Text

License Amendment Request for Adoption of TSTF-449 Regarding Steam Generator Tube Integrity
	ML061590405
Person / Time
Site:	Indian Point
Issue date:	05/31/2006
From:	Dacimo F; Entergy Nuclear Northeast
To:	; Document Control Desk, Office of Nuclear Reactor Regulation
References
	NL-06-063, TSTF-449
	Download: ML061590405 (88)
	v • d • e

a.g 4%-En terg Entergy Nuclear Northeast Indian Point Energy Center 450 Broadway, GSB P.O. Box 249 Buchanan, NY 10511-0249 Tel 914 734 6700 Fred Dacimo Site Vice President Administration May 31, 2006 Re:

Indian Point Units 2 and 3 Dockets 50-247 and 286 NL-06-063 U. S. Nuclear Regulatory Commission Document Control Desk Washington, D. C. 20555

SUBJECT:

License Amendment Request for Adoption of TSTF-449 Regarding Steam Generator Tube Integrity

References:

1. Entergy Letter NL-06-028, M. Kansler to U, S, NRC, "30-Day Response to NRC Generic Letter 2006-01: Steam Generator Tube Integrity and Associated Technical Specifications", dated February 21, 2006.

Dear Sir or Madam:

Pursuant to 10 CFR 50.90, Entergy Nuclear Operations, Inc. (ENO) is submitting a request for an amendment to the technical specifications (TS) for Indian Point Nuclear Generating Unit Nos.

2 & 3 (1P2 and IP3).

The proposed amendment would revise the TS requirements related to steam generator (SG) tube integrity. The change is 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). This proposed amendment request also fulfills ENO's commitment provided to the NRC in response to Generic Letter 2006-01 (Reference 1).

Attachment I provides a description of the proposed change and confirmation of applicability.

Attachment II provides the existing TS pages marked-up to show the proposed changes. In addition, Attachment III provides, for information purposes, the existing TS Bases pages marked-up to show the proposed changes.

Both the current IP2 TS primary-to-secondary leakage limit and the proposed limit are 150 gallons per day (gpd) through any one SG. In the background discussion supporting the CLIIP, the NRC assumed that the associated safety analyses were performed at a higher leak rate and thus margin between the analysis of record and the TS limit would exist. The IP2 safety analyses were performed using 150 gpd. Therefore, to provide additional margin as assumed in

NL-06-063 Dockets 50-247 and 50-286 Page 2 of 2 the CLIIP, ENO is committing (Attachment IV) to administratively maintain the IP2 primary-to-secondary leakage limit at 75 gpd through any one SG. ENO will revise the commitment when new calculations are performed which provide the margin discussed in the CLIIP Also, wording changes were made to the Bases that may differ from the CLIIP, to reflect plant specific safety analyses. The analyses for IP3 already provide for margin to the proposed new primary-to-secondary leakage limits as intended in the CLIIP.

A copy of this application and the associated attachments are being submitted to the designated New York State official.

ENO requests approval of the proposed license amendment by January 31, 2007, with the amendment being implemented within 60 days of approval. If you should have any questions, please contact Mr. Patric W. Conroy, IPEC Licensing Manager at (914) 734-6668.

I declare under penalty of perjury that the foregoing is true and correct. Executed on..L.

Sil

ely, dR. Dacimo Site Vice President Indian Point Energy Center Attachments:

I.

Analysis of Proposed Technical Specification Changes Regarding Steam Generator Tube Integrity, TSTF-449.

II.

Proposed Technical Specification Changes - Markup Pages Ill.

Proposed Technical Specification Bases Changes - Markup Pages IV.

Commitment cc:

Mr. John P. Boska, Senior Project Manager, NRC NRR DORL Mr. Samuel J. Collins, Regional Administrator, NRC Region I NRC Resident Inspector's Office, Indian Point 2 NRC Resident Inspector's Office, Indian Point 3 Mr. Peter R. Smith, NYSERDA Mr. Paul Eddy, NYS Department of Public Service

ATTACHMENT I TO NL-06-063 ANALYSIS OF PROPOSED TECHNICAL SPECIFICATION CHANGES REGARDING STEAM GENERATOR TUBE INTEGRITY, TSTF-449 ENTERGY NUCLEAR OPERATIONS, INC.

INDIAN POINT NUCLEAR GENERATING UNITS NO. 2 and 3 DOCKET NO. 50-247 and 50-286

NL-06-063 Dockets 50-247 and 50-286 Attachment I Page 1 of 5

1.0 INTRODUCTION

The proposed license amendment revises the requirements in Technical Specification (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 (70 FR 24126) as part of the consolidated line item improvement process (CLIIP).

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 3.4.13, "RCS [Reactor Coolant System] Operational Leakage"

" New TS 3.4.17, "Steam Generator (SG) Tube Integrity"

" Revised TS 5.5.7 (Indian Point Unit 2) and TS 5.5.8 (Indian Point Unit 3), "Steam Generator (SG) Program"

" Revised TS 5.6.7 (Indian Point Unit 2) and TS 5.6.8 (Indian Point Unit 3), "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.

3.0 BACKGROUND

The background 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 published 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.

Both the current Indian Point Unit 2 TS primary to secondary leakage limit and the proposed limit are 150 gallons per day (gpd) through any one SG. In the background discussion supporting the CLIIP, the NRC assumed that the associated safety analyses were performed at

NL-06-063 Dockets 50-247 and 50-286 Attachment I Page 2 of 5 a higher leak rate and thus margin between the analysis of record and the TS limit would exist.

The Indian Point Unit 2 safety analyses were performed using 150 gpd. Therefore, to provide additional margin as assumed in the CLIIP, ENO will administratively maintain the Indian Point Unit 2 primary to secondary leakage limit at 75 gpd through any one SG. ENO will revise the commitment when new calculations are performed which provide the margin discussed in the CLIIP. Also, wording changes were made to the Bases, that may differ from the CLIIP, to reflect plant specific safety analyses. The analyses for IP3 already provide for margin to the proposed new primary-to-secondary leakage limits as intended in the CLIIP.

5.0 TECHNICAL ANALYSIS

Entergy Nuclear Operations, Inc. (ENO) has reviewed the safety evaluation (SE) published on March 2, 2005 (70 FR10298) as part of the CLIIP 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. ENO has concluded that the justifications presented in the TSTF proposal and the SE prepared by the NRC staff are applicable to Indian Point Nuclear Generating Unit Nos. 2 & 3 (Indian Point Units 2 & 3) and justify this amendment for the incorporation of the changes to the Indian Point Units 2 & 3 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 Tables are provided to support the NRC staff's review of this application for amendment.

NL-06-063 Dockets 50-247 and 50-286 Attachment I Page 3 of 5 Table One - Indian Point Unit 2 Plant Name, Unit No.

Indian Point Unit 2 Steam Generator Model(s):

Westinghouse 44F Effective Full Power Years (EFPY) of service 5

for currently installed SGs Tubing Material 600TT Number of tubes per SG 3214 Number and percentage of tubes 21 SG - 10 Tubes, 0.31%

plugged in each SG 22SG -

3 Tubes, 0.09%

23SG -

3 Tubes, 0.09%

24SG -

9 Tubes, 0.28%

Number of tubes repaired in each SG 21SG -

0 Tubes 22SG -

0 Tubes 23SG -

0 Tubes 24SG -

0 Tubes Degradation mechanism(s) identified WEAR (AVB)

Current primary-to-secondary leakage limits:

per SG: 150 gpd Total :

600 gpd Leakage is evaluated at what temperature condition:

Room Temperature Approved Alternate Tube Repair Additional information for each ARC:

Criteria (ARC):

1. None

1. Not Applicable Approved SG Tube Repair Methods:

Additional information for each repair method:

1. None

1. Not Applicable Performance criteria for accident leakage Primary-to-secondary leak rate values assumed in licensing basis accident analysis, including assumed temperature conditions:

150 gpd per SG 600 gpd total Density of leakage assumed to be 62.4 Ibm/ft3 which corresponds to a temperature of < 530F

NL-06-063 Dockets 50-247 and 50-286 Attachment I Page 4 of 5 Table Two - Indian Point Unit 3 Plant Name, Unit No.

Indian Point Unit 3 Steam Generator Model(s):

Westinghouse 44F Effective Full Power Years (EFPY) of service 12 for currently installed SGs Tubing Material 690TT Number of tubes per SG 3214 Number and percentage of tubes plugged in 31 SG - 1 Tube, 0.03%

each SG 32SG - 6 Tubes, 0.19%

33SG - 3 Tubes, 0.09%

34SG - 4 Tubes, 0.12%

Number of tubes repaired in each SG 31 SG - 0 Tubes 32SG - 0 Tubes 33SG - 0 Tubes 34SG - 0 Tubes Degradation mechanism(s) identified NONE (The plugged tubes, indicated above, were plugged for non-service related reasons).

Current primary-to-secondary leakage limits:

per SG: 0.3 gpm (432 gpd)

Total:

1.0 gpm (1440 gpd)

Leakage is evaluated at what temperature condition: Room Temperature Approved Alternate Tube Repair Additional information for each ARC:

Criteria (ARC):

1. None

1. Not Applicable Approved SG Tube Repair Methods Additional information for each repair method:

1. None

1. Not Applicable Performance criteria for accident leakage Primary-to-secondary leak rate values assumed in licensing basis accident analysis, including assumed temperature conditions:

0.3 gpm per SG 1.0 gpm total Density of leakage assumed to be 62.4 Ibm/ft3 which corresponds to a temperature of < 530F

NL-06-063 Dockets 50-247 and 50-286 Attachment I Page 5 of 5 7.0 NO SIGNIFICANT HAZARDS CONSIDERATION ENO has reviewed the proposed no significant hazards consideration determination published on March 2, 2005 (70 FR 10298) as part of the CLIIP. ENO has concluded that the proposed determination presented in the notice is applicable to Indian Point Unit Nos. 2 & 3 and the determination is hereby incorporated by reference to satisfy the requirements of 10 CFR 50.91(a).

8.0 ENVIRONMENTAL EVALUATION ENO has reviewed the environmental evaluation included in the model SE published on March 2, 2005 (70 FR 10298) as part of the CLIIP. ENO has concluded that the staffs findings presented in that evaluation are applicable to Indian Point Unit Nos. 2 & 3 and the evaluation is hereby incorporated by reference for this application.

9.0 PRECEDENT This application is being made in accordance with the CLIIP. ENO is not proposing variations or deviations from the TS changes described in TSTF-449, Revision 4, or the NRC staffs 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 CFR 10298)

Notice of Availability published on May 6, 2005 (70 FR 24126)

ATTACHMENT II TO NL-06-063 MARKUP OF TECHNCIAL SPECIFICATION PAGES FOR PROPOSED CHANGES REGARDING STEAM GENERATOR TUBE INTEGRITY, TSTF-449 Affected Pages (IP2)

Table of Contents ii and iv 1.1-3 3.4.13-1 and -2 New Pages 3.4.17-1 and -2 5.5-6 through 5.5-8 5.5-16 and 5.5-17 5.6-4 and 5.6.5 Affected Pages (IP3)

Table of Contents ii and iv 1.1-4 3.4.13-1 and -2 New Pages 3.4.17-1 and -2 5.0-13 through 5.0-19 5.0-36 ENTERGY NUCLEAR OPERATIONS, INC.

INDIAN POINT NUCLEAR GENERATING UNITS NO. 2 and 3 DOCKET NO. 50-247 and 50-286

Facility Operating License No. DPR-26 Appendix A - Technical Specifications TABLE OF CONTENTS 3.4 REACTOR COOLANT SYSTEM (RCS) 3.4.1 RCS Pressure, Temperature, and Flow Departure from Nucleate Boiling (DNB) Limits 3.4.2 RCS Minimum Temperature for Criticality 3.4.3 RCS Pressure and Temperature (P/T) Limits 3.4.4 RCS Loops - MODES 1 and 2 3.4.5 RCS Loops - MODE 3 3.4.6 RCS Loops - MODE 4 3.4.7 RCS Loops - MODE 5, Loops Filled 3.4.8 RCS Loops - MODE 5, Loops Not Filled 3.4.9 Pressurizer 3.4.10 Pressurizer Safety Valves 3.4.11 Pressurizer Power Operated Relief Valves (PORVs) 3.4.12 Low Temperature Overpressure Protection (LTOP) 3.4.13 RCS Operational LEAKAGE 3.4.14 RCS Pressure Isolation Valve (PIV) Leakage 3.4.15 RCS Leakage Detection Instrumentation 3.4.16

-RCS Specific Activity 3.5 EMERGENCY CORE COOLING SYSTEM (ECCS) 3.5.1 Accumulators 3.5.2 ECCS - Operating 3.5.3 ECCS - Shutdown 3.5.4 Refueling Water Storage Tank (RWST) 3.6 CONTAINMENT SYSTEMS 3.6.1 Containment 3.6.2 Containment Air Locks 3.6.3 Containment Isolation Valves 3.6.4 Containment Pressure 3.6.5 Containment Air Temperature 3.6.6 Containment Spray System and Containment Fan Cooler Unit (FCU)

System 3.6.7 Recirculation pH Control System 3.6.8 Not Used 3.6.9 Isolation Valve Seal Water (IVSW) System 3.6.10 Weld Channel and Penetration Pressurization System (WC&PPS)

Indian Point 2 ii Amendment No. 243

Facility Operating License No. DPR-26 Appendix A - Technical Specifications TABLE OF CONTENTS 5.0 ADMINISTRATIVE CONTROLS 5.1 Responsibility 5.2 Organization 5.2.1 Onsite and Offsite Organizations 5.2.2 Unit Staff 5.3 Unit Staff Qualifications 5.4 Procedures 5.5 Programs And Manuals 5.5.1 Offsite Dose Calculation Manual (ODCM) 5.5.2 Primary Coolant Sources Outside Containment 5.5.3 Radioactive Effluent Controls Program 5.5.4 Component Cyclic or Transient Limit 5.5.5 Reactor Coolant Pump Flywheel Inspection Program 5.5.6 Inservice Testing Program 5.5.7 Steam Generator (SG)rb

,8Program 5.5.8 Secondary Water Chemistry Program 5.5.9 Ventilation Filter Testing Program (VFTP) 5.5.10 Explosive Gas and Storage Tank Radioactivity Monitoring Program 5.5.11 Diesel Fuel Oil Testing Program 5.5.12 Technical Specification (TS) Bases Control Program 5.5.13 Safety Function Determination Program (SFDP) 5.5.14 Containment Leakage Rate Testing Program 5.5.15 Battery Monitoring and Maintenance Program 5.6 Reporting Requirements 5.6.1 Not Used 5.6.2 Annual Radiological Environmental Operating Report 5.6.3 Radioactive Effluent Release Report 5.6.4 Not Used 5.6.5 CORE OPERATING LIMITS REPORT (COLR) 5.6.6 Post Accident Monitoring Report 5.6.7 Steam Generator Tube Inspection Report Indian Point 2 iv Amendment No. 242 Indian Point 2 iv Amendment No. 242

Definitions 1.1 1.1 Definitions LEAKAGE LEAKAGE shall be:

a.

Identified LEAKAGE

1.

LEAKAGE, such as that from pump seals or valve packing (except reactor coolant pump (RCP) seal water injection or leakoff), that is captured and conducted to collection systems or a sump or collecting tank,

2.

LEAKAGE into the containment atmosphere from sources that are both specifically located and known either not to interfere with the operation of leakage detection systems or not to be pressure boundary LEAKAGE, or

3.

