Text

License Amendment Request #264, Revision 0, Application to Modify Improved Technical Specifications Regarding Steam Generator Tube Integrity
	ML061500062
Person / Time
Site:	Crystal River
Issue date:	05/25/2006
From:	Young D; Progress Energy Co
To:	; Document Control Desk, Office of Nuclear Reactor Regulation
References
	3F0506-03
	Download: ML061500062 (82)
	v • d • e

c" Progress Energy Crystal River Nuclear Plant Docket No. 50-302 Operating License No. DPR-72 Ref: 10 CFR 50.90 May 25, 2006 3F0506-03 U.S. Nuclear Regulatory Commission Attn: Document Control Desk Washington, DC 20555-0001

Subject:

Crystal River Unit 3 - License Amendment Request #264, Revision 0 Application to Modify Improved Technical Specifications Regarding Steam Generator Tube Integrity

References:

1. NRC Generic Letter 2006-01 dated January 20, 2006, "Steam Generator Tube Integrity and Associated Technical Specifications"

2. Crystal River Unit 3 to NRC Letter dated February 13, 2006, "Crystal River Unit 3 Day Response to NRC Generic Letter 2006-01, "Steam Generator Tube Integrity and Associated Technical Specifications"

Dear Sir:

In accordance with the provisions of 10 CFR 50.90, Florida Power Corporation (FPC), doing business as Progress Energy Florida, Inc. (PEF), hereby submits License Amendment Request

264, Revision 0. The proposed amendment would revise the Crystal River Unit 3 (CR-3)

Improved Technical Specification (ITS) requirements related to steam generator tube integrity.

This submittal 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 ITS improvement was announced in the Federal Register on May 6, 2005 (70 FR 24126) as part of the consolidated line item improvement process (CLIIP).

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

Attachment B provides the existing ITS pages marked-up to show the proposed change, and Attachment C provides those same changes presented more formally with revision bars.

Attachments D and E provide similar formats for the related Bases sections.

PEF requests approval of the proposed license amendment by September 30, 2006, with the amendment to be implemented within ninety days of issuance.

In accordance with 10 CFR 50.91, a copy of this application with enclosures is being provided to the designated Florida State Official.

Progress Energy Florida, Inc.

Crystal River Nuclear Plant 15760 W. Powerline Street Crystal River, FL 34428

U.S. Nuclear Regulatory Commission 3F0506-03 Page 2 of 3 This letter establishes no new regulatory commitments.

The CR-3 Plant Nuclear Safety Committee has reviewed this request and recommended it for approval.

If you have any questions regarding this submittal, please contact Mr. Paul Infanger, Supervisor, Licensing and Regulatory Programs at (352) 563-4796.

Sincerely, Dale E. Young Vice President Crystal River Nuclear Plant DEY/dar Attachments: A. Description and Assessment B. Proposed Improved Technical Specification Changes (Mark-up)

C. Proposed Improved Technical Specification Changes (Revision Bar Format)

D. Proposed Improved Technical Specification Bases Pages (Mark-up)

E. Proposed Improved Technical Specification Bases Pages (Revision Bar Format) xc: NRR Project Manager Regional Administrator, Region II Senior Resident Inspector State Contact

U.S. Nuclear Regulatory Commission 3F0506-03 Page 3 of 3 STATE OF FLORIDA COUNTY OF CITRUS Dale E. Young states that he is the Vice President, Crystal River Nuclear Plant for Florida Power Corporation, doing business as Progress Energy Florida, Inc.; that he is authorized on the part of said company to sign and file with the Nuclear Regulatory Commission the information attached hereto; and that all such statements made and matters set forth therein are true and correct to the best of his knowledge, information, and belief.

ý04ýzlý Dale E. Young 6ý7 Vice President Crystal River Nuclear Plant The foregoing document was acknowledged before me this 125 +-S day of 2006, by Dale E. Young.

Signature of Notary Public.'

State of Florida .,ICOtJSSIONM#0408 1A II

.X"IRES:MJy.W ftnW4WNck~vk*mtuum II (Print, type, or stamp Commissioned Name of Notary Public)

Personally Produced Known %/___ -OR- Identification

PROGRESS ENERGY FLORIDA, INC.

CRYSTAL RIVER UNIT 3 DOCKET NUMBER 50-302 / LICENSE NUMBER DPR-72 LICENSE AMENDMENT REQUEST #264, REVISION 0 Application to Modify Improved Technical Specifications Regarding Steam Generator Tube Integrity ATTACHMENT A Description and Assessment

U.S. Nuclear Regulatory Commission Attachment A 3F0506-03 Page 1 of 4 Description and Assessment

1.0 INTRODUCTION

The proposed license amendment revises the requirements in the Crystal River Unit 3 (CR-3) Improved Technical Specification (ITS) related to steam generator tube integrity.

The changes are consistent with NRC approved Technical Specification Task Force (TSTF) Standard Technical Specification Change Traveler, TSTF-449, "Steam Generator Tube Integrity," Revision 4. The availability of this technical specification improvement was announced in the Federal Register on May 6, 2005 as part of the consolidated line item improvement process (CLIIP).

2.0 DESCRIPTION

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

" Revised ITS definition of LEAKAGE

" Revised ITS 3.4.12, RCS [Reactor Coolant System] Operational Leakage

" New ITS 3.4.16, Steam Generator (OTSG) Tube Integrity

" Revised ITS 5.6.2.10, Steam Generator (OTSG) Program

" Revised ITS 5.7.2.c, d, and e, Steam Generator Tube Inspection Report(s)

Proposed revisions to the ITS 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 ITS improvement. The changes to the affected TS Bases pages will be incorporated in accordance with the ITS 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.

5.0 TECHNICAL ANALYSIS

Progress Energy Florida, Inc. (PEF) has reviewed the safety evaluation (SE) published on March 2, 2005 (70 FR 10298) as part of the CLIUP 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. PEF has concluded that the justifications presented in the TSTF proposal and the SE prepared by the NRC staff are

U.S. Nuclear Regulatory Commission Attachment A 3F0506-03 Page 2 of 4 applicable to CR-3 and justify this amendment for the incorporation of the changes to the CR-3 ITS.

