG performance c r i t e r i a w i l l continue t o be met u n t i l t h e next r e f u e l i n g outage o r SG tube inspection. The tube i n t e g r i t y determination i s based on t h e estimated c o n d i t i o n o f t h e tube a t the time the s i t u a t i o n i s discovered and t h e estimated growth o f t h e degradation p r i o r t o t h e next SG tube inspection. I f i t i s determined t h a t tube i n t e g r i t y i s n o t being maintained, Condition B applies.

A Completion Time o f 7 days i s s u f f i c i e n t t o complete the evaluation while minimizing t h e r i s k o f p l a n t operation w i t h a SG tube t h a t may not have tube i n t e g r i t y.

I f t h e evaluation determines t h a t t h e a f f e c t e d tube(s) have tube i n t e g r i t y, Required Action A.2 allows p l a n t operation t o continue u n t i l t h e next r e f u e l i n g outage o r SG inspection provided t h e inspection i n t e r v a l continues t o be supported (conti nued)

North Anna Units 1 and 2 B 3.4.20-5

SG Tube I n t e g r i t y B 3.4.20 BASES ACTIONS A. 1 and A.2 (continued) by an operational assessment t h a t r e f l e c t s the affected tubes. However, the affected tube(s) must be plugged p r i o r t o entering MODE 4 f o l l o w i n g the next r e f u e l i n g outage o r SG inspection. This Completion Time i s acceptable since operation u n t i l the next inspection i s supported by the operational assessment.

B. l and B.2 I f the Required Actions and associated Completion Times o f Condition A are not met o r i f SG tube i n t e g r i t y i s not being maintained, the reactor must be brought t o MODE 3 w i t h i n 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and MODE 5 w i t h i n 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months .

The a1 1 owed Completion Times are reasonable, based on operating experience, t o reach the desired p l a n t conditions from f u l l power conditions i n an o r d e r l y manner and without chal 1 engi ng p l a n t systems.

SURVEILLANCE SR 3.4.20.1 REQUIREMENTS During shutdown periods the SGs are inspected as required by t h i s SR and the Steam Generator Program. N E I 97-06, Steam Generator Program Gui del i nes (Ref. 1), and i t s referenced EPRI Guidelines. e s t a b l i s h the content o f the Steam Generator program. Use o f the Steam Generator Program ensures t h a t the inspection i s appropriate and consistent w i t h accepted industry practices.

During SG inspections a condition monitoring assessment o f t h e SG tubes i s performed. The condition monitoring assessment determines the "as found" condition o f the SG tubes. The purpose o f the condition moni t o r i n g assessment i s t o ensure t h a t the SG performance c r i t e r i a have been met f o r the previous operating period.

The Steam Generator Program determines the scope o f the inspection and the methods used t o determine whether the tubes contain flaws s a t i s f y i n g the tube r e p a i r c r i t e r i a.

Inspection scope ( i.e.,

which tubes o r areas o f tubing w i t h i n the SG are t o be inspected) i s a function o f e x i s t i n g and p o t e n t i a l degradation locations. The Steam Generator Program also specifies the inspection methods t o be used t o f i n d p o t e n t i a l degradation. Inspection methods are a North Anna Units 1 and 2 B 3.4.20-6

SG Tube I n t e g r i t y B 314.20 BASES SURVEILLANCE SR 3.4.20.1 (continued)

REQUIREMENTS f u n c t i o n o f degradation morphology, non-destructive examination (NDE) technique capabi 1 it i es, and inspection locations.

The Steam Generator Program defines the Frequency o f SR 3.4.20.1.

The Frequency i s determined by t h e operational assessment and other 1 i m i t s i n t h e SG examination guide1 ines (Ref. 7). The Steam Generator Program uses information on e x i s t i n g degradations and growth r a t e s t o determine an inspection Frequency t h a t provides reasonable assurance t h a t t h e tubing w i l l meet the SG performance c r i t e r i a a t the next scheduled inspection. I n addition, S p e c i f i c a t i o n 5.5.8 contains p r e s c r i p t i v e requirements concerning inspection i n t e r v a l s t o provide added assurance t h a t t h e SG performance c r i t e r i a w i l l be met between scheduled inspections.

During an SG inspection, any inspected tube t h a t s a t i s f i e s t h e Steam Generator Program r e p a i r c r i t e r i a i s removed from service by plugging. The tube r e p a i r c r i t e r i a delineated i n S p e c i f i c a t i o n 5.5.8 are intended t o ensure t h a t tubes accepted f o r c o n t i nued s e r v i ce s a t i s f y t h e SG performance c r i t e r i a w i t h allowance f o r e r r o r i n t h e f l a w s i z e measurement and f o r f u t u r e f l a w growth. I n addition, the tube r e p a i r c r i t e r i a, i n conjunction w i t h other elements o f the Steam Generator Program, ensure t h a t t h e SG performance c r i t e r i a w i l l continue t o be met u n t i l the next inspection o f t h e subject tube(s). Reference 1 provides guidance f o r performing operational assessments t o v e r i f y t h a t the tubes remaining i n service w i l l continue t o meet t h e SG performance c r i t e r i a.

The Frequency o f p r i o r t o entering MODE 4 f o l l o w i n g a SG inspection ensures t h a t t h e Surveillance has been completed and a l l tubes meeting the r e p a i r c r i t e r i a are plugged p r i o r t o subjecting t h e SG tubes t o s i g n i f i c a n t primary t o secondary pressure d i f f e r e n t i a l.

REFERENCES

1. NEI 97-06, "Steam Generator Program Guidelines."

2. 10 CFR 50 Appendix A, GDC 19.

3. 10 CFR 50.67.

North Anna Units 1 and 2 B 3.4.20-7

SG Tube I n t e g r i t y B 3.4.20 BASES REFERENCES

4. RG 1.183, J u l y 2000.

(continued)

5. ASME B o i l e r and Pressure Vessel Code, Section 111, Subsection NB.

6. D r a f t Regulatory Guide 1.121, "Basis f o r Plugging Degraded Steam Generator Tubes," August 1976.

7. EPRI, "Pressurized Water Reactor Steam Generator Examination Guidelines."

North Anna Units 1 and 2

v t e Letter Sequence Request
TAC:MD1838, Steam Generator Tube Integrity (Approved, Closed)
Initiation Request Acceptance... Administration Questions Answers Results Approval Other: ML062900458, ML063000028
MONTHYEAR2006-12-28 [Table View]

ML061430062

Text

1.0 INTRODUCTION

2.0 DESCRIPTION

3.0 BACKGROUND

5.0 TECHNICAL ANALYSIS

6.0 REGULATORY ANALYSIS

10.0 REFERENCES

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