Reactor Coolant stem (RCS) LEAKAGE through a steam generator to the Secondary SysterW

b.

Unidentified LEAKAGE C,*ear, o $eo^id' L_.A(

All LEAKAGE (except RCP seal water injection or leakoff) that is not identified LEAKAGE, and

c.

Pressure Boundary LEAKAGE lp,-

,,rl LEAKAGE (except-LEAKAGE) through a nonisolable fault in an RCS component body, pipe wall, or vessel wall.

MASTER RELAY TEST A MASTER RELAY TEST shall consist of energizing each required master relays in the channel required for channel OPERABILITY and verifying the OPERABILITY of each required master relay. The MASTER RELAY TEST may be performed by means of any series of sequential, overlapping, or total steps.

MODE A MODE shall correspond to any one inclusive combination of core reactivity condition, power level, average reactor coolant temperature, and reactor vessel head closure bolt tensioning specified in Table 1.1 -1 with fuel in the reactor vessel.

INDIAN POINT 2 1.1 -3 Amendment No. 241

RCS Operational LEAKAGE 3.4.13 3.4 REACTOR COOLANT SYSTEM (RCS) 3.4.13 RCS Operational LEAKAGE LCO 3.4.13 APPLICABILITY:

ACTIONS RCS operational LEAKAGE shall be limited to:

a.

No pressure boundary LEAKAGE,

b.

1 gpm unidentified LEAKAGE,

c.

10 gpm identified LEAKAGE, and

d.

1501aons per day primaryto secondary LEAKAGE through any MODES 1, 2, 3, and 4.

L CONDITION REQUIRED ACTION COMPLETION TIME A.

RCSVLEAKAGE not A.1 Reduce LEAKAGE to 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months within limits for reasons within limits.

other than pressure boundary LEAKAGFp 0

oq 4-.

e ao',r L-..A kiy B.

Required Action and B.1 Be in MODE 3.

6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months associated Completion Time of Condition A not AND met.

B.2 Be in MODE 5.

36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months ODR Pressure boundary LEAKAGE exists.

PE~

'P;mamo 3ec L Akk&-C

~oW;";

INDIAN POINT 2 3.4.13-1 Amendment No. 238

RCS Operational LEAKAGE a.-, /* e6 app lca,6L ft 4,o pri',via y

+0 se-c vv o4 (Lf L E A EK 3.4.13 SURVEILLANCE S R 3.4.1 3.1

O T -

Not required to be performed in MODE 3 or 4 until

-12 hours of steady state operation.

Verify RCS Operational LEAKAGE is within limits by performance of RCS water inventory balance.

72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months If~v1~..f-t 5tcLok4o,.

i*s ~IfO '~eJjor)~

d,*,*o.* **

o,*s'&.

INDIAN POINT 2 3.4.13 -2 Amendment No. 238

TSTF-449, Rev. 4 INSERT 3.4.13 A

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

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.

I

TSTIu.AAb Rau A SG Tube Integrity I W.-,

t' 3.4 REACTOR COOLANT SYSTEM (RCS)

Steam Generator (SG) Tube Integrity LCO 1' SG tube integrity shall be maintained.

AND All SG tubes satisfying the tube repair criteria shall be plugged [or repaired] in accordance with the Steam Generator Program.

APPLICABILITY:

MODES 1,2,3, and 4.

ACTIONS

NOT Separate Condition entry is allowed for each SG ti I-------------------------------------------------------------

CONDITION REQUIRED ACTION COMPLETION TIME A. One or more SG tubes A.1 Verify tube integrity of the 7 days satisfying the tube repair affected tube(s) is criteria and not plugged maintained until the next (9

e

] in refueling outage or SG accordance with the tube inspection.

Steam Generator Program.

AND A.2 Plug 2 the affected Prior to entering tube

in accordance with MODE 4 following the the Steam Generator next refueling outage Program.

or SG tube inspection B. Required Action and B.1 Be in MODE 3.

6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months associated Completion Time of Condition A not AND met.

B.2 Be in MODE 5.

36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months OR SG tube integrity not maintained.

Ind i"

?D,'P14 I I VVJU 0 1 A El fine" Iv.

-1

SG TubeI

~i IRVFILLANCE REOUIREMENTS Q QVFILLANCE REQUI EMENTS SURVEILLANCE FREQUENCY 3*`-1 T

Verify SG tube integrity in accordance with the Steam Generator Program.

In accordance with the Steam Generator Program

-j -:

[

Verify that each Inspected SG tube that satisfies the Prior to entering tube repair criteria Is plugged ;

In MODE 4 following accordance with the Steam GitoProgram.

a SQ tube 1?.

I,~~

Inpcto

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.6 Inservice Testing Program (continued)

b.

The provisions of SR 3.0.2 are applicable to the above required Frequencies for performing inservice testing activities,

c.

The provisions of SR 3.0.3 are applicable to inservice testing activities, and

d.

Nothing in the ASME Boiler and Pressure Vessel Code shall be construed to supersede the requirements of any TS.

5.5.7 1

7 Steam Generator (SG)u 95 r

9'!i4,wceProqram This program assures the co inued integrityo hesteam generato ubes that ara part of the primary coolant ressure bound

. Steam genera r tubes shall e determined OPERABLE y the followin inspection progr and corre tive measures:

a.

Definitions

1.

Imperfe ion is a deviatio from the dimensio finish, or cont ur required by dra ing or specificat n.

2.

Def rmation is a de ation from the initi circular cros -section of th tu ng.

Deformati n includes the d iation from t initial circulr oss-section kno n as denting.

3.

Degradation m ans service-induc cracking, wa age, pitting, w r or corrosion (i.e service-induced i erfections).

Degraded ube is a tube at contains i perfections c sed by degradat' n large enough be reliably tected by ed y current inspett n. This is conside d to be 20% d radation.

5.

% D gradation is an est' ated % of the be wall thickn s affected or re vedbydegradati.

6.

efect is adegradat' n of such sever' ythat it exceed the plugging limit.

Atube containing defect is defeci e.

7 Plugging Limit i the degradation epth at or beyo d which the tube must be plugged or epaired.

8.

Hot-Leg Tue Examination' an examinatio of the hot-leg side tube length. T sshall include t length from the oint of entry at the hot-leg tube sh et around the

-bend to the t support of the cold leg.

INDIAN POINT 2 5.5-6 Amendment No. 238

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.7 Steam Generator (SG) T

.,.iProgram (continued)

9.

Cold-Leg Tube Examination is examination of the cold-leg side tube length. This shall include the ;be length between the top support of t cold leg and the face of th old-leg tube sheet.

b.

Extent and Frequency of mination

1.

Steam genera examinations shall be conducted ot less than 12 months n ater than twenty four calendar month fter the previous examinati 1

2.

Sch uled examinations shall include each o e four steam generators in rvice.

3.

Unscheduled steam generator exa 'ations shall be required in the event there is a prim'ary to s ondary leak exceeding technical specifications, a seisimic occur n=e greater than an operating basis earthquake, a loss-of -coolan ccident requiring actuation of engineer safeguards, or a major st line or feedwater line break.

4.

Unscheduled exami tions may include only the steam g erator(s) affected by the le or other occurrence.

c.

Basic Sample Sel ion and Examination

1.

At leas

% of the tubes in each steam gener or to be examined shall be s jected to a hot-leg examination.

2.

t least 25% of the tubes inspected i echnical Specification 5.5.7.c.1 above shall be subjected to a cold-g examination.

3.

Tubes selected for examinati shall include, but not be limited to, t es in areas of the tube bun in which degradation has been re

rted, either at Indian Point n prior examinations, or at other u' ies with similar steam gener rs.

4.

Examination s 11 be by eddy current techniques specified by the steam gen tor examination program sub red to the NRC in accorda with Technical Specification 5.5.7 n all cases, a probe with atlea a 610-mil diameter shall be used.

Except th the surveillance related to the ste generator tube inspection due no ter than November 17, 2004, ma e deferred until June 17, 2006.

INDIAN POINT 2 5.5-7 Amendment No. 239

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.7 Steam Generator (SG)lTubc Sur...

anc, Program (continued)

d.

Additional Examination riteria (Degradation)

1.

If 5% or mor of the tubes examine in a steam generator exhibit degradation r if any of the tubes ex med in a steam generator are defective, dditional examinations hall be required as specified in Table 5.1

2.

Tube for additional examinati shall be selected from the affected area of e tube array and the ex ination may be limited to that region of the t

e where degradation o efective tube(s) were detected.

3.

The second and third mple inspections in Table 5.5-1 may be limited to the partial tube insp tion only, concentrating on tubes in the areas of th tube sheet array nd on the portion of the tube where tubes h

imperfections w e found.

Acceptance Criter and Corrective Action

1.

Tubess 11 be considered acceptable for continued se e if:

a.

epth of degradation is less than 40% of the e wall thickness, and the tube will permit passage of a 0.610" diameter probe Tubes that are not considered acceptab for continued service shall be plugged or repaired.

Reports and Review

1.

The proposed steam gener r examination program shall besubmitted for NRC staff review least 60 days prior to ea scheduled examination.

2.

The results of eac steam generator examinatio hall be submitted to NRC within 45 ays after the completion the examination.

A significant inc ase in the rate of denting or ignificant change in steam generator ndition shall be reportable i ediately.

3.

Resta, after the scheduled steam erator examination need not be sub* ct to NRC approval.

INDIAN POINT 2 5.5-8 Amendment No. 238

Programs and Manuals 5.5 INDIAN POINT 2 5.5-16 Amendment No. 238

Programs and Manuals 5.5 Table 5.5-1 (Page 2 2)

Steam Generator Tube nspection s insa ct ionPge2 Category C-1 Less an 5% of the total tubes ins cted are degraded t es and none of the is de ctive.isdf ti Category C-2 One or more of the total tube! inspected is defecti but less than 1% oft e tubes inspected are defective a less than 10% of t tubes inspected are egraded Ca ory C-3 More than 10% of th otal inspected are graded or more than % of the tubes inspected are defe ive.

INDIAN POINT 2 5.5 - 17 Amendment No. 238

TSTF-449, Rev. 4 INSERT 5.5f<-

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:

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 tubing during an SG inspection outage, as determined from the inservice inspection results or by other means, prior to the plugging rg Ilof tubes. Condition monitoring assessments shall be conducted during each outag ring which the SG tubes are inspected, pluggedUr FFePa.di]Fo confirm that the performance criteria are being met.

b.

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.

1.

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 andleakage rate for an individual SG. Leakage is not to tpexRe'ei*[,prfi 1per S[,e t~r spep'c types ef deg;6datioD,,at spetific*

/

/ 1

~

~ioaors a-'asds~criDe1 1ý1 0=,

I gA417,6 the SteaWnGerderator, rogr= ý~l--

3.

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

c.

Provisions for SG tube repair criteria. Tubes found by inservice inspection to contain flaws with a depth equal t or exceeding 40f/4 of the nominal tube wall thickness shall be plugged d.

I

TSTF-449, Rev. 4

d.

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.

Review r's Note ------------

Plants ar o include the propriate Fr eency (e.g.,

lect the ppropriate em 2.) f their S-design. The fir Item 2 is app~ able to SGswith AIlo 600 mill a ealed t ing.

The s cond Item 2 is plicable to S s with Alloy 0 the ly treated bing. T third te

.2. is applicable oSGs with All 690 therm Y treate tubing.

1.

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

[2.

Insp t 100% of the es at seque ial periods of effective full po er month T

first sequenti eriod shall b considered to Igin after the fir inservice spection of th Gs. No SG all operate for ore than 24 eff ctive full wer months or on refueling out e (whichever is ess) without be, g inspec

.]

2.

Inspect 100% of the tubes at sequential periods of 120, 90, 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 48 effective full power months or two refueling outages (whichever is less) without being inspectedf

[2./lspect 100°/% of ttubes at sequentia eriods of 144, 8, 72, and, th heafter, 60 effective full p0er months. The fir equential ped hall be consi red to begin

2

TSTF-449, Rev. 4 after the firs nservice i pection of the Gs. In ad "dion, inspec 0% of th tubes by the refu ing outag nearest the mi point of the eriod and t e remaini g 50% b the refueli g outage 'earest the end ~f the period'. No SG shalI operate/for more/

than 72 ective ful power months r three ref ling outag (whiche r is less without eing insp cted.]

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(s), then the indication need not be treated as a crack.

e.

Provisions for monitoring operational primary to secondary LEAKAGE.

[f.

Provisions for tube repair m ods. Steam gener tor tube repair ethods shall provide the ans to reestabli the RCS pressure oundary integri of SG tubes ithout removing t tube from servi e. For the purposes f these Specifi tions, tube pgging is not a rep i. All acceptabl ube repair methods re listed below

Review s Note ------

Tub repair methods urrently permitted by lant technical ecifications eto be listed hee. The descripti n of these tube repa ethods shoul be equivalen o the scriptions in cu ent technical i

ions. If there e no approve tube repair methods, this s tion should not be us S------------

1.]

3

Reporting Requirements 5.6 5.6 Reporting Requirements 5.6.5 CORE OPERATING LIMITS REPORT (COLR) (continued)

8.

WCAP-12610-P-A, "VANTAGE+ Fuel Assembly Reference Core Report", April 1995.

9.

WCAP-10079-P-A, "NOTRUMP, A Nodal Transient Small Break and General Network Code", August 1985;

10.

WCAP-1 0054-P-A, 'Westinghouse Small Break ECCS Evaluation Model Using the NOTRUMP Code", August 1985; and

11.

WCAP-10054-P-A, Addendum 2, Revision 1, "Addendum to the Westinghouse Small Break ECCS Evaluation Model Using the NOTRUMP Code: Safety Injection Into the Broken Loop and Cosi Condensation Model", July 1997.

c.

The core operating limits shall be determined such that all applicable limits (e.g., fuel thermal mechanical limits, core thermal hydraulic limits, Emergency Core Cooling Systems (ECCS) limits, nuclear limits such as SDM, transient analysis limits, and accident analysis limits) of the safety analysis are met.

d.

The COLR, including any midcycle revisions or supplements, shall be provided to the NRC upon issuance for each reload cycle.

5.6.6 Post Accident Monitoring Report When a report is required by Condition B or F of LCO 3.3.3, "Post Accident Monitoring (PAM) Instrumentation," a report shall be submitted within the following 14 days. The report shall outline the preplanned alternate method of monitoring, the cause of the inoperability, and the plans and schedule for restoring the instrumentation channels of the Function to OPERABLE status.

5.6.7 Steam Generator Tube Inspection Report If the results of the steam neherator inspection idi te greater than 1% of the inspected tubes in any s) am generator exceed e repair criteria in accorda e

with the requirements, the Steam Generator rogram, a Special Report all be submitted within 12,days after the initial ey into MODE 4 following c pletion

"*vt e-r+

of the inspectio he report shall summ ze:

c-'1 Thi rnna nf inQn rotinnc na rmad nn onh Qti nan *tnr inen*ptari in e affected unit during e current outage,

/

Active degradation m hanisms found, c)

NDE techniques tilized for each degradati mechanism INDIAN POINT 2 5.6-4 Amendment No. 241

Reporting Requirements 5.6 5.6 Reporting Requirements 5.6.7 Steam Generator Tube Inspection Report (continued) d)

Location, orientation (if linear nd measured sizes (if a ilable) of service induced indications, e)

Number of tubes plug d or repaired during the,* spection outage f each active degrad n mechanism, f)

Repair method ilized and the number of bes repaired by ch repair

method, g)

Total num r and percentage of tub plugged and/or r aired to date, h)

The e ctive plugging percenta for all plugging a tube repairs in eac steam generator, and i) he results of condition nitoring including t results of tube pulls and in-situ testing.