6.0 REGULATORY ANALYSIS

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

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

Plant Name, Unit No. CrystalRiver Unit 3 Steam Generator Model(s): 177FA Effective Full Power Years (EFPY) of service for currently Approximately 19.2 as of Refuel 14 (Nov. 05) installed OTSGs Tubing Material Alloy 600 Stress Relieved Number of tubes per OTSG 15,531 Number and percentage of tubes OTSG A OTSG B plugged in each OTSG 351 (2.3%) 862(5.6%)

Number of Tubes repaired in each OTSG OTSGA OTSG B Tubes wi sleeves (Inservice) 159 156 Tubes wi repairrolls (Inservice) 948 1401

- PrimaryWater Stress Corrosion Cracking Degradation mechanism(s) (PWSCC)

- Outside DiameterIntergranularAttack/Stress identified CorrosionCracking (OD IGA/SCC)

- Wear /Fretting / Thinning Per SG: 150 gallonsper day (gpd) per LCO 3.4.12.d Current primary-to-secondary Total: No total limit specified in ITS Temperature condition leakage is evaluated at: room temperature

U.S. Nuclear Regulatory Commission Attachment A 3F0506-03 Page 3 of 4 Approved Alternate Tube Repair Criteria (ARC):

1. FirstSpan IGA - Approved by: Amendment 158 dated 10/28/97

- Applicability: Inservice tubes with pit-like IGA indicationsin thefirst span of OTSG B

- Any special limits on allowable accident leakage:

None

- Any exceptions or clarifications to the structural performance criteria that apply to the ARC: None

2. Tube End Cracks (TECs) - Approved by: Amendments 188 dated 10/01/99 and 222 dated 10/31/05

- Applicability: Inservice tubes with axially-orientedTECs in either OTSG

- Any special limits on allowable accident leakage:

1 gallon perminute (gpm) minus 150 gpdfor TECs combined with all otherpostulatedaccident leakage

- Any exceptions or clarifications to the structural performance criteria that apply to the ARC: None Approved OTSG Tube Repair Methods

1. Sleeves - Approved by: Amendment 136 dated 09/11/91

- Applicability limits, if any: (ITS 5.6.2.10.4.a.11.a)

No more thanfive thousandsleeves may be installedin each OTSG.

- Repair criteria: 40% of the sleeve wall thickness Approved by: Amendment 198 dated 09/10/01

2. RepairRolls Applicability limits, if any: None.

Repair criteria: 40% of the initial wall thickness Performance criteria for accident Primary to secondary leak rate values assumed in leakage licensing basis accident analysis, including assumed temperature conditions: 1 gpm at room temperature assumed in the CR-3 FinalSafety Analysis Report 7.0 NO SIGNIFICANT HAZARDS CONSIDERATION PEF has reviewed the proposed no significant hazards consideration determination published on March 2, 2005 (70 FR 10298) as part of the CLIIP. PEF has concluded that the proposed determination presented in the notice is applicable to CR-3 and the determination is hereby incorporated by reference to satisfy the requirements of 10 CFR 50.91(a).

U.S. Nuclear Regulatory Commission Attachment A 3F0506-03 Page 4 of 4 8.0 ENVIRONMENTAL EVALUATION PEF has reviewed the environmental evaluation included in the model SE published on March 2, 2005 (70 FR 10298) as part of the CLIIP. PEF has concluded that the staff's findings presented in that evaluation are applicable to CR-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. PEF is not proposing variations or deviations from the TS changes described in TSTF-449, Revision 4, or the NRC staff's model SE published on March 2, 2005 (70 FR 10298).

10.0 REFERENCES

Federal Register Notices:

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

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

PROGRESS ENERGY FLORIDA, INC.

CRYSTAL RIVER UNIT 3 DOCKET NUMBER 50-302 / LICENSE NUMBER DPR-72 LICENSE AMENDMENT REQUEST #264, REVISION 0 Application to Modify Improved Technical Specifications Regarding Steam Generator Tube Integrity ATTACHMENT B Proposed Improved Technical Specification Changes (Mark-up) 1ieeut te*t indicates deleted text.

h indicates added text.

TABLE OF CONTENTS 3.3 INSTRUMENTATION (continued) 3.3.11 Emergency Feedwater Initiation and Control (EFIC) System Instrumentation ................ 3.3-26 3.3.12 Emergency Feedwater Initiation and Control (EFIC) Manual Initiation ...................... 3.3-30 3.3.13 Emergency Feedwater Initiation and Control (EFIC) Automatic Actuation Logic ............. 3.3-32 3.3.14 Emergency Feedwater Initiation and Control (EFIC)-Emergency Feedwater (EFW) -Vector Valve Logic ................................... 3.3-34 3.3.15 Reactor Building (RB) Purge Isolation-High Radiation ..................................... 3.3-35 3.3.16 Control Room Isolation-High Radiation .......... 3.3-36 3.3.17 Post Accident Monitoring (PAM) Instrumentation.. 3.3-38 3.3.18 Remote Shutdown System .......................... 3.3-42 3.4 REACTOR COOLANT SYSTEM (RCS) ...................... 3.4-1 3.4.1 RCS Pressure, Temperature, and Flow Departure from Nucleate Boiling (DNB) Limits ........... 3.4-1 3.4.2 RCS Minimum Temperature for Criticality ......... 3.4-3 3.4.3 RCS Pressure and Temperature (P/T) Limits ....... 3.4-4 3.4.4 RCS Loops-MODE 3 ............................... 3.4-6 3.4.5 RCS Loops-MODE 4 ............................. 3.4-8 3.4.6 RCS Loops-MODE 5, Loops Filled ................. 3.4-10 3.4.7 RCS Loops-MODE 5, Loops Not Filled ............. 3.4-13 3.4.8 Pressurizer .................................. 3.4-15 3.4.9 Pressurizer Safety Valves ..................... 3.4-17 3.4.10 Pressurizer Power Operated Relief Valve (PORV).. 3.4-19 3.4.11 Low Temperature Overpressure Protection (LTOP) System ................................... 3.4-21 3.4.12 RCS Operational LEAKAGE ......................... 3.4-22 3.4.13 RCS Pressure Isolation Valve (PIV) Leakage ...... 3.4-24 3.4.14 RCS Leakage Detection Instrumentation ........... 3.4-27 3.4.15 RCS Specific Activity ........................... 3.4-30 3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS) .............. 3.5-1 3.5.1 Core Flood Tanks (CFTs) ......................... 3.5-1 3.5.2 ECCS-Operating ................................. 3.5-4 3.5.3 ECCS- Shutdown .................................. 3.5-7 3.5.4 Borated Water Storage Tank (BWST) ............... 3.5-9 3.6 CONTAINMENT SYSTEMS ................................ 3.6-1 3.6.1 Containment .................................. 3.6-1 3.6.2 Containment Air Locks ......................... 3.6-3 3.6.3 Containment Isolation Valves .................... 3.6-8 3.6.4 Containment Pressure ............................ 3.6-15 3.6.5 Containment Air Temperature ..................... 3.6-16 (continued)