INDIAN POINT 2 5.6-5 Amendment No. 241

TSTF-449, Rev. 4 INSERT 5.6 4__.J 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 5.54 Steam Generator (SG) Program. The report shall include:

a.

The scope of inspections performed on each SG,

b.

Active degradation mechanisms found,

c.

Nondestructive examination techniques utilized for each degradation mechanism,

d.

Location, orientation (if linear), and measured sizes (if available) of service induced indications,

e.

Number of tubes plugged" j[i-1j;*i during the inspection outage for each active degradation mechanism,

f.

Total number and percentage of tubes plugged[O :

to date,

g.

The results of condition monitoring, including the results of tube pulls and in-situ testing, The effective plugging percentage for all pluggingrrj*i*

n each SGi

[i.

.pair m"tod utilize/d/and the/pdmber oVIA bes re~pred byVdCh repi'metho,5k(

Facility Operating License No. DPR-64 Appendix A - Technical Specifications TABLE OF CONTENTS 3.4 REACTOR COOLANT SYSTEM (RCS) 3.4.1 RCS Pressure, Temperature, and Flow Departure from Nucleate Boiling (DNB)

Limits 3.4.2 RCS Minimum Temperature for Criticality 3.4.3 RCS Pressure and Temperature (P/T) Limits 3.4.4 RCS Loops-MODES 1 and 2 3.4.5 RCS Loops-MODE 3 3.4.6 RCS Loops-MODE 4 3.4.7 RCS Loops-MODE 5, Loops Filled 3.4.8 RCS Loops-MODE 5, Loops Not Filled 3.4.9 Pressurizer 3.4.10 Pressurizer Safety Valves 3.4.11 Pressurizer Power Operated Relief Valves (PORVs) 3.4.12 Low Temperature Overpressure Protection (LTOP) 3.4.13 RCS Operational LEAKAGE 3.4.14 RCS Pressure Isolation Valve (PIV) Leakage 3.4.15 RCS Leakage Detection Instrumentation 3.4.16 RCS Specific Activity 3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS) 3.5.1 Accumulators 3.5.2 ECCS-Operating 3.5.3 ECCS-Shutdown 3.5.4 Refueling Water Storage Tank (RWST) 3.6 CONTAINMENT SYSTEMS 3.6.1 Containment 3.6.2 Containment Air Locks 3.6.3 Containment Isolation Valves 3.6.4 Containment Pressure 3.6.5 Containment Air Temperature 3.6.6 Containment Spray System and Containment Fan Cooler System 3.6.7 Spray Additive System 3.6.8 Not Used 3.6.9 Isolation Valve Seal Water (IVSW)

System 3.6.10 Weld Channel and Penetration Pressurization System (WC & PPS)

(continued)

INDIAN POINT 3 ii Amendment 228

Facility Operating License No. DPR-64 Appendix A - Technical Specifications TABLE OF CONTENTS 4.0 DESIGN FEATURES 4.1 Site Location 4.2 Reactor Core 4.3 Fuel Storage 5.0 ADMINISTRATIVE CONTROLS 5.1 Responsibility 5.2 Organization 5.3 Unit Staff Qualifications 5.4 Procedures 5.5 Programs and Manuals 5.5.1 Offsite Dose Calculation Manual (ODCM) 5.5.2 Primary Coolant Sources Outside Containment 5.5.3 NOT USED 5.5.4 Radioactive Effluent Controls Program 5.5.5 Component Cyclic or Transient Limit 5.5.6 Reactor Coolant Pump Flywheel Inspection Program 5.5.7 Inservice Testing Program 5.5.8 Steam Generator (SG)

Tube Surqein" Program 5.5.9 Secondary Water Chemistry Program 5.5.10 Ventilation Filter Testing Program (VFTP) 5.5.11 Explosive Gas and Storage Tank Radioactivity Monitoring Program 5.5.12 Diesel Fuel Oil Testing Program 5.5.13 Technical Specification (TS)

Bases Control Program 5.5.14 Safety Function Determination Program (SFDP) 5.5.15 Containment Leakage Rate Testing Program 5.6 Reporting Requirments 5.6.1 NOT USED 5.6.2 Annual Readiological Environmental Operating Report 5.6.3 Radioactive Effluent Release Report 5.6.4 NOT USED 5.6.5 CORE OPERATING LIMITS REPORT (COLR) 5.6.6 NOT USED 5.6.7 Post Accident Monitoring Instrumentation (PAM)

Report 5.6.8 Steam Generator Tube Inspection Report 5.7 High Radiation Area INDIAN POINT 3 iv Amendment 227

Definitions 1.1 1.1 Definitions LEAKAGE (continued) system not directly connected to the atmosphere.

Leakage past the pressurizer safety valve seats and leakage past the safety injection pressure isolation valves are examples of reactor coolant system leakage into closed systems.)

2.

LEAKAGE into the containment atmosphere from sources that are both specifically located and known either not to interfere with the operation of leakage detection systems or not to be pressure boundary LEAKAGE: or

3.

Reactor Coolant System (RCS)

LEAKAGE through a steam generator 1=to the Secondary System:

b.

Unidentified LEAKAGE All LEAKAGE (except for leakage into closed systems and RCP seal water injection or leakoff) that is not identified LEAKAGE;

c.

Pressure Boundary LEAKAGE LEAKAGE (except

_LEAKAGE) through a nonisolable fault in an RCS component body, pipe wall, or vessel wall.

A MASTER RELAY TEST shall consist of energizing each master relay and verifying the OPERABILITY of each relay.

The MASTER RELAY TEST shall include a continuity check of each associated slave relay.

A MODE shall correspond to any one inclusive combination of core reactivity condition, power level, average reactor coolant loop temperature, and reactor MASTER RELAY TEST MODE (continued)

INDIAN POINT 3 1.1-4 Amendment 205

RCS Operational LEAKAGE 3.4.13 3.4 REACTOR COOLANT SYSTEM (RCS) 3.4.13 RCS Operational LEAKAGE LCO 3.4.13 RCS operational LEAKAGE shall be limited to:

a.

No pressure boundary LEAKAGE:

b.

1 gpm unidentified LEAKAGE; C.

10 gpm identified LEAKAGE; d./

V 1 ratotal nimaryd o

enar hroughp 11sti

,/ erator (SGS)$nd/

//I ne gallons per day primary to secondary LEAKAGE through any 1 17 ne *-l ftrn' fl.4 od?'5)

APPLICABILITY:

MODES 1. 2 ACTIONS

. 3, and 4.

I CONDITION REQUIRED ACTION COMPLETION TIME A.

RCSLEAKAGE not within A.1 Reduce LEAKAGE to within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months limits for reasons other limits.

than pressure boundary LEAAG b r ffi%(ptov 4-ecandeu (AA B.

Required Action and B.1 Be in MODE 3.

6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months associated Completion Time of Condition A not AND met.

B.2 Be in MODE 5.

36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months Pressure boundary LEAKAGE exists.

&-to* 4 0

fe LLAS Act no1v W h, 1I..

INDIAN POINT 3 3.4.13-1 Amendment 205

RCS Operational LEAKAGE 3.4.13 SL A

r EQIRE.'C-44 1

Lf iry MN eSr'1 Ak-A C SURVEILLANCE REQUIREMENTS I.

SURVEILLANCE FREQUENCY 9.

SR 3.4.13.1 NOTE*-----------

Not required to be performed in MODE 3 or 4 until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months of steady state operation.

Verify RCS Operational[J-4is within limits by performance of RCS water inventory balance.

..... NOTE......

Only required to be performed during steady state operation 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months SR 3.4.13.2 Verify eam gener or tube 'iegrity i in acco ance with Steam nerator S eillnce P ram.

I T

In ac rdan~e wi* the 1ieam P/IneraJ Ty ISurv 1 1a peI Fi~T]

L2JŽ~i eieu 4-hrow~j

~41k o-o C

o

c.

INDIAN POINT 3 3.4.13-2 Amendment 205

TSTF-449, Rev. 4 INSERT 3.4.13 A

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

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.

1

SG Tube II wI--

3.4 REACTOR COOLANT SYSTEM (RCS)

Steam Generator (SG) Tube Integrity LCO I SG tube integrity shall be maintained.

AND All SG tubes satisfying the tube repair criteria shall be plugged [or repaired] in accordance with the Steam Generator Program.

APPLICABILITY:

MODES 1,2, 3, and 4.

ACTIONS NOT Separate Condition entry is allowed for each SG ti r

CONDITION REQUIRED ACTION COMPLETION TIME A. One or more SG tubes A.1 Verify tube integrity of the 7 days satisfying the tube repair affected tube(s) is criteria and not plugged maintained until the next

[o repain refueling outage or SG accordance with the tube inspection.

Steam Generator Program.

AND A.2 Plug the affected Prior to entering tube s in accordance with MODE 4 following the the Steam Generator next refueling outage Program.

or SG tube inspection B. Required Action and B.1 Be in MODE 3.

6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months associated Completion Time of Condition A not AND met.

B.2 Be in MODE 5.

36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months OR SG tube integrity not maintained.

v v %.#%.A 1j I ",I El fin"An" A"

> -1 pow

SG Tube Integ' SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY AII I

Verify SG tube integrity In accordance with the Steam Generator Program.

In accordance with the Steam Generator Program R 3i*

Verify that each Inspected SG tube that satisfies the Prior to entering tube repair criteria Is pluggedln MODE 4 following accordance with the Steam Generator Program.

a SG tube Inspection w. %w 1%4 %# 9 I~

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.8 Steam Generator (SG) il;ýncelproara J-4 5.5 Programs and Manuals This program provides contr s for the inservice inspection of SG ubes to assure the continued int ity of the Reactor lant System pre ure boundary and shall inclu the following:

a.

S/ Selection a SG Tube Sample Size The minimum mple size shall be ' -conformance wit the requirement specified i Table 5.5-1.

Sele ion and testing steam generator tubes sha be made on the fol owing basis:

1.

the first inservic inspection subs ent to the pre-ervice inspection.

ix percent of t tubes in each o two steam generators s 11 be inspected s a minimum.

2 At the second i ervice inspectio subsequent to pre-service inspec.ion, twelve perc t of the tubes one of the two steam ge rators not ins ted during the f/rst inservice inspection all be inspect as a minimum.

3.

At the t 'rd inservice in ction subseque to the pre-servic inspection, twel e percent of t tubes in the steam gener or not inspect during the firs two inservice ins tions shall be nspected as a m imum.

4.

Furth and subseq n inservice in tions may be limit to ne steam genera r on a rotati schedule encompassing 21 of the tubes if he results of first or previous inspections i icate that all team generators are rforming in like man r. Under some ircumstances. the ope ating conditions n one or more eam generators may found to be more sev e than those i other steam generator.

Under such circums nces, the samp sequences should modified to ins the steam gen ator with the most s ere conditions.

5.

Un heduled ins ons should be condu ed on the affected s am generator(s in accordance with first sample (continued)

INDIAN POINT 3 5.0-13 Amendment 205

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.8 Steam Generator (SG) veia'ProQram (continued) inspection specied in Table 55-1 the event prim ry-da s tu, ng lek ofr tta to-secondary tu e leaks (not inc leaks originat from tube-to-tube eet welds) exceediA technical specifi ations, a seismic oc rrence greater thai an operating basi earthquake, a loss-of-coolant cident requiring a uation of engineer safeguards, or a m jor steam line or edwater line bre

b.

SG Tube Sel ction Criteria

1.

Tu s for the inspecti n should be select on a random basis e cept where experie e in similar plan with similar water hemistry indicates critical areas to inspected.

2.

The first sample nspection subsequ t to the pre-servic inspection shold include all non-ugged tubes that previously ha detectable wall etration (> 20%) a should also include ubes in those are s where experience s

indicated tential problems.

3.

The sec d and third sampl inspections in Tab 5.5-1 may be limite to the partial tu e inspection only, oncentrating on tubes in the areas of t tube sheet array d on the portion of e tube where tube with imperfection were found.

4.

all inspections, reviously degrade tubes must exhibit ignificant ('

further wall penet ation to be included in the percentage c culation for the sult categories in Table 5.5-1.

C.

nspection FREQUE

1.

Inservice inspections shoul be not less than 12 or more than 24 cale ar months after t e previous inspection.

/

(continued)

INDIAN POINT 3 5.0-14 Amendment 205

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.8 S(continued)

2.

If the esults of two conse tive inspections,/not including the pr service inspection, 11 fall into the-1 category,/

the fVequency of inspecti may be extended o 40-month intevals.

Also, if it n be demnstrated through tw consecutive ins tions that pr viously observed d adation has not ontinued and no a ditional degradatio has occurred, a 0-month inspection

.terval may be initated.

3.

SR 3.0.2 is appl ic le to the Steam enerator Tube Surveillance Pro am test frequenc' s.

d.

Cl ssification of Te Results Definitions:

Imperfect is an exceptio to the dimension, fj ish, or contour r uired by drawin or specification.

De rada *on means a serv e-induced cracking wastage, wear or cor osion.

Dear /ded Tube is a tu that contains im rfections caused y eddeg adation large e ugh to be reliably etected by eddy curent inspection.

This is considerey to be 20%

gradation.

Dgradatio i an estimate % of e tube wall thic ess affected or re oved by degradati/

/

Defect is an imperfectionbofcs h severity that exceeds tfhe pluggi limit. A ubc taming a defect is defective.

(continued)

INDIAN POINT 3 5.0-15 Amendment 205

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.8 S

n r

(

n Proram (continued)

SPlu n im" is the tube impe ection depth at or beyond which the tu must either be remov from service or repaired.

This is con dered to be an imperf ction depth of 40t.

" i is the sl ve imperfection depth at or beyond ci the sleeved tube ust be removed from service or repaired.

This is consid ed to be an imperfection de of 40t for tu sleeves.

t is a full length inspection for the i ial 3X sa le specified in Tab 5.5-1.

Supplemental sampl inspections (fter the initial U mple) may be limited to a rtial length spection concentrat ng on those locations where radation has strn found.

2.

Results Cla ifications The resul s of each sampling examina on of a steam generato shl lssified into the follow~ing threecaeois

-1: Less than 5% of t total tubes inspected re degr ded tubes and none are de ive.

C r

One or more bu not more than U of t total ubes inspected are defect* e or between 5 and 10 of the tubes inspected are degraed tubes.

Category C-3: More tha 10% of the total tube inspected are degraded or more tha 1% of the tubes ins ed are defective.

/e Corrective Action

1.

The inspecti result classificati and the corresponding required a ion are specified in able 5.5-1.

(continued)

INDIAN POINT 3 5.0-16 Amendment 205

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.8 Steam Generator (SG)ITub S~rveilarke Program (continued)

2.

All leaking tu s and defective tu s should be plug or repaired.

3.

Results o steam generator t inspections whi fall into Categor C-3 of Table 5.5-1 equire notificat in of the NRC ithin 15 da of this determina on.

/

s

4.

approval prior to tartup is requir when SG Tu Inspections dentify Category C-degradation or fects in mor than one SG.