Crystal River Unit 3 ii Amendment No. +6-1

TABLE OF CONTENTS B 3.3 INSTRUMENTATION (continued)

B 3.3.12 Emergency Feedwater Initiation and Control (EFIC) Manual Initiation ................... B 3.3-100 B 3.3.13 Emergency Feedwater Initiation and Control B 3.3.14 (EFIC) Automatic Actuation Logic ...........

Emergency Feedwater Initiation and Control B 3.3-105 I

(EFIC)-Emergency Feedwater (EFW)-Vector Valve Logic ................................ B 3.3-110 B 3.3.15 Reactor Building (RB) Purge Isolation-High Radiation ............................... B 3.3-114 B 3.3.16 Control Room Isolation-High Radiation ........ B 3.3-119 B 3.3.17 Post Accident Monitoring (PAM) Instrumentation B 3.3-124 B 3.3.18 Remote Shutdown System ........................ B 3.3-145 B 3.4 REACTOR COOLANT SYSTEM (RCS) ...................... B 3.4-1 B 3.4.1 RCS Pressure, Temperature, and Flow Departure from Nucleate Boiling (DNB) Limits .......... B 3.4-1 B 3.4.2 RCS Minimum Temperature for Criticality ........ B 3.4-6 B 3.4.3 RCS Pressure and Temperature (P/T) Limits ...... B 3.4-9 B 3.4.4 RCS Loops-MODE 3 .............................. B 3.4-17 B 3.4.5 RCS Loops-MODE 4 .............................. B 3.4-22 B 3.4.6 RCS Loops-MODE 5, Loops Filled ................ B 3.4-27 B 3.4.7 RCS Loops-MODE 5, Loops Not Filled ............ B 3.4-33 B 3.4.8 Pressurizer................................. B 3.4-37 B 3.4.9 Pressurizer Safety Valves ...................... B 3.4-43 B 3.4.10 Pressurizer Power Operated Relief Valve (PORV) . B 3.4-47 B 3.4.11 Low Temperature Overpressure Protection (LTOP) System .................................. B 3.4-52 B 3.4.12 RCS Operational LEAKAGE ........................ B 3.4-53 B 3.4.13 RCS Pressure Isolation Valve (PIV) Leakage ..... B 3.4-58 B 3.4.14 RCS Leakage Detection Instrumentation .......... B 3.4-65 B 3.4.15 RCS Specific Activity .......................... B 3.4-71

_4j:6-_ er~iap~~...B34 B 3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS) ............. B 3.5-1 B 3.5.1 Core Flood Tanks (CFTs) ........................ B 3.5-1 B 3.5.2 ECCS-Operating ................................ B 3.5-9 B

B 3.5.3 3.5.4 ECCS-Shutdown .................................

Borated WaterStorage Tank (BWST) ..............

B B

3.5-20 3.5-24 I B 3.6 CONTAINMENT SYSTEMS ............................... B 3.6-1 B 3.6.1 Containment .................................... B 3.6-1 B 3.6.2 Containment Air Locks ........................ B 3.6-6 B 3.6.3 Containment Isolation Valves .................. B 3.6-15 B 3.6.4 Containment Pressure ........................... B 3.6-29 B 3.6.5 Containment Air Temperature .................... B 3.6-32 B 3.6.6 Reactor Building Spray and Containment Cooling Systems .............................. B 3.6-35 Inud (cont (conti nued)

Crystal River Unit 3 vi Amendment No. 14ýZ

Definitions 1.1 1.1 Definitions LEAKAGE 3. Reactor Coolant System (RCS) LEAKAGE (continued) through a steam generator EOTSG) -u to the secondary system ymrj --

o sdary

b. Unidentified LEAKAGE All LEAKAGE that is not identified LEAKAGE.

c. Pressure Boundary LEAKAGE LEAKAGE (except OTSG tube leakage "IrMary to pndrLMaAK7**) through a non-isolable fault in an RCS component body, pipe wall, or vessel wall.

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.

NUCLEAR HEAT FLUX HOT F.Q(Z) shall be the maximum local linear power CHANNEL FACTOR (F(Z)) density in the core divided by the core average fuel rod linear power density, assuming nominal fuel pellet and fuel rod dimensions.

NUCLEAR ENTHALPY RIS$EN F' shall be the ratio of the integral of linear HOT CHANNEL FACTOR IFZ) power along the fuel rod on which minimum departure from nucleate boiling ratio occurs to the average fuel rod power.

OPERAB LE-OPERABI LITY A system, subsystem, train, component, or device shall be OPERABLE when it is capable of performing its specified safety function(s) and when all necessary attendant instrumentation, controls, normal or emergency electrical power, cooling and seal water, lubrication and other auxiliary equipment that are required for the system, subsystem, train, component, or device to perform its specified safety function(s) are also capable of performing their related support function(s).

PHYSICS TESTS PHYSICS TESTS shall be those tests performed to measure the fundamental nuclear characteristics of

.the reactor core and related instrumentation.

(continued)

Crystal River Unit 3 1.1-5 Amendment No. 149

RCS Operational LEAKAGE 3.4.12 3.4 REACTOR COOLANT SYSTEM (RCS) 3.4.12 RCS Operational LEAKAGE LCO 3.4.12 RCS operational LEAKAGE shall be limited to:

a. No pressure boundary LEAKAGE;

b. 1 gpm unidentified LEAKAGE;

c. 10 gpm identified LEAKAGE; and

d. 150 gpd of primary to secondary LEAKAGE through any one steam generator (OTSG).

Tw OS- s shall bePERABLE-.

APPLICABILITY: MODES 1, 2, 3, and 4.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. RCS *ierational A.1 Reduce LEAKAGE to 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months LEAKAGE not within within limits.

limits for reasons other than pressure boundary LEAKAGE Fr bonmary ,dJý'; ond"'d 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 associ ated Completion Time not met. AND OR 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.

Primar to seondaryn LEAKAGE not within,

~jmi t Crystal River Unit 3 3.4-22 Amendment No. +5-8

RCS Operational LEAKAGE 3.4.12 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY

.4 SR 3.4.12.1 --------------------

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

Li Not required to be performed in MODE 4.

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

~.Not a~pli6cable' to 'pri'mar'y toqsecondary

~.EKAGE.

[-irf '-RS operaiioniiT- L-EAIK-AGqE3 &' ihj 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months

!rts by pjýrformance'of Perform RCS water inventory balance during steady state opeatin.

SR 3.4.12.2 7- -NOTE---- - - - - - - in accordance 4ot required to be performed until 12 .------ hours' with the Steam ifter * *',77*N ---

establishment -,- - -*--------*-

of,steady state Generator Tube

)peration. Su..rveill1ance P-J._.L v *.

Program-

. l

verity ;team generator tune integrity is in Vl hourS-I I-accordance with the Steam Generator Tube Surveillance Prra,,. proi* 'rfy i7-'

~conar9EA~E' < 150,,gallons pe r day 1hrough, any__qe s~te~am generaor Crystal River Unit 3 3.4-23 Amendment No. -149

1i OT6ibiY-'--i

~ iyringt~ih tbe,, pair criteria ~shiil be pilugged'orr~g~jr in_ accordance with _the Steam Generatori eat ont----------------------NOT 0*------- Ey E

5eparate Condition entry is allowed for each OTSG tube.:

VbQJID ACIN WkPLEMONTM ubes sati sfying ithi f the affected ube repair criterji rube(s) is maintaijned nd not-plugged or ntil the next epairedin efueling outage or ccor 'dan-ce' 0iEKhetSube_inspIcIon-team Generator rPogr~m. iN Yug or repair th rior to eteringi

ffected tube(s) in NODE 4 following (ccordance withbhe *he next refueling

team Gekrator utage or OTSG Reqsu- i atedA an iCnseon soiated CompiIeti 6ii inie of Conditipn,ýA ~

pot,_mai ntai ned.

Crystal River Unit 3 3.4-34 Amendment No. XX

PTSG TubeP Integrity Ur EIL CAN CE IREQUENCY

$k _3.,4,] ji ~Veifry"a-6bb- ifSC ni'te " if-fVin -ccord~i. ri cordancejvft Wvith the $team'Genertor FPrgram. ~ he ýSteam

[,.enertr Prgram ypRi that ~ach i spected OTSG ttibe thaii pior to 'kenring

ýatisfies-the tube repair criteria is NODE 4 following a SlugIge6d or repaired in accordance with,'ihe' TSG tube team qenýrator .Proga.bppcto Crystal River Unit 3 3.4-35 Amendment No. XX

Procedures, Programs and Manuals 6 5.6 5.6 Procedures, Programs and Manuals (continued) 5.6.2.10 Steam Generator (OTSG) Tube Surveillanee Program Ealh OTSG shall be demonstrated OPERALE by performance of thIe following augmented inservice i npection program.

1. Each OTSG shall be determined OPERABLE during shutdown by selecting and inspecting at least the miiu umber of OTSGs speeified in Table 5.6.2 1.

2. The OTSG tube minimum sample .I*1e,inspetion result classification, and the corresponding action required shall 111 be as specified in Table 5.6.2 2. The inserI1' i ection of OTSG tubes shall be performed at the frequencies specified 4i Specification 5.6.2.310.) and the inspecte* d tubes shall be verified acceptable per the acceptance

-riteria of Specification 5.6.2.10.4. The tubes sele.ted for each *nserv inspection shall include at least 3of the total number of tubes in all OTSGs. The tubes selected for these inspections shall be selected on a random basis exeept.

a. Where, e,.peiene in similar plants with similar water chemstryindiates critical areas to be inspected, then at least 50% of the tubes inspected shall be fro these critical areas.

b. The first inservice inspection (subsequent to the preservice inspection) of each OTSG shall include:

1. All nonplugged tubes that previously ha

2. Tubes in those areas where experience has Sindiated potential problems.

C.The second and thi rd ieric inspectioans may be less than a full tube inspection by concentrating (selectin at least 50% of the tubes to be inspected) the inspection on those areas of the tube sheet array and on those portions of the tubes where tubes wt imperfections wer prvosly found-.-

d. Tubes in seiic.limited areas whiceh are distinmgui she by unique operating conditions or physical constructio may be excluded from random samples if all such tubesy (continued)

Crystal River Unit 3 5.0-13 Amendment No. -149

Procedures, Programs and Manuals 5.6 5.6--Procedures, Programs and Manuals 5.6.2.10 OTSG Tube Surveillane, Program (continued) in the specifi. area of an OTSG are inspected with the inspection result classification and the corresponding action required as specifid in Table 5.6.2 3. No 1redit will be taken for these tubes in meeting minimUm sample sizereqirements. Degraded or defective tube found in these ara*s will not be.onsidered in determining the inspe=tion results category as long asI the mode of degradation isuie to that area and not random in nature.