(continued)

INDIAN POINT 3 5.0-17 Amendment 205

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5 Programs and Manuals TABLV 5.5-1 (page 1 of 2)

STEAM AENERATOR TUBE INSPECTION First Sample Saimple Third S4i1 Result Required Action suit Required Action Result Required Action C-i Acceptable for

/C-i Acceptable for C-i Acceptable for Service Service Service C-2 Plug or Repair C-i Acceptable for N/

N/A defective tubes Service AND C-2 Plug or Repair C-Acceptable for defective tubes Service 2Stubesin is AND C-2 Plug or Repa SG defective t s Inspect additional 4S tubes in this AND Accepta e for Servic C-3 Ins all tubes in is SG lug or Repair dfdefective tubes AND Inspect 2S tubes in each other SG C-3 nspect all tubes N/A N/A

/in this SG AND Plug or Repair defective tubes AND Inspect 2S tubes

,__in each other SG

/

(continued)

INDIAN POINT 3 5.0-18 Amendment 205

Programs and Manuals 5.5 5.5 Programs and Manuals le 2 ECI2) 1E SPECTION AND Plug or Repair defective tubes AND Report and NRC Approval required prior to startup where:

N is the number of steam n is the number of ste Result Classifications (C-1, C-2And C

ýrifig an examination ion 5.5.8.d.

INDIAN POINT 3 5.0-19 Amendment 205

TSTF-449, Rev. 4 INSERT 5.5{*<-!

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:

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 tubing during an SG inspection outage, as determined from the inservice inspection results or by other means, prior to the plugging II4of tubes. Condition monitoring assessments shall be conducted during each outage during which the SG tubes are inspected, plugged,J1cr Iepa*red~4to confirm that the performance criteria are being met.

b.

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.

1.

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

?

. ]

lealka rate for all SG-and~leakage rate for an individual SG. Leakage is not to

%GnDt excee A.[

er, ep:rspeictypesqfdegdatioot sp ific

ý/,,d$,tlec e

peagraph,¢ the Stem Ge feratorProggmý-

3.

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

c.

Provisions for SG tube repair criteria. Tubes found by inservice inspection to contain flaws with a depth equal tq or exceedingf0f/i of the nominal tube wall thickness shall be pluggedVtrpre.

I-, U

.14 1

------------------ Reviewer' ote ---------------- -----------------------------

A s

e re e

e e Alternate tube rep i criteria currently permi by plant techni I specifications are li ed he c rna e e h d here. The descr' tion of these alternate tu repair criteria s uld be equivalent to e

de nt s jo eio descriptions in urrent technical specific ons and should so include any allow t

t accident ind ed leakage rates for spe ic types of degr ation at specific loc ons ident ind ed lea s 'r sp associated ith tube repair criteria.

ociated ith tube re n

r kag crip-nt tý n

it as rr 0"

d p i

sct c p su r -

r u

t 1/based criteria:

[The Ilowing alternate tube re ir criteria may applied as an alter tive to the 40%

d.

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.

-R eview er' N ote Plants to include the ap ropriate Frequ cy (e.g., select the a ropriate Item 2.)

r their design. The firs tem 2 is applic le to SGs with Alloy 00 mill annealed t ing.

Th econd Item 2 is a licable to SGs ith Alloy 600 therm treated tubing.

e third It 2 is applicable t Gs with Alloy 90 thermally treated bing.

7----------------------------

1.

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

[2.

Inspectl 10oof the tubes at sequential priods of 60 effective fu power months./

The first

.quential period shall be consJ ered to begin after th first inservice/

inspecti

'n of the SGs. No SG shall citrate for more than 24/ ffective full powe month or one refueling outage (whiever is less) without

'ing inspected.]

[2.

Ins pect 100% of the tubes at seq, 'ntial periods of 120,

0, and, thereafte 60 eective full power months. Th e'first sequential perio eshall be conside red to begin ater the first inservice inspect* n of the SGs. In ad liion, inspect 50 °/o%0 the tubes

/ b he refueling outage near r'tt e m d o n f h/

ei d a dt e reaining 50% by Sthe refueling outage neare

the end of the peri o/. No SG shall op erate for more

/ than 48 effective full po w r months or two refu,,eing outages (whi iever is less)

!without being inspected*

.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 2

TSTF-449, Rev. 4 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 inspectedl

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(s), then the indication need not be treated as a crack.

e.

Provisions for monitoring operational primary to secondary LEAKAGE.

[f.

Provisions fo G tube rep I methods. Steam enerator tu repair metho shall provide th eans to ree ablish the RCS pr sure bound integrity of tubes with t

removin he tube fro service. For the pu oses of the Specification, tube pluggig is not a pair. All acc table tube repair m hods are lis d below.

P~viewer's No................ -------------------

ube repair ethods currently perm ed by plant chnical speci ations are t e listed here. The escription of these tub repair meth ds should be uivalent to e

descrip i ns in current technical ecifications If there are n approved t e repair meth s, this section should n be used.

1]

/

'3

Reporting Requirements 5.6 5.6 Reporting Requirements 5.6.7 Post Accident Monitorina Instrumentation (PAM)

Report When a report is required by LCO 3.3.3, "Post Accident Monitoring (PAM)

Instrumentation," a report shall be submitted within the next 14 days.

The report shall outline the preplanned alternate method of monitoring, the cause of the inoperability, and the plans and schedule for restoring the instrumentation channels of the Function to OPERABLE status.

5.6.8 Steam Generator Tube Insprection Report The number of tube plugged or paired in eac steam generpor during each inservice i pection of eam generator ubes shall V reported t the Commission wit n 15 days lowing the in ction.

Complete r ults of the team generator ube inservi inspectio' shall be reported n writing o an annual basi for the pern in whichTne inspec:io was compl eed per Specifi ation 5.5.8.//This repor shall incl e:

a Number an extent of tube inspected.

b.

Locat' n and percent wall-thickn ss penetrati n for each ndication of imperfection.

c.

dentification o the tubes pl gged and th tubes rep fred.

INDIAN POINT 3 5.0-36 Amendment 205

TSTF-449, Rev. 4 INSERT 5.6§#*__

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 5.59 Steam Generator (SG) Program. The report shall include:

a.

The scope of inspections performed on each SG,

b.

Active degradation mechanisms found,

c.

Nondestructive examination techniques utilized for each degradation mechanism,

d.

Location, orientation (if linear), and measured sizes (if available) of service induced indications,

e.

Number of tubes plugged [rJ;;f'e' during the inspection outage for each active degradation mechanism,

f.

Total number and percentage of tubes plugg ed[o eo

date,

g.

The results of condition monitoring, including the results of tube pulls and in-situ testing, The effective plugging percentage for all plugging' jr i

in each SG J (._J

[i.

,/*pair mtod utilizeý/and theodmber oY' bes reppafed byých repýhmetho 2 I

ATTACHMENT III TO NL-06-063 MARKUP OF TECHNCIAL SPECIFICATION BASES PAGES FOR PROPOSED CHANGES REGARDING STEAM GENERATOR TUBE INTEGRITY, TSTF-449 (for information only)

Affected Sections (IP2)

Table of Contents 3.4.4 3.4.5 3.4.6 3.4.7 3.4.13 3.4.17 (new section added)

Affected Sections (IP3)

Table of Contents 3.4.4 3.4.5 3.4.6 3.4.7 3.4.13 3.4.17 (new section added)

ENTERGY NUCLEAR OPERATIONS, INC.

INDIAN POINT NUCLEAR GENERATING UNITS NO. 2 and 3 DOCKET NO. 50-247 and 50-286

Facility Operating License No. DPR-26 Appendix A - Technical Specifications TABLE OF CONTENTS B.3.4.10 Pressurizer Safety Valves B.3.4.11 Pressurizer Power Operated Relief Valves (PORVs)

B.3.4.12 Low Temperature Overpressure Protection (LTOP)

B.3.4.13 RCS Operational LEAKAGE B.3.4.14 RCS Pressure Isolation Valve (PIV) Leakage B.3.4.15 RCS Leakage Detection Instrumentation B.3.4.16 RCS Specific Activity /--IS

-e-nerJ'or (5s&) Tab't -tvft, rr./4 B.3.5 EMERGENCY CORE COOLING SYSTEM (ECCS)

B.3.5.1 Accumulators B.3.5.2 ECCS - Operating B.3.5.3 ECCS - Shutdown B.3.5.4 Refueling Water Storage Tank (RWST)

B.3.6 CONTAINMENT SYSTEMS B.3.6.1 Containment B.3.6.2 Containment Air Locks B.3.6.3 Containment Isolation Valves B.3.6.4 Containment Pressure B.3.6.5 Containment Air Temperature B.3.6.6 Containment Spray System and Containment Fan Cooler Unit (FCU)

System B.3.6.7 Recirculation pH Control System B.3.6.8 Not Used B.3.6.9 Isolation Valve Seal Water (IVSW) System B.3.6.10 Weld Channel and Penetration Pressurization System (WC&PPS)

B.3.7 PLANT SYSTEMS B.3.7.1 Main Steam Safety Valves (MSSVs)

B.3.7.2 Main Steam Isolation Valves (MSIVs) and Main Steam Check Valves (MSCVs)

B.3.7.3 Main Feedwater Isolation B.3.7.4 Atmospheric Dump Valves (ADVs)

B.3.7.5 Auxiliary Feedwater (AFW) System B.3.7.6 Condensate Storage Tank (CST)

B.3.7.7 Component Cooling Water (CCW) System B.3.7.8 Service Water System (SWS)

B.3.7.9 Ultimate Heat Sink (UHS)

B.3.7.10 Control Room Ventilation System (CRVS)

B.3.7.11 Spent Fuel Pit Water Level B.3.7.12 Spent Fuel Pit Boron Concentration B.3.7.13 Spent Fuel Pit Storage B.3.7.14 Secondary Specific Activity B.3.8 ELECTRICAL POWER SYSTEMS B.3.8.1 AC Sources - Operating INDIAN POINT 2 ii Revision 1

RCS Loops - MODES 1 and 2 B 3.4.4 BASES APPLICABLE SAFETY ANALYSES (continued)

Both transient and steady state analyses have been performed to establish the effect of flow on the departure from nucleate boiling (DNB). The transient and accident analyses for the plant have been performed assuming four RCS loops are in operation. The majority of the plant 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 four pump coastdown, single pump locked rotor, single pump (broken shaft or coastdown), and rod withdrawal events (Ref. 1).

Steady state DNB analysis has been performed for the four RCS loop operation. For four RCS loop operation, the steady state DNB analysis generates the pressure and temperature Safety Limit (SL) (i.e., the departure from nucleate boiling ratio (DNBR) limit) by assuming a maximum for the power level. This is the design overpower condition for four RCS loop operation. The allowable value for the nuclear overpower (high flux) trip in LCO 3.3.1, "Reactor Protection System (RPS) Instrumentation," is based on this analysis assumption and bounds instrumentation errors. The DNBR limit defines a locus of pressure and temperature points that result in a minimum DNBR greater than or equal to the critical heat flux correlation limit.

The plant is designed to operate with all RCS loops in operation to maintain DNBR above the SL, during all normal operations and anticipated transients.

By ensuring heat transfer in the nucleate boiling region, adequate heat transfer is 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)(ii).

LCO The purpose of this LCO is to require an adequate forced flow rate for core heat removal. Flow is represented by the number of RCPs in operation for removal of heat by the SGs. To meet safety analysis acceptance criteria for DNB, four 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 a'ccordance wlith them -C-te*_m GeniaeraterTbe u.,e!nePr rm.

APPLICABILITY In MODES 1 and 2, the reactor is critical and thus has the potential to produce maximum THERMAL POWER.

Thus, to ensure that the assumptions of the accident analyses remain valid, all RCS loops are required to be OPERABLE and in operation in these MODES to prevent DNB and core damage.

INDIAN POINT 2 B 3.4.4 - 2 Revision 0

RCS Loops - MODE 3 B 3.4.5 BASES LCO (continued)

Utilization of the Note is permitted provided the following conditions are met, along with any other conditions imposed by test or maintenance procedures:

a.

No operations are permitted that would dilute the RCS boron concentration with coolant at boron concentrations less than required to assure the SDM of LCO 3.1.1, thereby maintaining the margin to criticality. Boron reduction with coolant at boron concentrations less than required to assure SDM is maintained is prohibited because a uniform concentration distribution throughout the RCS cannot be ensured when in natural circulation.

This Note does not prohibit injection into the RCS of water with a boron concentration that is equal to or greater than the minimum boron concentration needed to meet the SDM requirement in LCO 3.1.1 even if the water being injected has a lower boron concentration than the water already in the RCS.

b.

Core outlet temperature is maintained at least 1 0°F below saturation temperature, so that no vapor bubble may form and possibly cause a natural circulation flow obstruction.

An OPERABLE RCS loop consists of one OPERABLE RCP and one OPERABLE SG'-.

Uc, I w

Rt G n

,which'has the minimum water level specified in SR 3.4.5.2. An RCP is OPERABLE if it is capable of being powered and is able to provide forced flow if required.

APPLICABILITY In MODE 3, this LCO ensures forced circulation of the reactor coolant to remove decay heat from the core and to provide proper boron mixing. The most stringent condition of the LCO, that is, two RCS loops OPERABLE and two RCS loops in operation, applies to MODE 3 with the Rod Control System capable of rod withdrawal. The least stringent condition, that is, two RCS loops OPERABLE and one RCS loop in operation, applies to MODE 3 with the Rod Control System not capable of rod withdrawal.

Operation in other MODES is covered by:

LCO 3.4.4, LCO 3.4.6, LCO 3.4.7, LCO 3.4.8, "RCS Loops - MODES 1 and 2,"

"RCS Loops - MODE 4,"

"RCS Loops - MODE 5, Loops Filled,"

"RCS Loops - MODE 5, Loops Not Filled,"

INDIAN POINT 2 B 3.4.5 - 3 Revision 0

RCS Loops - MODE 4 B 3.4.6 BASES LCO (continued)

An OPERABLE RCS loop comprises an OPERABLE RCP and an OPERABLE SGt,,,

with the S

[

a, which has the minimum water level specified in SR 3.4.6.2.

An OPERABLE RHR loop consists of one OPERABLE RHR pump and one OPERABLE RHR heat exchanger as well as associated piping and valves to transfer heat between the RHR heat exchanger and the core. Although either RHR heat exchanger may be credited for either RHR loop, one RHR heat exchanger must be OPERABLE for each OPERABLE RHR loop.

RCPs and RHR pumps are OPERABLE if they are capable of being powered and are able to provide forced flow if required.

APPLICABILITY In MODE 4, this LCO ensures forced circulation of the reactor coolant to remove decay heat from the core and to provide proper boron mixing. One loop of either RCS or RHR provides sufficient circulation for these purposes.

However, two loops consisting of any combination of RCS and RHR loops are required to be OPERABLE to meet single failure considerations.

Operation in other MODES is covered by:

LCO 3.4.4, LCO 3.4.5, LCO 3.4.7, LCO 3.4.8, LCO 3.9.4, LCO 3.9.5, "RCS Loops - MODES 1 and 2,"

"RCS Loops - MODE 3,"

"RCS Loops - MODE 5, Loops Filled,"

"RCS Loops - MODE 5, Loops Not Filled,"

"Residual Heat Removal (RHR) and Coolant Circulation -

High Water Level" (MODE 6), and "Residual Heat Removal (RHR) and Coolant Circulation -

Low Water Level" (MODE 6).

ACTIONS A.1 If one required loop is inoperable, redundancy for heat removal is lost.

Action must be initiated to restore a second RCS or RHR loop to OPERABLE status.

The immediate Completion Time reflects the importance of maintaining the availability of two paths for heat removal.