e--Inservice tubes with pit like IGA indications in the first span of the B OTSG, identified in the OTSG inservi.e inspetion Surveillance -r-,edure, must be inspected with bobbin and Motorized Rotating . a.-ake Coil EMRP,) eddy current techniques from the lower tube sheet secondary face to the bottom of the first tube support plate during each inservie i..ns..tion of the B OTSG. No credit is to be takeLN--nl for this inspection i-n meeting miniu sample Size requi rements for the rando inspection. Defective tubes found during ti inspection are to be plugged or sleeved. Degraded or defective tubes found during this inspection are not to be considered in determining the inspection results category for the random inspection, unlessth degradation mechanism identified is a mechanism othe-r than pi t ike !GA-.

f-.---Tubes in service with axially oriented tube end cracks (TEE) are identi fied in the OTSG INser.v ic.. Inspecti on Surveillance procedure. The portion of the tube with the axial TEE must be inspected using the motorized rotating coil eddy current technique during each subsequent inspection. No credit is to be taken for this inspection for meeting the minimu saple size reurment for random sample inspection.

Tbsidentified with TEE that meet the alternate repi criteria wI be added to the exi sti ng i st of tuesi

-lhl inserviceIT*CG inspection Surveillance procedure.

Tu.es identified with TEE during the previou insecio whiih meet%Ith cri terHia to reain. sin i lwill not be included when calculat-ng the inspection category of the (continued)

Crystal River Unit 3 5.0-14 Amendment No. +H

Procedures, Programs and Manuals 5-6--Procedures, Programs and Manuals 5.6.2.10 OTSG Tube Surveillane. Program ( -ontinued)

The inspection data for tubes with axiall oriented TEC

-indi 111'a" -'t .. Is. sa me eiGIbmVo)IIIn 4, t~l %VII/;4 A 'V to I.I%o IF mt V i. 4Ill .1 t*e r.. / e.i... I"J" Inspection~~~~

dat tomntrteidctons for growth.

I%ý Tubes If IOI l- l I with axiall

.Ij .IiLI ;! I V oiented TEE ma- belet,in service I V .w 1 I Jiwlm* ; . II V

V V .I using-the method- srbdi oia Reprt BAW 2346P, Revision 0, providedthe~ombined-'pr..ed*'- *leakage frm teame, IIO ie e ak* I1-)

ak ..

acideteaikage It I OTSG.~~~ehThHotiuin oML ekgertsfo E Topica Reor BraW 23P46rIP,Revision 0.O to secnaryleakae adtecuei determine to be-examind tubes; ardendefetiv tubesý 100 of0th tube loca tionofteT. %-

removd frm serice singther aprpitheapoe us u I&method.

IQL/uII * .i&; *TuAe h~ IL*

L. UII 23ith irumrentisoall p*aL i I',*LJa 61,. d ll. rine nau*L TCo Il11*

eASll*

of thde tubeshetshallub reardorn remoed fro servi e oiia using lee th appopithe capproedismethod.

Theutshfeac For the-* inspec.t XionqrA. c ci sapeiseton tcrdanc tohbi shaleb wi

L .II;;

pI 111t Ii H* IC.z*.

wail 1e t- lr.iionl il to bel,U.. IineluIy-clsifi Ed intohoe oftherOS following theemi caeoies:h at the 1§97 locati r oF te T TE npetisall wl'l.be incl u*ded inthebelow Tubesfwith 5...1,. = *.*. (10%) . furterwl tube w.ith. penetrations TEE'/ ind wti cat toebeaincde on t 41.

id-en-t- i/

inthebelpow "I xaINZ La.01 , pretage a ~ hpeto calulahetios.alb wil be inlue , wo eardo in,.=the t belo 5.6.2.10.2.f only w* ,,=v*,=,ECtubens ,, witl

,.,* o,.*,E idctin

. exm*, detfe een t nuhel Crysta vIrIUnitI. *a*0 ll e-,A m e xhibiV1eIt 22 Ersa River* Uni 3 5.l 14 Amendment No. 222 pcenssaged calclatones.h oll..,caeois

Procedures, Programs and Manuals 5.6 5-f6-Procedures, Programs and Manuals 5 .6.2.10*--TS-G-r.ube Su....ve'll, r ane.. Program* E.v,,t,,,edý Cateaory inspection Results C1 Less than 5% of the total tubesinpte are de*raSd dtubes .. and none of the inspe.ce tubees aRe, defeetive.

C7 2 One or more tubes, but not more than B6 of the total tubess ispected are defctive,- or between 5% and .1.0%6 6f the total-- tubes insected are degraded tubes.

C 3 More than 10% of the total tubes. inspecte are degraded tubes or more than 33 ef the nsected tubes are defective.

3. The above requre inservic inpe!ction of OTSG tubes shl be perfored at the folig frequenciesw

a. ...,:cinsp.' ections shall be perforTed at inter;'l

~fte th prvios inspection. if two consecutive inspetion floig conditions!., erice under all volatile treatment EAVT9 not nludigth re iIn, r.0 1 L. As4- l in lt r r I F-L* I" *_, "q y. , rp i t.... --.. .. .. i.

inpcions demontrt taprvosy bserved dlegrdtion has not eontinued' anQnl adipoa degadtion has occurred, teisection interval may bextede to a maximum of01ý once per 40months.

b. if the inservic inpetion of an OTSG, coenducted i

.W "- ll1 .I%_L~L Iwis/ i. i,. II 1, 5.ý {;.I I 1 4 l*%- %-%A#A%

I .L,IilI' I accordance wjithTable 5.6.2 2 orTbec.. require lnd n thirdsample sa inspcto i not reurd fqth C) result bnpeto classifato sdetinlin new tubes with TEE indications~Lw thte theccrtei trmin in service, no reduction in inspectionfeqec isrqurd

. Additionalsc l nice of an OTSGons shall be inspection prom -'-c'on . eac ,

leaks.*,*]f ,. bi,i Yti T... g;

inI I acco -- rdance I"... I tub41

. i . Ii*¥ wt t UWt~ UU JZ- J first..

i~l II,,.,,

'ample !s ---- ' t -- 10s-- pec" in Table 5.6.2 2 or Table

-ified

-du ~~

g shtonsbeuent to any of the in Ixces s. i.fits. oF Specification 3.4.12,-

2. A ei eurrence greater than the Operating Basis Earthquake,

3. A loss of coolant accident requrn actuation of the engineered safeguards, or

4. A main steam line or feedwater line brek (continued)

Crystal River Unit 3 5.0-15 Amendment No. 2-22

Procedures, Programs and Manuals 5.6 5--6-rr I edures, Programs and Manual.s 5.6.2.10 OTSG Tube Surveillance Program (,nntinued)

4. Aeceptanee criteria:

a. Vocabulary as used in this Specification:

1. Tubing or Tube means that portion of the tube or sleeve which forms the primary system to secondary system pressure boundary.