INDIAN POINT 2 B 3.4.6-3 Revision 0

RCS Loops - MODE 5, Loops Filled B 3.4.7 BASES LCO (continued)

Note 4 provides for an orderly transition from MODE 5 to MODE 4 during a planned heatup by permitting removal of RHR loops from operation when at least one RCS loop is in operation. This Note provides for the transition to MODE 4 where an RCS loop is permitted to be in operation and replaces the RCS circulation function provided by the RHR loops.

RHR pumps are OPERABLE if they are capable of being powered and are able to provide flow if required. ASG can perform as a heat sink via natural circulation when it has an adequate water level and is OPERABLEI;11 Viclc wi' h

taianntT b

uviln If the SGs being credited as the redundant method of decay heat removal depend on natural circulation (Ref. 1) for decay heat removal, the SGs are considered OPERABLE only if:

a. RCS loop and reactor pressure vessel filling and venting was completed during startup or pressurizer level has been maintained > 10% to assure no draining of SG tubes,

b. The ability to pressurize and control pressure in the RCS to > 100 psig is maintained to control the potential for flashing and void formation at the top of the SG tubes; and,

c. The Condensate Storage Tank (CST) and the motor driven auxiliary feedwater pump(s) associated with the credited SGs is operable.

Additionally, the level indication in the pressurizer should be monitored since an unexplained rise in level could be indicative of non-condensable gases coming out of solution.

APPLICABILITY In MODE 5 with RCS loops filled, this LCO requires forced circulation of the reactor coolant to remove decay heat from the core and to provide proper boron mixing. One loop of RHR provides sufficient circulation for these purposes. However, one additional RHR loop is required to be OPERABLE, or the secondary side water level of at least two SGs is required to be __ 0%

narrow range.

Operation in other MODES is covered by:

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

LCO 3.4.5, "RCS Loops - MODE 3;"

INDIAN POINT 2 B 3.4.7 - 4 Revision 1

RCS Operational LEAKAGE B 3.4.13 BASES BACKGROUND (continued)

This LCO deals with protection of the reactor coolant pressure boundary (RCPB) from degradation and the core from inadequate cooling, in addition to preventing the accident analyses radiation release assumptions from being exceeded.

The consequences of violating this LCO include the possibility of a loss of coolant accident (LOCA).

APPLICABLE SAFETY ANALYSES f r, m r7 -

LCAA&

Except for primary to secondary LEAKAGE, the safety analyses do not address operational LEAKAGE. However, other operational LEAKAGE is related to the safety analyses for LOCA because the amount of leakage can affect the probability of such an event. The safety analysis for an event resulting in steam discharge to the atmosphere assulma 60""gdopirr tozs6conddry Lg2%6Atff(1 50,pd i9,+/-acl'yf th for *s)

(P[ef.,X. /

Primary to secondary LEAKAGE is a factor in the dose releases outside containment resulting from locked rotor and steam line break (SLB) accidents.

To a lesser extent, other accidents or transients involve secondary steam release to the atmosphere, such as a steam generator tube rupture (SGTR). The leakage contaminates the secondary fluid.

In the analyses of the locked rotor and steamline break accidents the 150 gpd per steam generator lpao is the primary contributor to the doses. In the locked rotor accident'analysis the leakage is the only path by which the contaminated primary coolant can be transferred out of the reactor coolant system. Activity transferred to the secondary side during a locked rotor event is subject to partitioning as steam is released to the atmosphere, but the leakage is the main source of the secondary activity. In the steamline break analysis all activity transferred to the faulted steam generator by the leakage is released without partitioning. I Activity transferred to the intact steam generators is subject to partitioning so this leakage is relatively inconsequential. In the SGTR analysis the ruptured tube is the primary path by which the contaminated primary coolant is transferred out of the reactor coolant system. Activity transferred to the intact steam generators is much lower due to the lower leak rate and is subject to partitioning sot is.

e-is relatively inconsequential. The dose consequences resulting from these events are within the applicable limits (Ref. 3). The dose acceptance limits are defined by Regulatory Guide 1.183 (Ref. 4).

Th. 44ýt

~-for tro 5V 4 (aC(kir-,+e t~o V, A iio t', -

4vit. 'r LI r

e'r"v 1

.'0J4 A limit of 150 gpd of primary to secondary leakage per SG is established as part of the performance criteria for the SG tube surveillance program recommended in Reference 5. Monitoring and limiting primaryto secondary leakage is an important defense in depth measure for monitoring overall tube integrity during operation. SG leakage monitoring and the INDIAN POINT 2 B 3.4.13 - 2 Revision 2

RCS Operational LEAKAGE B 3.4.13 BASES LCO (continued) truer-F

1.

Primary to Secondary LEAKAGE through One SG The 150 gpd limit for primary t condary LEAKAGE' ach of the four SGs is part of the perf ance criteria for the ube surveillance program required b chnical Specificatio

..7, Steam Generator (SG) Tube S lance Program, a eference 5. SG leakage monitorin the associated lim' ows operators to safely respon to si ions in which tube in ity becomes impaired before signif nt kage or tube failure curs.

Note that p ryto secondary LEAKAGE is also co ed as identified LEA E

in accordance with Technical pecification 1.1, e finitions."

APPLICABILITY In MODES 1,2,3, and 4, the potential for RCPB LEAKAGE is greatest when the RCS is pressurized.

In MODES 5 and 6, LEAKAGE limits are not required because the reactor coolant pressure is far lower, resulting in lower stresses and reduced potentials for LEAKAGE.

LCO 3.4.14, "RCS Pressure Isolation Valve (PIV) Leakage," measures leakage through each individual PIV and can impact this LCO. Of the two PIVs in series in each isolated line, leakage measured through one PIV does not result in RCS LEAKAGE when the other is leak tight. If both valves leak and result in a loss of mass from the RCS, the loss must be included in the allowable identified LEAKAGE.

ACTIONS A.1 Anideitified LEAKAGEq identified LEAKAGE m r-tnr in excess of the LCO limits must be reJduce to within limits within

-urs. This Completion Time allows time to verify leakage rates and either identify unidentified LEAKAGE or reduce LEAKAGE to within limits before the reactor must be shut down. This action is necessary to prevent further deterioration of the RCPB.

INDIAN POINT 2 B 3.4.13 - 4 Revision 2

RCS Operational LEAKAGE B 3.4.13 BASES ACTIONS (continued)

B.1 and B.2 m 1-4 o

-ecoc,4 4e-ryLt A C16I h -t If any pressure boundary LEAKAGE exists:r if unidentified

'E-jAKAGE

'(

identified LEAKAG _. 7 mary to seeeneary LLA!Uýýcannot be reduced to within limits within-4 hours, the reactor must be brought to lower pressure conditions to reduce the severity of the LEAKAGE and its potential consequences. It should be noted that LEAKAGE past seals and gaskets is not pressure boundary LEAKAGE. The reactor must be brought to 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 .

This action reduces the LEAKAGE and also reduces the factors that tend to degrade the pressure boundary.

The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems. In MODE 5, the pressure stresses acting on the RCPB are much lower, and further deterioration is much less likely.

SURVEILLANCE SR 3.4.13.1 REQUIREMENTS Verifying RCS LEAKAGE to be within the LCO limits ensures the integrity of the RCPB is maintained. Pressure boundary LEAKAGE would at first appear as unidentified LEAKAGE and can only be positively identified by inspection.

It should be noted that LEAKAGE past seals and gaskets is not pressure boundary LEAKAGE. Unidentified LEAKAGE and identified LEAKAGE are determined by performance of an RCS water inventory balance. Prim ry to second EAKAGE is so measured b performanc, of an RC water Iinve ry balance in c junction with effluent monitorin,ithin the s condary am and feedwa systems.

/

The RCS water inventory balance must be met with the reactor at steady state operating condRtion Nors that this [T,. s-a.e'¢.

SR is not required to be performed until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after establishing steady state operation. The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months allowance. provides sufficient time to collect and process all necessary data after stable plant conditions are established.

Steady state operation is 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 is defined Ps stable RCS pressure, temperature, power level, pressurizer and makeup tank levels, makeup and letdown, and RCP seal injection and return flows.

INDIAN POINT 2 B 3.4.13 - 5 Revision 2

RCS Operational LEAKAGE B 3.4.13 BASES SURVEILLANCE REQUIREMENTS (continued)

SR 3.4.13.1 (continued)

An early warning of pressure boundary LEAKAGE or unidentified LEAKAGE is provided by the automatic systems that monitor the containment atmosphere radioactivity and the containment sump level. It should be noted that LEAKAGE past seals and gaskets is not pressure boundary LEAKAGE.

These leakage detection systems are specified in LCO 3.4.15, "RCS

.eakage Detection Instrumentation."

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

SR 3.4.13.2

'v-)

5 This S rovides the means neces ry to determine SG PERABILITY in 3, q..13 413D an opational MODE. The requir ment to demonstrate G tube integrity' acc rdance with the Steam Generator Tube S rveillance Pro m

[e phasizes the importanc of SG tube integ, even thoug this urveillance cannot be pe rmed at normal oper ting conditions.

REFERENCES

1.

10 CFR 50, Appendix A, GDC 30.

2.

Regulatory Guide 1.45, May 1973.

3.

WCAP-1 6157, "Indian Point Unit 2 Stretch Power Uprating Licensing Report," January 2004.

4.

Regulatory Guide 1.183, "Alternative Radiological Source Terms for Evaluating Design Basis Accidents at Nuclear Power Reactors," July N 90 t

na 2000.

i

~

~15// N Jý97-06,*'team C*neratorVProgram,6uide, lnes, R(.1

/

I INDIAN POINT 2 B 3.4.13 - 6 Revision 2

TSTF-449, Rev. 4 INSERT B 3.4.13 A

[OO ql4Is.v, tI

,d that primary to secondaryJEAKAGE from all steam generators (SGs) isl[op(e ga,*or)/pe*' miu$]l or increases tol[boye g pallgn p

u as a result of accident induced conditions. The LCO requirement to limit primary to secondary LEAKAGE through any one SG to less than or equal to 150 gallons per day issiighificantly)essA tilthe conditions assumed in the safety analysis.

INSERT B 3.4.13 B Lt Ji

d.

Primary to Secondary LEAKAGE Through Any One SG 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 BWO This SR verifies that pri ary to secondary LEA GE is less tha or equal to 150 gallons per day through anyone S. Satisfying the prim to secondary AKAGE limit ensures that e

operational LEAKAG performance criterion n the Steam Ge erator Program is met. If t s SR is not met, complian e with LCO 3.4.17, "S am Generator T be Integrity," should be ev uated.

The 150 gallons pe day limit is measured t room temper re as described in Refere ce 5.

The operational L AKAGE rate limit appl *s to LEAKAGE rough any one SG. If it i not practical to assi the LEAKAGE to an' dividual SG, all e primary to secondary KAGE should be cons rvatively assumed to from one SG.

The Surveill ce is modified by a N e which states at the Surveillance is no equired to be performed til 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after esta ishment of ste y state operation. For S primary to secondary EAKAGE determina n, steady state s defined as stable RCS ressure, tempera re, power level, press izer and make tank levels, makeup a letdown, and RCP seal inj tion and return flows.

The urveillance Frequency f 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months is a easonable interval to tr d primary to secondary LE GE and recognizes e importance early leakage detectio in the prevention of ac idents. The primary to econdary LEA GE is determined usi continuous process r diation monitors or radi chemical grab ampling in accordanc ith the EPRI guidelines (Ref.

1

TSTF-449, Rev. 4 INSERT B 3.4.13 D (WG4 This SR verifies that primary to sec ndary LEAKAGE is less or equal to 150 gallons per day through any one SG. Satisfying th* primary to secondary LEAKAGE limit ensures that the operational LEAKAGE performaricE rtrion in the Steam Generator Program is met. If this SR is not met, compliance with LCOI.

2,J"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 from 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 seal 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 DCEOG This SR verifies that pri ry to secondary LEA GE is less or equal to 150 gallons per y

through any one SG.

atisfying the primary t secondary LEAKAGE limit ensures tha e

operational LEAKA performance criterio in the Steam Generator Program is m. If this SR is not met, compl 'nce with LCO 3.4.18," team Generator Tube Integrity," shoul e evaluated.

The 150 gallon per day limit is meas ed at room temperature as described i eference 5.

The operatio I LEAKAGE rate limi pplies to LEAKAGE through any one

. If it is not practical t ssign the LF-AKAG o an individual SG, all the primary to s ondary LEAKAGE should beconservatively asesu d to be from one SG.

Th urveillance is modifd by a Note which states that the Surv ance is not required t e

ormed until 12 hou after establishment of steady state op ation. For RCS prima to econdary LEAKAG determination, steady state is defined stable RCS pressure temperature, ow level, pressurizer and makeup tank le Is, makeup and letdo and RCP seal injection a return flows.

The Surve ance Frequency of 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months is a reas able interval to trend pr ary to secondary LEAKA and recognizes the importance of e leakage detection in t prevention of accid ts. The primary to secondary LEAKA is determined using c tinuous process ra tion monitors or radiochemical grab s pling in accordance wi the EPRI guidelines (Ref.

INSERT B 3.4.13 E NEI 97-06, "Steam Generator Program Guidelines."

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

2

IT-STF -44. Roy.4*-]

SG Tube Integrity I.*.4.

B 3.4 REACTOR COOLANT SYSTEM (RCS)

Steam Generator (SG) Tube Integrity BASES BACKGROUND Steam generator (SG) tubes are small diameter, thin walled tubes that carry primary coolant through the primary to secondary heat exchangers.

The SG tubes have a number of important safety functions. Steam generator tubes are an integral part of the reactor coolant pressure boundary (RCPB) and, as such, are relied on to maintain the primary system's pressure and inventory. The SG tubes isolate the radioactive fission products in the primary coolant from the secondary system. In addition, as part of the RCPB, the SG tubes are unique in that they act as the heat transfer surface between the primary and secondary systems to remove heat from the primary system. This Specification addresses only the RCPB integrity function of the SG. The SG heat removal function is addressed by LCO 3.4.4, "RCS Loops - MODES 1 and 2," LCO 3.4.5, "RCS Loops - MODE 3," LCO 3.4.6, "RCS Loops - MODE 4," and LCO 3.4.7, "RCS Loops - MODE 5, Loops Filled."

SG tube integrity means that the tubes are capable of performing their intended RCPB safety function consistent with the licensing basis, including applicable regulatory requirements.

Steam generator tubing is subject to a variety of degradation mechanisms. Steam generator tubes may experience tube degradation related to corrosion phenomena, such as wastage, pitting, intergranular attack, and stress corrosion cracking, along with other mechanically induced phenomena such as denting and wear. These degradation mechanisms can impair tube integrity if they are not managed effectively.

The SG performance criteria are used to manage SG tube degradation.

Specification I.,"Steam Generator (SG) Program," requires that a program be established and implemented p ensure that SG tube integrity is maintained. Pursuant to Specification t ube integrity is maintained when the SG performance cn are met. There are three SG performance criteria: structural integrity, accident induced leakage, and operational LEAKAGE. The SG performance criteria are described in Speci ication*

Meeting the SG performance criteria provides reasonable assurance of maintaining tube integrity at normal and accident conditions.

The processes used to meet the SG performance criteria are defined by the Steam Generator Program Guidelines (Ref. 1).