2.. Imperfection means an exception to the dimensions, finiish or contour of a tube from that required by fabrication drawings or specifications. Eddy current testing indications below 20% of the nominal tube wall thickness, if detectable, may be considered as imperfections-.

3. Degradation means a service induced cracking, wastage, wear, or general coroio occurring on either inside or outside of a tube.

4. Degraded Tube means a tube containing degradatio

_:ý 20% through wall but < 40% through wall in the p-ressure boundary.

5. % Degradation/% Through wall means the percentag of the tube (pressure boundary) wall thicknesrs affected or removed by degradation.

6. Defective Tube means a tube containing degradatio

>40% through wall in the pressure boundatry.-Any tube which does not permit the passage of the eddy current inspection probe shall be deemed I

defective tube.

_----Pi- .. .GA) Attack likeIntergranular indication mfeans a bobbi n coil i ndi cation confi rmed by Motorized Rotating rancake Coil iMRPC) or other qualified inspection techniques to have a volumetrie, pit like morphology characteristico (conti nued)

Crystal River Unit 3 5.0-16 Amendment No. 190

Procedures, Programs and Manuals 5.6 5--6-Procedures, Programs and Manual..

5.6.2.10 OTSG Tube Surveillance Program (continued) 6.-r*,luging/Repair Limit means the extent of pressure boundary degradation beyond whieh the tube shal either be removed from service by installation o plugs or the area of degradation shall be remve from servi. e (a new pressure boundary established) u s Approved

. Repair Te'hnique. The plugging/,repair limit is 40% through wall for all pressure boundary degradationt.

9. Unserviceable describes the condition of a tubeif-it leaks or contains a defect large enough to affect its structural integrity in the event of an Operating Basis Earthquake, a loss of coolant accident, o, a ma.n steam line or feedwater line ak, as specified in 5.6.2.0.3.e, above.

3:---Tube Inspection means an inspction of the OTSG

.tube pressure boundary.

11.-Apprved Repair Technique means a technique, other than plugging, that has been accepted by the NRC as a methodology to remove or repair degraded or defective portions of the pressure boundary and to establish a new pressure boundary. Following are Approved Repair Techniques:

-)--Sleeve installation in accordance with the B&W process (or method) described in report BAW 2120P. No moeta five thousand sleeves may be installed in each OTSG.

b)-installation of repair rolls in the upper and lower tubesheets "i..... rdance with BAW 2303-,

Revision 4. The repair process (single, overlapping, or multiple roll) may be performed in each tube. The repair roll area will be examined using eddy current methods following installation. The repair roll must be free of imperfections and degradation for the repair to be considered acceptable.

(continued)

Crystal River Unit 3 5.0-17 Amendment No. +M

Procedures, Programs and Manuals

-5.-*6 5-6-Procedures, Programs and Manuals 5.6.2.10,---OTSG Tube Surveillanee Program Eeentinuedý The repair roll in eaeh tube will be inspete during each subsequent inservice inspection while the tube with a repair roll is in service. The repair roll will be.onsidered a specific limited area and will be excluded from the random sampling. No ,redit will be taken for meeting the miimu saple size.

If primary to secondary leakage results in -

shutdown of the plant and the cause i determined to be degradation in at repair roll-,

100% of the repai"r roll-s in that OTSG shall be examined. if that inspection results in entering Category C 2 or C 3 for specific Si mi ted ar ea inspecti on, as detail1ed in Tabl-e 5.6.2 3, 100% oF the repair rolls shall be exained in the other OTS*G.

12---Tube End Cracks (TEC) are those crack like eddy current indications,,i rcumferentially and/or axially oriented, that are within the In,*nel cla region of the primary face of the upper and lower tubesheets, but do not extend into the carbon steel to Inconel clad interface.

b. The OTSG shall be determined OPERABLE after completing the corresponding actions (plug or repair all tubes ex^eeding the plugging/repair limit) required by Table 5.6.2 2 (and Table 5.6.2 3 if the provi sion o

&peciflcation 5.6.2.10.2.01 aeuilized).

Inservice .tubes with pit like IGA indications in the "B" I

OTSG first span shall be monitored for growth of these indications by using a test probe equivalent to the high frequency bobbin probe used in the 1997 inspection. The indicated percentage throughwall value from the curren inspection shall be compared to the indicated percentage throughwall value from the 1997 inspection.

Eeon~tiuedý I q .. .. g i aya " v W_-

m r111i--"

i .iiii;iii.c~ i1 U .,

"INO

... /

Procedures, Programs and Manuals 5.6 5.6 Procedures, Programs and Manuals 5.6.2.10 Steam Generator (OTSG) piýogram

nsure that OTSG tube integrity is. maintained. In addition, the

.team Generator Program shall include the following. provsos condition netmeisions-fr ssments7 C6hdii-n asii onitoring assessment means anev luation of the"as to the performance-found" ondition of the tubing with respect riei o tutrlitgiyand accident induced eakage. The "as foun'd" condition refersoutage, to the asconditi6n f the tubing during an OTSG inspection etermined from the inservice inspection results oF-by ther means, prior to the plugging or repair of tubes.

ondition monitoring assessments shall1be conducted during ach outage during which the OTSG -tubes are inspected,,

lugged, or repaired to confirm ,that.the performance luriteria arebeing

, ormanceTcr tera ferrrTo , G ,tubenteg ri y. 'SG tube tntegrity shall be maintained by meeting the performance 1riteria for tube structural integrity, accident induced

... kae, androperatinteal LEAKAGE.