-I t'Q~Il

TF M1 A 9.10

-. 4 SG Tube Integrity' BASES APPLICABLE SAFETY ANALYSES The steam generator tube rupture (SGTR) accident is the limiting design basis event for SG tubes and avoiding an SGTR is the basis for this Specification. The analysis of a SGTR event assumes a bounding primary to secondary LEAKAGE rate equal to the operational LEAKAGE rate limits in LCO 3.4.13, "RCS Operational LEAKAGE," plus the leakage rate associated with a double-ended rupture of a single tube. The accident analysis for a SGTR assumes the contaminated secondary fluid islohNbr "J1 released to the atmosphere viasafety valves-'t]

n wsc ar e*e o airyco nae A*

j.

J

_' (-

The analysis for design basis accidents and transients other than a SGTR assume the SG tubes retain their structural integrity (i.e., they are assumed not to rupture.) In these analyses, the steam discharge to the atmosp ere is based on the total primary to secondary LEAKAGE from all SGs of I

`pp mipUM or is assumed to increase tofJ 0

6o as a result of accident induced conditions. For that o not involve fuel damage, the primary coolant activity level of DOSE EQUIVALENT 1-131 is assumed to be equal to the LCO 3.4.16, "RCS Specific Activity," limits. For accidents that assume fuel damage, the primary coolant activity is a function of the amount of activity released from the damaged fuel. The dose consequences of these events are within the limits of GDC 19 (Ref. 2), 10 CFR 100 (Ref. 3) or the NRC approved licensing basis (e.g., a small fraction of these limits).

Steam generator tube integrity satisfies Criterion 2 of 10 CFR 50.36(c)(2)(ii).

LCO The LCO requires that SG tube integrity be maintained. The LCO also requires that all SG tubes that satisfy the repair criteria be plugged{wJ

[rj

]in accordance with the Steam Generator Program.

During an SG inspection, any inspected tube that satisfies the Steam Generator Program repair criteria is e or removed from service by plugging. If a tube was determined to satisfy the repair criteria but was not pluggedy r "afd the tube may still have tube integrity.

In the context of this Specification, a SG tube is defined as the entire length of the tube, including the tube walll[

ar rtrt2rrdcyýqj between the tube-to-tubesheet weld at the tube inlet and the tubeto-t tubesheet weld at the tube outlet. The tube-to-tubesheet weld is not considerea part oT me toe.

A SG tube has tube integrity when it satisfies the SG erformance criteria.

The SG performance criteria are defined in Specifica iW-R Steam Generator Program," and describe acceptable SG tube pie ormance.

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

3T.

1-111hycide A

Aj~k' I I I lov.

^.^

I ý11

-T6TF". Rev.~ 4l~

SG Tube Integrity BASES F 3. q. I' LCO (continued)

There are three SG performance criteria: structural integrity, accident induced leakage, and operational LEAKAGE. Failure to meet any one of these criteria is 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 is defined as, "The gross structural failure 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 at the ends of the degradation." Tube collapse is defined as, "For the load displacement curve for a given structure, collapse occurs at 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" is defined as "An accident loading condition other than differential pressure is considered significant when the addition of such loads in the assessment of the structural integrity performance criterion could cause a lower structural limit or limiting burst/collapse condition to be established." For tube integrity evaluations, except for circumferential degradation, axial thermal loads are classified as secondary loads. For circumferential degradation, the classification of axial thermal loads as primary or secondary loads will be evaluated on a case-by-case basis.

The division between primary and secondary classifications will be based on detailed analysis and/or testing.

Structural integrity requires that the primary membrane stress intensity in a tube not exceed the yield strength for all ASME Code,Section III, Service Level A (normal operating conditions) and Service Level B (upset or abnormal conditions) transients included in the design specification.

This includes safety factors and applicable design basis loads based on ASME Code,Section III, Subsection NB (Ref. 4) and Draft Regulatory Guide 1.121 (Ref. 5).

The accident induced leakage performance criterion ensures that the primary to secondary LEAKAGE caused by a design basis accident, other than a SGTR, is within the accident analysis assumptions. The accident analysis assumes that accident induced leakage does not exceed F[lCAm/I

{p r S,, e~tept)Or spocific tyes o deg,,adatioen atspeoific Io1atigfis//

Ihei the' NRG' has*.ppr9Qed grgratertdccidint irlduced leak~~, IThe accident induced leakage rate includes any primary to secondary LEAKAGE existing prior to the accident in addition to primary to secondary LEAKAGE induced during the accident.

PerO

)OtelO4 Peect

-i I.6 f1

".1 -3 I mina =r.

I i 8420aJ

I -Tcr-,49. Re.. 4 SG Tube Integrity BASES I(I*'Et LCO (continued)

The operational LEAKAGE performance criterion provides an observable indication of SG tube conditions during plant operation. The limit on operational LEAKAGE is contained in LCO 3.4.13, "RCS Operational LEAKAGE," and limits primary to secondary LEAKAGE through any one SG to 150 gallons per day. This limit is based on the assumption that a single crack leaking this amount would not propagate to a SGTR under the stress conditions of a LOCA or a main steam line break. If this amount of LEAKAGE is due to more than one crack, the cracks are very small, and the above assumption is conservative.

APPLICABILITY Steam generator tube integrity is challenged when the pressure differential across the tubes is large. Large differential pressures across SG tubes can only be experienced in MODE 1, 2, 3, or 4.

RCS conditions are far less challenging in MODES 5 and 6 than during MODES 1, 2, 3, and 4. In MODES 5 and 6, primary to secondary differential pressure is low, resulting in lower stresses and reduced potential for LEAKAGE.

ACTIONS The ACTIONS are modified by a Note clarifying that the Conditions may be entered independently for each SG tube. This is acceptable because the Required Actions provide appropriate compensatory actions for each affected SG tube. Complying with the Required Actions may allow for continued operation, and subsequent affected SG tubes are governed by subsequent Condition entry and application of associated Required Actions.

A.1 and A.2 L~Iy1~IJ L~,o1jaA1 e044A Condition A applies if it is discovered that one or more SG tubes examined in an inservice inspection satisfy the tube repair criteria but were not pluggedJ,T4 f]in accordance with the Steam Generator Program as required byi.b

.2 An evaluation of SG tube integrity of the affected tube(s)ust be made. Steam generator tube integrity is based on meeting the SG performance criteria described in the Steam Generator Program. The SG repair criteria define limits on SG tube degradation that allow for flaw growth between inspections while still providing assurance that the SG performance criteria will continue to be met. In order to determine if a SG tube that should have been plugged irmelaired] has tube integrity, an evaluation must be completed that monstrates that the SG performance criteria will continue to be met until the next refueling outage or SG tube inspection. The tube integrity determination is based on the estimated condition of the tube at the time the situation is discovered and the estimated growth of the degradation prior to the next SG tube inspection. If it is determined that tube integrity is not being maintained, Condition B applies.

16341ýl ee)M I

B 8.4.264 1 I Rey. X.X j -

TSTF 119. Ro~.. I SG Tube Integrity f, 3.

A. I BASES Actions (continued)

A Completion Time of 7 days is sufficient to complete the evaluation while minimizing the risk of plant operation with a SG tube that may not have tube integrity.

If the evaluation determines that the affected tube(s) have tube integrity, Required Action A.2 allows plant operation to continue until the next refueling outage or SG inspection provided the inspection interval continues to be supported by an operational assessment that reflects the affected tubes. However, the affected tube(s) must be pluggedt i'prior to entering MODE 4 following the next refueling outage or SG inspection. This Completion Time is acceptable since operation until the next inspection is supported by the operational assessment.

B.1 and B.2 If the Required Actions and associated Completion Times of Condition A are not met or if SG tube integrity is not being maintained, the reactor must be brought to 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, to reach the desired plant conditions from full power conditions in an orderly manner and without challenging plant systems.

SURVEILLANCE REQUIREMENTS SK A.A.

During shutdown periods the SGs are inspected as required by this SR and the Steam Generator Program. NEI 97-06, Steam Generator Program Guidelines (Ref. 1), and its referenced EPRI Guidelines, establish the content of the Steam Generator Program. Use of the Steam Generator Program ensures that the inspection is appropriate and consistent with accepted industry practices.

During SG inspections a condition monitoring assessment of the SG tubes is performed. The condition monitoring assessment determines the "as found" condition of the SG tubes. The purpose of the condition monitoring assessment is to ensure that the SG performance criteria have been met for the previous operating period.

VVUUM-1 B 8.4.2 I -

11 -

I

TSTF-44,

49. Rev. 4" SG Tube Integrity BASES I 1U3.1 SURVEILLANCE REQUIREMENTS (continued)

The Steam Generator Program determines the scope of the inspection and the methods used to determine whether the tubes contain flaws satisfying the tube repair criteria. Inspection scope (i.e., which tubes or areas of tubing within the SG are to be inspected) is a function of existing and potential degradation locations. The Steam Generator Program also specifies the inspection methods to be used to find potential degradation.

Inspection methods are a function of degradation morphology, non-destructive examination (NDE) technique capabilities, and inspection locations.

I fo, 3.2..i.I.

The Steam Generator Program defines the Frequency of GR...

I.

1 The Frequency is determined by the operational assessment and other limits in the SG examination guidelines (Ref. 6). The Steam Generator Program uses information on existing degradations and growth rates to determine an inspection Frequency that provides reasonable assurance that the tubing will meet the SG performance criteria at the next scheduled inspection. In addition, Specificationp o

iafis "i, prescriptive requirements concerning inspection intervals to provide added assurance that the SG performance criteria will be met between scheduled inspections.

During an SG inspection, any inspected tube that satisfies the Steam Generator Program repair criteria isil, removed from service by plugging. The tube repair criteria delineated in pecification ý5_ grei__

intended to ensure that tubes accepted for continued service satis y the SG performance criteria with allowance for error in the flaw size measurement and for future flaw growth. In addition, the tube repair criteria, in conjunction with other elements of the Steam Generator Program, ensure that the SG performance criteria will continue to be met until the next inspection of the subject tube(s). Reference 1 provides guidance for performing operational assessments to verify that the tubes remaining in service will continue to meet the SG performance criteria.

[Steam g #erator tube r airs are only erformed u ng provdvrep dr method as described' the Steam (enerator Pr; rarra

/

The Frequency of prior to entering MODE 4 following a SG inspection ensures that the Surveillance has been completed and all tubes meeting the repair criteria are pluggedl[9(ripý,ir.d] prior to subjecting the SG tubes to significant primary to secondary pressure differential.

I V V "%ý3 Z3 I Zr Is-& ý.- ý I-

I TSF49 e SG Tube Integrity 1 k-+2*I+_1 REFERENCES

1.

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

2.

10 CFR 50 Appendix A, GDC 19.

3.

10CFR100.

4.

ASME Boiler and Pressure Vessel Code,Section III, Subsection NB.

5.

Draft Regulatory Guide 1.121, "Basis for Plugging Degraded Steam Generator Tubes," August 1976.

6.

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

Facility Operating License No DPR-64 Appendix A -

Technical Specification Bases TABLE OF CONTENTS (continued)

B.3.4 B.3.4.1 B.3.4.2 B.3.4.3 B.3.4.4 B.3.4.5 B.3.4.6 B.3.4.7 B.3.4.8 B.3.4.9 B.3.4.10 B.3.4. 11 B.3.4.12 B.3.4.13 B.3.4.14 B.3.4.15 B.3.4.16 B.3.5 B.3.5.1 B.3.5.2 B.3.5.3 B.3.5.4 REACTOR COOLANT SYSTEM (RCS)

RCS Pressure, Temperature, and Flow Departure from Nucleate Boiling (DNB)

Limits RCS Minimum Temperature for Criticality RCS Pressure and Temperature (P/T) Limits RCS Loops-MODES 1 and 2 RCS Loops-MODE 3 RCS Loops-MODE 4 RCS Loops-11ODE 5, Loops Filled RCS Loops-MODE 5, Loops Not Filled Pressurizer Pressurizer Safety Valves Pressurizer Power Operated Relief Valves (PORVs)

Low Temperature Overpressure Protection (LTOP)

RCS Operational LEAKAGE RCS Pressure Isolation Valve (PIV)

Leakage RCS Leakage Detection Instrumentation RCS Specific Activity r; 3.

L1. sjet., err,,er.4-or c6& T.I7C'fI TIer11~

l EMERGENCY CORE COOLING SYSTEMS (ECCS)

Accumulators ECCS-Operating ECCS-Shutdown Refueling Water Storage Tank (RWST)

B.3.6 CONTAINMENT SYSTEMS B.3.6.1 Containment B.3.6.2 Containment Air Locks B.3.6.3 Containment Isolation Valves B.3.6.4 Containment Pressure B.3.6.5 Containment Air Temperature B.3.6.6 Containment Spray System and Containment Fan Cooler System B.3.6.7 Spray Additive System B.3.6.8 Not Used B.3.6.9 Isolation Valve Seal Water (IVSW)

System B.3.6.10 Weld Channel and Penetration Pressurization System (WC & PPS)

(continued)

I INDIAN POINT 3 B ii Revision 2

RCS Loops - MODES 1 and 2 B 3.4.4 BASES (continued)

LCO The purpose of this LCO is to require an adequate forced flow rate for core heat removal.

Flow is represented by the number of RCPs in operation for removal of heat by the SGs.

To meet safety analysis acceptance criteria for DNB, four 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 ]

a orda ce w th tV Ste~afn Gener or,9urvejlanc Pr §ram.

APPLICABILITY In MODES 1 and 2, the reactor is critical and thus has the potential to produce maximum THERMAL POWER.

Thus, to ensure that the assumptions of the accident analyses remain valid, all RCS loops are required to be OPERABLE and in operation in these MODES to prevent DNB and core damage.

The decay heat production rate is much lower than the full power heat rate.

As such, the forced circulation flow and heat sink requirements are reduced for lower, noncritical MODES as indicated by the LCOs for MODES 3, 4, and 5.

Operation in other MODES is covered by:

LCO 3.4.5, "RCS Loops-MODE 3":

LCO 3.4.6, "RCS Loops-MODE 4":

LCO 3.4.7, "RCS Loops-MODE 5, Loops Filled";

LCO 3.4.8, "RCS Loops-MODE 5, Loops Not Filled";

LCO 3.9.4, "Residual Heat Removal (RHR) and Coolant Circulation-High Water Level" (MODE 6): and LCO 3.9.5, "Residual Heat Removal (RHR) and Coolant Circulation-Low Water Level" (MODE 6).

ACTIONS A.1 If the requirements of the LCO are not met, the Required Action is to reduce power and bring the plant to MODE 3.

This lowers power level and thus reduces the core heat removal needs and minimizes the possibility of violating DNB limits.

(continued)

INDIAN POINT 3 B 3.4.4 - 3 Revision 0

RCS Loops -MODE 3

B 3.4.5 BASES LCO (continued) therefore, only one RCS loop in operation is necessary to ensure removal of decay heat from the core and homogenous boron concentration throughout the RCS.

An additional RCS loop is required to be OPERABLE to ensure redundant decay heat removal capability.

The Note permits all RCPs to be not be in operation for 5 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months per 8 hour9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months period.

The purpose of the Note is to permit performance of required tests or maintenance that can only be performed with all reactor coolant pumps not in operation.

The 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months time period specified is acceptable because operating experience has shown that boron stratification is not a problem during this short period with no forced flow.

Utilization of the Note is permitted provided the following conditions are met, along with any other conditions imposed by test or maintenance procedures:

a.

No operations are permitted that would dilute the RCS boron concentration, thereby maintaining the margin to criticality.