..... i tyef6 r;u n 6 neat 6rh 7I H6nA 'i ntu ervice steam generator tubes shall -retain structu.raT ntegrity over the full range of normal operating___

o.nditions (including startup, operation in the p6wer angeIe, hot standby, and cool down and all anticipated ransients included in the design specification) and esign basis accidents. This i ncludes, retaining a afety-factor of 3.0 against burst under normal ist6ad tate full power operation primary-to-secondary ressure differential and a safety factor of 1.ý4 gainst burst applied to the. design, basis .acciden-t rimary-to-secondary pressure differentials. Apa rom the above requi rements,, additional i oading

-onditions, associated with the deisign basis accfdeiif r combination of accidents In accordance with the si.gn and. icensing basis, shall also' be eval uateTt6 etermineif the associated oads contribute ignificanty to burst or-collapse. In the aiissse0 f tubelintegrity, those loads that :do significantly ffect burst or *collapse -shall be determined and ssessed rin combination with the loads due to pressure ith a safety factor ýof 1.' on the combiAed. primary oads_ano 1.0 on axial--secondary( lueads (conti nued)

Crystal River Unit 3 5.0-13 Amendment No. XX

Procedures, Programs and Manuals 5.6 5.6 Procedures, Programs and Manuals 5.6.2.10 OTSG P (continued) rimary to secondary accident induced leakage ratelfo ny design hbasis accident, other than an OTSG tube upture,` shall not exceed the leakage rate assumed"Ji he accident analysis in terms of totalleakage rate or all OTSGs and -leakage rate for an individual OTSG, eakage is not to exceed one gall on per, minute per TSG, except for specific types of degradation at peci fic ocations as described in paragraph c orthe team P AR, PGer-o

~rt~f6iil LtA~AdE performac~e '5riterio Is

___he

. pecf...edin*d LCO 3 4,122 RCS q0perational LEAKAGE."

P7 isions *-r OTSG tube repai r crtera b Tubes und -by nservice inspection to contain flaws wi'th a depth equal to

ýr exceeding 40% of the nominal tube wallthickness shall'

h lowin4g alternate t t epa r criteria may be apied an alternativeto the 40% depthbased n cri ria:

te IGA) i ndi cati ons, in the first span of the B OTSGC dentifiedi in the OTSG Inservice Inspection.

urveillance Procedure, must be inspected -wih brobbin nd Motorized Rotating Pancake Coill (MRPC) eddy urrent techniques from the lower tube sheet sec66dary ace ..to .the bottom of the first, tube'support plate inservice inspection of the B MG. No Iredit each uring is to be taken for this inspection in meei

¶nimum Inspection. sample size requirements for the random

ýTubes found during this inspection thiat

'xceed the 40% of tube wall thickness ýrepair criterif`onr re to be plugged or sleeved. Degraded or defective ubes found during. this: inspection :are not to be onsidered in determining the insp6ection result.s ategory for the random inspection, unless the_

egradation mechani-sm .identified is amechani-sm*dhe (conti nued)

Crystal River Unit 3 5.0-14 Amendment No. XX

Procedures, Programs and Manuals 5.6 5.6 Procedures, Programs and Manuals 5.6.2.10 OTSG j'rgani (continued) ubes n s rivdce: win axia, oriente tube end cracks TEC) are identified in the OTSG Inservice inspection uurveillance procedure. The portion of the tube with he axial TEC must be inspected using the motorized otating coil eddy current technique during each-_

ubsequent inspection. No credit is to be taken for his inspection for meeting the minimum sampei size equi rement for random~s'amp] e inspection.

ubes identified wi th'T'E'C that rneet tie-alernate epair criteria will be added to the existing liSt _of ubes in the OTSG Inservice.Inspection Surveillance

.rocedure. Tubes identified with TEC during the,__-,,,_,

revious inspection which meet the criteria to rre~mai n-service will not I~Z be included_, when calculating the

._n~sp-e

nsection _Sc.tiegpryp cegyof,,the OTSG. ....... ... ..................

.be.-OT

hee iinsp n -ditataflrotubes w tiax"ayrTl'6 iented

[EC indications shall be comPared to the 'previous nspection _data to-,monitor the'indications, frgowti.ý u -'-with -axiaiiy-bor-eti-iea- -E, m'a-y-1e-eft in-service sing the method described in Topical Report BAW-,

,346P, Revision 0, provided the combined projected eakage from all primary-to-secondary leakage,.

including axial TEC iindications left in-service, does' ot exceed the Main Steam Line Break (MSLB) accident eakage limit of one gallon per minute, minus 150 allonsper day, per'0TSG. The contribution to MSLB eakage rates from TEC indicati.ons .shall be determined tiltizing the methodology in,Addendum B dated August 0, 2005 to Topical Report :BAW-2346P, Revi sion 0. The rojection of TEC leakage that may .develop duri ngo the ext operating' cycle shall -be determined using the 9*pj.cal].,...eP._rin ethodology BA*L 2 34 6P,C.;dated t Addendum Bon0 ... 3,9 . 2005 Rev i s*i August to

o-secondary leakage and the' cause is determinedto: bd egrad ationpof the TEC portion of the tubes,i100%of

he tubes with TEC in that IOTSG shall be examined fin phe location of the TEC. 1 If more than 1% of the

.xamined tubes are defective, 100% of the tubes with ECn inrthe -,other OTSG shbe examined in the ca iont of the TEC.

(conti nued)

Amendment No. XX 5.0-15 Crystal Unit 3 River Unit Crystal River 3 5 .0-15 Amendment No. XX

Procedures, Programs and Manuals 5.6 5.6 Procedures, Programs and Manuals 5.6.2.10 OTSG (continued)

-'ro*g~am treel portion of the tubesheet shall be repaired or emoved from service uSing the appropriate approved ethod.. 'Tubes with circumferentially oriented TEC 6o olumetric indications wi thin the.Inconel ,,clad region f,the tubesheet shall be -repaired or removed f rom ervi ce us6 th prpit prvdmtod.