Boron reduction is prohibited because a uniform concentration distribution throughout the RCS cannot be ensured when in natural circulation; and

b.

Core outlet temperature is maintained at least 10OF below saturation temperature, so that no vapor bubble may form and possibly cause a natural circulation flow obstruction.

An OPERABLE RCS loop consists of one OPERABLE RCP and one OPERABLE SG jit ccor~anc" ith iH Ste!

Gener or T: Surv 1 cewogram.

which has the minimum water level specified in SR 3.4.b.2.

An RGP is OPERABLE if it is capable of being powered and is able to provide forced flow if required.

APPLICABILITY In MODE 3, this LCO ensures forced circulation of the reactor coolant to remove decay heat from the core and to provide proper boron mixing.

The most stringent condition of the LCO, that is, two RCS loops OPERABLE and two RCS loops in operation, applies to MODE 3 with RTBs in the closed position.

The least stringent (continued)

INDIAN POINT 3 B 3.4.5-3 Revision 0

RCS Loops-MODE 4 B 3.4.6 BASES LCO (continued)

Note 1 permits all RCPs and RHR pumps to not be in operation for # 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months per 8 hour9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months period.

The purpose of the Note is to permit performance of required tests or maintenance that can only be performed with no forced circulation.

The 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months time period is acceptable because operating experience has shown that boron stratification is not a problem during this short period with no forced flow.

Utilization of Note 1 is permitted provided the following conditions are met along with any other conditions imposed by test or maintenance procedures:

a.

No operations are permitted that would dilute the RCS boron concentration, therefore maintaining the margin to criticality.

Boron reduction is prohibited because a uniform concentration distribution throughout the RCS cannot be ensured when in natural circulation; and

b.

Core outlet temperature is maintained at least 10 OF below saturation temperature, so that no vapor bubble may form and possibly cause a natural circulation flow obstruction.

Note 2 requires that the reactor coolant pump starting requirements of LCO 3.4.12, Low Temperature Overpressure Protection (LTOP),

must be met before the start of an RCP with any RCS cold leg temperature less than or equal to the LTOP arming temperature.

This restraint is to prevent a low temperature overpressure event due to a thermal transient when an RCP is started.

An OPERABLE RCS loop comprises an OPERABLE RCP and an OPERABLE a'c Irdpfce

"{h ffie Stgdm G era r/TbeXurveXlar/e/rgpra.

has the minimum water level specitied in SR 3.4.6.2.

SGw whi ch Similarly for the RHR System, an OPERABLE RHR loop comprises an OPERABLE RHR pump capable of providing forced flow to an OPERABLE RHR heat exchanger.

RCPs and RHR pumps are OPERABLE if they are capable of being powered and are able to provide forced flow if required.

(continued)

INDIAN POINT 3 B 3.4.6-3 Revision 1

RCS Loops-MODE 5, Loops Filled B 3.4.7 BASES LCO (continued)

Note 3 requires that the reactor coolant pump starting requirements of LCO 3.4.12, Low Temperature Overpressure Protection (LTOP),

must be met before the start of a reactor coolant pump (RCP) with an RCS cold leg temperature less than the LTOP arming temperature specified in LCO 3.4.12, Low Temperature Overpressure Protection (LTOP).

This restriction is to prevent a low temperature overpressure event due to a thermal transient when an RCP is started.

Note 4 provides for an orderly transition from MODE 5 to MODE 4 during a planned heatup by permitting removal of RHR loops from operation when at least one RCS loop is in operation.

This Note provides for the transition to MODE 4 where an RCS loop is permitted to be in operation and replaces the RCS circulation function provided by the RHR loops.

RHR pumps are OPERABLE if they are capable of being powered and are able to provide flow if required. 4i§P SG can perform as a heat sink with forced flow or naturalcFirculation when it has an adequate water level and is OPERABLE 51eco/an96 w hhe,team I I Cdner to Tu6 S rvell ce/Pro,4raj.,'

APPLICABILITY In MODE 5 with RCS loops filled, this LCO requires forced circulation of the reactor coolant to remove decay heat from the core and to provide proper boron mixing.

One loop of RHR provides sufficient circulation for these purposes.

However, one additional RHR loop is required to be OPERABLE, or the secondary side water level of at least two SGs is required to be ? 71% wide range.

Loops filled is based on the ability to use the SGs as a backup means of decay heat removal.

The RCS loops are considered filled provided that pressurizer level has been maintained D10%.

The loops are also considered filled following the completion of filling and venting the RCS.

The ability to pressurize the RCS to

_>100 psig and to control pressure must be established to take credit for use of the SGs as backup decay heat removal.

This is to prevent flashing and void formation at the top of the SG tubes (continued)

INDIAN POINT 3 B 3.4.7-4 Revision 0

RCS Operational LEAKAGE B 3.4.13 BASES APPLICABLE SAFETY ANALYSES 1~bTI~er Except for primary to secondary LEAKAGE, the safety analyses do not address operational LEAKAGE.

However, other operational LEAKAGE is related to the safety analyses for LOCA; the amount of leakage can affect the probability of such an event.

The safety analysis for events resulting in steam discharge to the atmosphere assumes ar/n I o*p*Yarf o fconday LA*Gfro* 0. 1 go* to 7UO gp-m 7s-tbi/i t ialI Primary to secondary LEAKAGE is a factor in the dose releases outside containment resulting from a steam line break (SLB) accident.

To a lesser extent, other accidents or transients involve secondary steam release to the atmosphere, such as a steam generator tube rupture (SGTR).

The leakage contaminates the secondary fluid.

The FSAR (Ref. 2) analysis for SGTR assumes the contaminated secondary fluid is released via safety valves and atmospheric dump valves.

The RJgpm primary to secondary LEAKAGE is relatively inconsequential.

The SLB is more limiting for site radiationreleases.

The safety analysis for the SLB accident assumes[ý lprimary to secondary

4 LEAKAGEras an initial condition.

The dose consequences resulting from 4-h' A4S d

the SLB accident are well within the limits defined in 10 CFR 50.67 and the staff approved licensing basis (i.e., a small fraction of these limits).

I The RCS operational LEAKAGE satisfies Criterion 2 of 10 CFR 50.36.

LCO RCS operational LEAKAGE shall be limited to:

a.

Pressure Boundary LEAKAGE No pressure boundary LEAKAGE is allowed, being indicative of material deterioration.

LEAKAGE of this type is unacceptable as the leak itself could cause further deterioration, resulting (continued)

INDIAN POINT 3 B.3.4.13 - 2 Revision 3

RCS Operational LEAKAGE B 3.4.13 BASES LCO (continued) in higher LEAKAGE.

Violation of this LCO could result in continued degradation of the RCPB LEAKAGE past seals and gaskets is not pressure boundary LEAKAGE.

b.

Unidentified LEAKAGE One gallon per minute (gpm) of unidentified LEAKAGE is allowed as a reasonable minimum detectable amount and is consistent with the capability of the equipment required by LCO 3.4.15, RCS Leakage Detection Instrumentation.

Violation of this LCO could result in continued degradation of the RCPB, if the LEAKAGE is from the pressure boundary.

c.

Identified LEAKAGE Up to 10 gpm of identified LEAKAGE is considered allowable because LEAKAGE is from known sources that do not interfere with detection of unidentified LEAKAGE and is well within the capability of the RCS Makeup System.

Identified LEAKAGE includes LEAKAGE to the containment from specifically known and located sources, but does not include pressure boundary LEAKAGE, the leakage into closed systems or controlled reactor coolant pump (RCP) seal leakoff (a normal function not considered LEAKAGE).

Violation of this LCO could result in continued degradation of a component or system.

d.

rimar to Secon arv LEAKAi throu h A1 Steau /Generat s (SGs)

Tot primary o secondiy LEAKAG amounti to 1 g (1440 d) th ough all Gs produc s accepta e offsi e doses In the SL cident a lysis.

Volation o this L could ceed th ffsite se limits or this cident. Primary ot secon ary LEAKAGE ust be i luded in e tota allowab limit f r identi ed LEAKA.

(continued)

INDIAN POINT 3 B.3.4.13 - 3 Revision 3

RCS Operational LEAKAGE B 3.4.13 BASES LCO

e.

rimar/to Secon rv LEAKAG/throuah An One SG (continued)

Th 432 gall s per day 0.3 gpm) ii It on o SG is sed the assu tion tha a single cr ck leaki g this a ount uld

{

-L *

/

not propa te to a R under th stress ondition of a CA or a main eam line pture.

If eaked t ough ma crac, the crack are very all, and t above sumptio Is co ervative.

APPLICABILITY In MODES 1, 2, 3, and 4, the potential for RCPB LEAKAGE is greatest when the RCS is pressurized.

In MODES 5 and 6, LEAKAGE limits are not required because the reactor coolant pressure is far lower, resulting in lower stresses and reduced potentials for LEAKAGE.

Leakage past PIVs or other leakage into closed systems is that leakage that can be accounted for and contained by a system not directly connected to the atmosphere.

Leakage past PIVs or other leakage into closed systems is not included in the limits for either identified or unidentified LEAKAGE but PIV leakage must be within the limits specified for PIVs in LCO 3.4.14, "RCS Pressure Isolation Valves (PIV)."

Leakage past PIVs or other leakage into closed systems is quantified before being exempted from the limits for identified LEAKAGE.

ACTIONS A.

or Unidentified LEAKAG identified LEAKAGE iry o

onryl in excess of-he LCO limits must be reduced to within limits within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months .

This Completion Time allows time to verify leakage rates and either identify unidentified LEAKAGE or reduce LEAKAGE to within limits before the reactor must be shut down.

This action is necessary to prevent further deterioration of the RCPB.

B.

a d0.2(

p r, *M V rr + 0 i -e,9 #,4 B.1 and B.2 I

E I i

~

a4 P.41, I If any pressure boundary LEAKAGE exists, or if unidentified r

identified LEAKAGE, -o rimo to s5co ry I.AKAGE cannot be (continued)

INDIAN POINT 3 B.3.4.13 - 4 Revision 3

RCS Operational LEAKAGE B 3.4.13 BASES ACTIONS B.1 and B.2 (continued) reduced to within limits within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months , the reactor must be brought to lower pressure conditions to reduce the severity of the LEAKAGE and its potential consequences.

It should be noted that LEAKAGE past seals and gaskets is not pressure boundary LEAKAGE.

The reactor must be brought to 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 .

This action reduces the LEAKAGE and also reduces the factors that tend to degrade the pressure boundary.

The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.

In MODE 5, the pressure stresses acting on the RCPB are much lower, and further deterioration is much less likely.

SURVEILLANCE REQUIREMENTS SR 3.4.13.1 Verifying RCS LEAKAGE to be within the LCO limits ensures the integrity of the RCPB is maintained.

Pressure boundary LEAKAGE would at first appear as unidentified LEAKAGE and can only be positively identified by inspection.

It should be noted that LEAKAGE past seals and gaskets is not pressure boundary LEAKAGE.

Unidentified LEAKAGE and identified LEAKAGE are determined by performance of an RCS water inventory balance. I Pr ary tg/secondary LEAKAGE is also meas red by' performate of RCSwater Ynventor bal an* in cojuncti with elueD% moni bring ithin/he sec dary s,Jeam ad blowdo syst The RCS water inventory balance must be met with the reactor at steady state operating conditions and near operating pressure. ATherefore, this SR is not required to be performed in MODES 3 and 4-until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months of steady state operation near operating pressure have been established.

(continued)

INDIAN POINT 3 B.3.4.13 - 5 Revision 3

RCS Operational LEAKAGE B 3.4.13 BASES SURVEILLANCE REQUIREMENTS SR 3.4.13.1 (continued)

Steady state operation is required to perform a proper inventory balance; calculations during maneuvering are not useful and a Note requires the Surveillance to be met when steady state is established.

For RCS operational LEAKAGE determination by water inventory balance, steady state is defined as stable RCS pressure, temperature, power level, pressurizer and makeup tank levels, makeup and letdown, and RCP seal injection and return flows.

An early warning of pressure boundary LEAKAGE or unidentified LEAKAGE is provided by the systems that monitor the containment atmosphere radioactivity and the operation of the containment sump pump.

These leakage detection systems are specified in LCO 3.4.15, "RCS Leakage Detection Instrumentation." It should be noted that LEAKAGE past seals and gaskets, measured leakage past PIVs, and other leakage into closed systems is not pressure boundary LEAKAGE.

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

A Note under the Frequency column states that this SR is required to be performed during steady state operation.

SR 3.4.13.2 This S provides he means ecessary to determin SG OPERA LITY i an oper *ional MO The r uirement to emonstra SG tube integrty in G 3 j,.I3*-

acc rdance wh the St Generator ube Surv llance Pr gram V

)06) e hasizes e import ce of SG t e integri

, even t ough t s

Vurveill /ce cannot /e performed t normal perating onditi ns.

REFERENCES

1.

10 CFR 50, Appendix A, GDC 30.

2.

FSAR, Section 14.

1f 70;;ý-o 3 1-13 r I INDIAN POINT 3 B.3.4.13 - 6 Revision 3

TSTF-449, Rev. 4 INSERT B 3.4.13 A that primary to secondary LEAKAGE from all steam generators (SGs) is 1ýne gallon per minute or increases to one gallon per minutdtas a result of accident induced co-hditions. The LCO U

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

d.

Primary to Secondary LEAKAGE Through Any One SG 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.n 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 (BWO This SR verifies that pri ary to secondary LEA GE is less tha or equal to 150 gallons per day through any one S. Satisfying the prim to secondary KAGE limit ensures that e operational LEAKAG performance criterion n the Steam Ge rator Program is met. If t SR is not met, complian e with LCO 3.4.17, "S am Generator Tbe Integrity,3 should be ev uated.

The 150 gallons pe day limit is measured t room temper re as described in Refere ce 5.

The operational L KAGE rate limit appl s to LEAKAGE rough any one SG. If it i not practical to assig the LEAKAGE to an *dividual SG, all e primary to secondary KAGE should be cons rvatively assumed to from one SG.

The Surveill ce is modified by a N e which states at the Surveillance is no equired to be performed til 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after estaa ishment of ste y state operation. For S primary to secondary/EAKAGE determinati n, steady state' defined as stable RCS ressure, tempera re, power level, presstizer and make tank levels, makeup a letdown, and RCP seal in, ion and return flows.

The urveillance Frequency f 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months is a easonable interval to tr d primary to secondary L

GE and recognizes e importance early leakage detectio in the prevention of ac idents. The primary to condary LEA GE is determined usi continuous process r diation monitors or radi hemical grab ampling in accordanc ith the EPRI guidelines (Ref.

I

13,tY-44J, Key. 4 INSERT B 3.4.13 Dpi(-iq This SR verifies that primary to secondary LEAKAGE is less or equal to 150 gallons per day through any one SG. Satisfying the primary to secondary LEAKAGE limit ensures that the operational LEAKAGE performa cri.__

non in the Steam Generator Program is met. If this SR is not met, compliance with LCO..,

"Steam Generator Tube lntegrity, 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 from 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 seal 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 D (CEOG This SR verifies that pri ryto secondary LEA GE is less or equal to 150 gallons per y

through any one SG.

atisfying the primary t econdary LEAKAGE limit ensures tha e

operational LEAKA performance criterol in the Steam Generator Program Is mr. If this SR is not met, compl*nce with LCO 3.4.18,," team Generator Tube Integrity, shoul evaluated.

The 150 gallon per day limit Is meas at room temperature as described i eference 5.

The operatio I LEAKAGE rate lim, pplies to LEAKAGE through any one

. If it is not practical t ssign the LEAKAG an individual SG, all the primary to s 0ndary LEAKAGE should conservatively assu ed to be from one SG.

Th urvellance is modif by a Note which states that the Surv, Iance is not required 1rmed until 12 hou after establishment of steady state op ation. For RCS prima to econdary LEAKAG etermination, steady state is defined stable RCS pressure temperature, pow level, pressurizer and makeup tank e Is, makeup and letdo

, and RCP seal injection a return flows.

The Surv ance Frequency of 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months is a reas able interval to trend p ary to secondary L. EtKA and recognizes the importance of e leakage detection in t prevention of accidl ts. The primary to secondary LEAKA is determined using c tinuous process rra tin monitors or radiochemnical grab s pling in accordance wi the EPRI guidelines (Ref.

INSERT B 3.4.13 E NEI 97-06, "Steam Generator Program Guidelines."

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

2

SG Tube Integrity B 3.4 REACTOR COOLANT SYSTEM (RCS)

-4 j Steam Generator (SG) Tube Integrity BASES BACKGROUND Steam generator (SG) tubes are small diameter, thin walled tubes that carry primary coolant through the primary to secondary heat exchangers.

The SG tubes have a number of important safety functions. Steam generator tubes are an integral part of the reactor coolant pressure boundary (RCPB) and, as such, are relied on to maintain the primary system's pressure and inventory. The SG tubes isolate the radioactive fission products in the primary coolant from the secondary system. In addition, as part of the RCPB, the SG tubes are unique in that they act as the heat transfer surface between the primary and secondary systems to remove heat from the primary system. This Specification addresses only the RCPB integrity function of the SG. The SG heat removal function is addressed by LCO 3.4.4, "RCS Loops - MODES 1 and 2," LCO 3.4.5, "RCS Loops - MODE 3," LCO 3.4.6, "RCS Loops - MODE 4," and LCO 3.4.7, "RCS Loops - MODE 5, Loops Filled."

SG tube integrity means that the tubes are capable of performing their intended RCPB safety function consistent with the licensing basis, including applicable regulatory requirements.

Steam generator tubing is subject to a variety of degradation mechanisms. Steam generator tubes may experience tube degradation related to corrosion phenomena, such as wastage, pitting, intergranular attack, and stress corrosion cracking, along with other mechanically induced phenomena such as denting and wear. These degradation mechanisms can impair tube integrity if they are not managed effectively.

The SG performance criteria are used to manage SG tube degradation.

I.

Specification(i "Steam Generator (SG) Program," requires that a program be established and implemented to ensure that SG tube integri is maintained. Pursuant to Specification ube integrity is 5'

maintained when the SG performance c are met. There are three SG performance criteria: structural integrity, accident induced leakage, and operational LEAKAGE. The SG performance criteria are described in Seciiatito Meeting the SG performance criteria provides reasonable assurance of maintaining tube integrity at normal and accident conditions.

The processes used to meet the SG performance criteria are defined by the Steam Generator Program Guidelines (Ref. 1).

-I ~

Po;0t3 I

I 4ST1_A0.

Rev:. 4 SG Tube Integrity, BASES 183.i; I APPLICABLE SAFETY ANALYSES The steam generator tube rupture (SGTR) accident is the limiting design basis event for SG tubes and avoiding an SGTR is the basis for this Specification. The analysis of a SGTR event assumes a bounding primary to secondary LEAKAGE rate equal to the operational LEAKAGE rate limits in LCO 3.4.13, "RCS Operational LEAKAGE,* plus the leakage rate associated with a double-ended rupture of a single tube. The accident analysis for a SGTR assumes the contaminated seconda fluid is [oRlyAb*,flj released to the atmosphere via safety valves

(__-1 L'F or ph'ret-P.

The analysis for design basis accidents and transients other than a SGTR assume the SG tubes retain their structural Integrity (i.e., they are assumed not to rupture.) In these analyses, the steam discharge to the atmosphere is based on the total primary to secondary LEAKAGE from all SGs oi1 gallon per minut.lor is assumed to increase toll gallon per minuteas a result of accident induced conditions. For accidents that do not involve fuel damage, the primary coolant activity level of DOSE EQUIVALENT 1-131 is assumed to be equal to the LCO 3.4.16, IRCS Specific Activity," limits. For accidents that assume fuel damage, the primary coolant activity Is a function of the amount of activity released from the damaged fuel. The dose consequences of these events are within the limits of GDC 19 (Ref. 2), 10 CFR 100 (Ref. 3) or the NRC approved licensing basis (e.g., a small fraction of these limits).

Steam generator tube integrity satisfies Criterion 2 of 10 CFR 50.36(c)(2)(ii).

LCO The LCO requires that SG tube integrity be maintained. The LCO also requires that all SG tubes that satisfy the repair criteria be pluggedf in accordance with the Steam Generator Program.

During an SG inspection, any inspected tube that satisfies the Steam Generator Program repair criteria is *eremoved from service by plugging. If a tube was determined to satisfy the" repair criteria but was not plugged Wr ypýUrod] the tube may still have tube integrity.

In the context of this Specification, a SG tube is defined as the entire length of the tube, including the tube wall [n;l aro r 0 a

t it, between the tube-to-tubesheet weld at the tube inlet and the tube-to-tubesheet weld at the tube outlet The tube-to-tubesheet weld is not considered part of itre utube.

A SG tube has tube integrity when it satisfies the SG rformance criteria.

The SG performance criteria are defined in Specific'Gaa t

"Steam Generator Program," and describe acceptable SG tube pe ormance.

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

18~~

3. tI I-.

4 0Y1A P0.

4 13o 4/1'.

STZWTF 9 Rev P*;. 4 SG Tube Integrity LO 3.1.

BASES LCO (continued)

There are three SG performance criteria: structural integrity, accident induced leakage, and operational LEAKAGE. Failure to meet any one of these criteria is 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 is defined as,

'The gross structural failure 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 at the ends of the degradation." Tube collapse is defined as, "For the load displacement curve for a given structure, collapse occurs at 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' is defined as "An accident loading condition other than differential pressure is considered significant when the addition of such loads in the assessment of the structural integrity performance criterion could cause a lower structural limit or limiting burst/collapse condition to be established." For tube integrity evaluations, except for circumferential degradation, axial thermal loads are classified as secondary loads. For circumferential degradation, the classification of axial thermal loads as primary or secondary loads will be evaluated on a case-by-case basis.

The division between primary and secondary classifications will be based on detailed analysis and/or testing.

Structural integrity requires that the primary membrane stress intensity in a tube not exceed the yield strength for all ASME Code,Section III, Service Level A (normal operating conditions) and Service Level B (upset or abnormal conditions) transients included in the design specification.

This includes safety factors and applicable design basis loads based on ASME Code,Section III, Subsection NB (Ref. 4) and Draft Regulatory Guide 1.121 (Ref. 5).

The accident induced leakage performance criterion ensures that the primary to secondary LEAKAGE caused by a design basis accident, other than a SGTR, is within the accident analysis assumptions. The accident analysis assumes that accident induced leakage does not _exceed [1 rnm/

Vp,'r S

, e x.ept~or spe i c *j e

fd gadati,' a/ p fic lo 'ak s /

/

I h thNaG has*.pprg~ed grg.ater~dcidg/nt ir uce leal~e ' The acciden inauced leakage rate includes any primary to secondary LEAKAGE existing prior to the accident in addition to primary to secondary LEAKAGE induced during the accident.

0.3jfln PO-SI-,o toM.o 1e~a1e.

S "t, 17 Lý-

B 8.4.20 3-1 I WQQ SIR R

I T-449. R 4

SG Tube Integrity BASES I""i2EJ LCO (continued)

The operational LEAKAGE performance criterion provides an observable indication of SG tube conditions during plant operation. The limit on operational LEAKAGE is contained in LCO 3.4.13, "RCS Operational LEAKAGE," and limits primary to secondary LEAKAGE through any one SG to 150 gallons per day. This limit is based on the assumption that a single crack leaking this amount would not propagate to a SGTR under the stress conditions of a LOCA or a main steam line break. If this amount of LEAKAGE is due to more than one crack, the cracks are very small, and the above assumption is conservative.

APPLICABILITY Steam generator tube integrity is challenged when the pressure differential across the tubes is large. Large differential pressures across SG tubes can only be experienced in MODE 1, 2, 3, or 4.

RCS conditions are far less challenging in MODES 5 and 6 than during MODES 1, 2, 3, and 4. In MODES 5 and 6, primary to secondary differential pressure is low, resulting in lower stresses and reduced potential for LEAKAGE.

ACTIONS The ACTIONS are modified by a Note clarifying that the Conditions may be entered independently for each SG tube. This is acceptable because the Required Actions provide appropriate compensatory actions for each affected SG tube. Complying with the Required Actions may allow for continued operation, and subsequent affected SG tubes are governed by subsequent Condition entry and application of associated Required Actions.

A.1 and A.2 Condition A applies if it is discovered that one or more SG tubes examined in an inservice inspection satisfy the tube repair criteria but were not plugged r!'r*

in accordance with the Steam Generator Program as required Dy 5

.4.20.2. An evaluation of SG tube integrity of the affected tube(s) must be made. Steam generator tube integrity is based on meeting the SG performance criteria described in the Steam Generator Program. The SG repair criteria define limits on SG tube degradation that allow for flaw growth between inspections while still providing assurance that the SG performance criteria will continue to be met. In order to determine if a SG tube that should have been plugged aI has tube integrity, an evaluation must be completed that

'demonstrates that the SG performance criteria will continue to be met until the next refueling outage or SG tube inspection. The tube integrity determination is based on the estimated condition of the tube at the time the situation is discovered and the estimated growth of the degradation prior to the next SG tube inspection. If it is determined that tube integrity is not being maintained, Condition B applies.

L, i J:YAýý,q &--14 J-1 L 3..h-4

TI T. 1-9. Re.v. 4 SG Tube Integrity B "3.

fi'7' BASES Actions (continued)

A Completion Time of 7 days is sufficient to complete the evaluation while minimizing the risk of plant operation with a SG tube that may not have tube integrity.

If the evaluation determines that the affected tube(s) have tube integrity, Required Action A.2 allows plant operation to continue until the next refueling outage or SG inspection provided the inspection interval continues to be supported by an operational assessment that reflects the affected tubes. However, the affected tube(s) must be plugged[.

reeprior to entering MODE 4 following the next refueling outage or SG inspection. This Completion Time is acceptable since operation until the next inspection is supported by the operational assessment.

B.1 and B.2 If the Required Actions and associated Completion Times of Condition A are not met or if SG tube integrity is not being maintained, the reactor must be brought to 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, to reach the desired plant conditions from full power conditions in an orderly manner and without challenging plant systems.

SURVEILLANCE REQUIREMENTS During shutdown periods the SGs are inspected as required by this SR and the Steam Generator Program. NEI 97-06, Steam Generator Program Guidelines (Ref. 1), and its referenced EPRI Guidelines, establish the content of the Steam Generator Program. Use of the Steam Generator Program ensures that the inspection is appropriate and consistent with accepted industry practices.

During SG inspections a condition monitoring assessment of the SG tubes is performed. The condition monitoring assessment determines the "as found" condition of the SG tubes. The purpose of the condition monitoring assessment is to ensure that the SG performance criteria have been met for the previous operating period.

R Q. 4. OE).&

I ý %0 ý I

I STT-449.

. 4R SG Tube Integrity BASES II. iL 2Zj SURVEILLANCE REQUIREMENTS (continued)

The Steam Generator Program determines the scope of the inspection and the methods used to determine whether the tubes contain flaws satisfying the tube repair criteria. Inspection scope (i.e., which tubes or areas of tubing within the SG are to be inspected) is a function of existing and potential degradation locations. The Steam Generator Program also specifies the inspection methods to be used to find potential degradation.

Inspection methods are a function of degradation morphology, non-destructive examination (NDE) technique capabilities, and inspection locations.

I y

,at3. " 11.

1 1.

The Steam Generator Program defines the Frequency of,,

M.4.2A.I.

J_

The Frequency is determined by the operational assessment and other limits in the SG examination guidelines (Ref. 6). The Steam Generator Program uses information on existing degradations and growth rates to determine an inspection Frequency that provides reasonable assurance that the tubing will meet the SG performance criteria at the next scheduled inspection. In addition, Specification5 n.ains

'iff.4 prescriptive requirements concerning inspection intervals to provide added assurance that the SG performance criteria will be met between scheduled inspections.

During an SG inspection, any inspected tube that satisfies the Steam Generator Program repair criteria is o] removed from service by plugging. The tube repair criteria delineated in Sr)ecification re intended to ensure that tubes accepted for continued service satisFy tFe SG performance criteria with allowance for error in the flaw size measurement and for future flaw growth. In addition, the tube repair criteria, in conjunction with other elements of the Steam Generator Program, ensure that the SG performance criteria will continue to be met until the next inspection of the subject tube(s). Reference 1 provides guidance for performing operational assessments to verify that the tubes remaining in service will continue to meet the SG performance criteria.

I [Steam g erator tube r airs are only erformed u ng provd"rep r method as describedJf the Steam 53'enerator Prp rar The Frequency of prior to entering MODE 4 following a SG inspection ensures that the Surveillance has been mpleted and all tubes meeting the repair criteria are pluggedr Oep1ir~d]iprior to subjecting the SG tubes to significant primary to secondary pressure differential.

-rvk V V I

Rev.X.

SG Tube Integrity REFERENCES

1.

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

2.

10 CFR 50 Appendix A, GDC 19.

3.

10CFR100.

4.

ASME Boiler and Pressure Vessel Code,Section III, Subsection NB.

5.

Draft Regulatory Guide 1.121, "Basis for Plugging Degraded Steam Generator Tubes," August 1976.

6.

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

B 8.4.i4:R

ATTACHMENT IV TO NL-06-063 ENTERGY COMMITMENT FOR PROPOSED CHANGES REGARDING STEAM GENERATOR TUBE INTEGRITY, TSTF-449 ENTERGY NUCLEAR OPERATIONS, INC.

INDIAN POINT NUCLEAR GENERATING UNITS NO. 2 and 3 DOCKET NO. 50-247 and 50-286

NL-06-063 Dockets 50-247 and 50-286 Attachment IV Page 1 of 1 COMMITMENT REGARDING PROPOSED LICENSE AMENDMENT REQUEST REGARDING STEAM GENERATOR TUBE INTEGRITY ID Commitment Description Due Date NL-06-063-A ENO will administratively maintain the Indian Upon implementation Point Unit 2 TS primary-to-secondary leakage of approved license limit at 75 gpd through any one Steam amendment Generator.

I I

v t e Letter Sequence Request
TAC:MD0083, Steam Generator Tube Integrity, Delete Fire Protection Program Implementation from Administrative Controls, TSTF-44 (Approved, Closed) TAC:MD0084, Steam Generator Tube Integrity, Delete Fire Protection Program Implementation from Administrative Controls, TSTF-44 (Approved, Closed)
Initiation Request, Request Acceptance... Administration Questions 12 July 2006 Answers 30 August 2006 Results Approval, Approval Other: ML070530178
MONTHYEAR2006-08-30 [Table View]

ML061590405

Text

SUBJECT:

References:

Dear Sir or Madam:

1.0 INTRODUCTION

2.0 DESCRIPTION

3.0 BACKGROUND

5.0 TECHNICAL ANALYSIS

6.0 REGULATORY ANALYSIS

10.0 REFERENCES

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