P rov*isions for OTShGý Tnspecto~ns. _Pe-ri odicOTSG tube ee nspections shall be performed, The number and portions of he tubes inspected and methods of insPection shall .be erformed with the objective6of detecting: flaws of any'type e.g., volumetric flaws, axial and circumferential cracks) hat may be present along the'length of the tube,'from the ube-to-tubesheet weld at the tube inlet to the tube-to-ubesheet weld at the tube outlet, and that may satisfy the ppli cable tube- repair criteria. The tube-to-tubesheet eldd is not part of the tube. In addition to meeting te, equirements of d.1, d.2,' and d.3 below, the inspection cope, inspection methods, "and inspection :intervals shall e such as to ensure that OTSG tube integrity is maintajied ntil the next ,OTSG inspection. An assessment of.

egradation shall be performed to determi ne the tjfre*! *d ocation of flaws to which the tubes may be susceptible ndj based on this assessment, to determine which nIspection methods need ~to'be employed-and at what, locati ons.

16sripeci 100% 6 "thi t~ibd9 in eah OTSG dur-in~g -the rFjrst rrfel ing.ouag folwigTSg r , ont 01Oo~ s. replacement._ý rsti ......

16 Thsct

.ffecti ve tb-e-"t-ub-esa-tseunilprosf ful ofp~er 100/06 nhs T,*:~he fij equenti al, 6 fneri~d salb.

.. shallbe jeriod.

s.rvice inspection id67 f" te Ito spc considered, cIn OSs of the::OTSGs.begin N-OS No OT1 the.hl after firsýt

'perate _f o mo.r .r Iethan .24 effecti ve full pw 'ohi rpone refuelingoe (whic'hever I les) ps w o

-'If TTE;hfnseiofTfns ii iii inan OTfot-ethe, ten he next inspection forea.ch echaniSm that caused `theMcrack indicationOTSG for the degradati on shallnot ixceed 24 effective full power months or .bo fueIi j utage, (whichever is less). If definitive nformation, such as from examination of aTph]

ube,diagnostic non-destructive testing, or

.ngineering evaluationhindicates that a crackýlMIk indication is not associ ated with a crack(s) then the pdfi(ation need not be treated as a crack.)

(conti nued)

Crystal River Unit 3 5.0-16 Amendment No. XX

Procedures, Programs and Manuals 5.6 5.6 Procedures, Programs and Manuals 5.6.2.10 OTSG rgram (continued)

LEAKAGE.

t PF6vovi ons f6i OTSG i-urepair mefiiiods. Stegn'erao...r ube repair methods shall provide the means to reestabliis he RCS pressure boundary integrity of OTSG tubes without emoving the.tube from service. For: the purposes of these 1peci fi cations, tube pluggi ng i s not ,a repair. All itcceptable tube repay mehods ~are, litd below.:

L*T.*eeve i nstalatiq5ý71n accor ance * *nt the W p

ss

,or method) described in report BAW-2120P. No more

,than five thousand.Isleeves 4my, b~e installed in each I)TSG.

V-Insta i1Tan of repair , ols--iri the upper Tandlower ubesheets in accordance with BAW-2303P, Revision 4.

[e , repai r,, process (single, overlapping, or multiple ol )' .may beý performed in each tube. The repair rolT ea :Will be examined using eddy-current methods ol owing installation. The repair roll must ý,be free ffipefectio~ns 'And degradation for the repai~r,,to ý2be A ed accep 1e on Tneabc tub e iYT be Tnsp ected uin, g e aro l l ach subsequent inservice insp~ection whil'e'the(tube

,jiph a repai r roll is. in se rvjce.~

(conti nued)

Crystal River Unit 3 5.0-17 Amendment No. XX

Procedures, Programs and Manuals 5.6

-- - - - - - I - I . I 1 j.t 0L i pge! o i rI' 4J.i~ urI* I~il IX JI .J I LI-rM'l %JL-IIl-~r% I I ,.V I .-;%J.,j J %*JIX I WJ L,- J.1I'd.1.)1 L,..% I L-I,.

Preservice Inspection YeS Number of OTSGs TWO First Inservice Inspection ene Second --n' Subs......quen ... ...- _

peetionsOne*

The irsrieinspeetion may be limited to one OTSG I r- LU~ I- I LIIe reut In UI Or LI firs L US VIU inI3IJe-tiUII IIIUI l*L L*,. 1.1(11.LQ IUL.II V I.%,J, 'lI C I IUIl vIl IIIIlL III C; I IlV-manner. Note that under som rcumstancmses, the operating conditions in one OTSG may be found to be more

.c-u severe than those in the other OTSG. Under sueh tamces the sample sequence shall be modified to inspet the most severe conditios.

Crystal River Unit 3 5.0-24 Amendment No. +0

Procedures, Programs and Manuals 5.6 TABLE 5.6.2 2 (page 1 oJf 1)

OTNSG TUBr ,NSPEErTIN

, ° ,

5- j N/r. % Whr N 13 the~ nube ol UIA.311 the. unit and n i thez numbe. of fTSU. imspeted

.~

. ~ nor~d.

Crystal River Unit 3 5.0-25 Amendment No. 14G

Procedures, Programs and Manuals 5.6 r---------. _r .I I- .

I- N.. i .. .. . -. . i enrr-r.-rr , r.arrrn a nrA -r.,rnrfrrn.i

.. j1 -- .JL'. ILI.11J. I LId /%XL1=% .LII.JI L=., I .L.JIV 1st Sample inspection of a 2nd Sample inspectio of et "Spe-ifi' Limited Ae "Specifi- Limited Area" Sml qz Reut Action Resul*t Aetion

_ _ _ ~ re Requ~ed 100% of area E-+ None NA NA i n-both.

OT-SGs _____

64 Plug-or N/NA dde-efet+ve

_ tubesy- ___

E-3 Plug or N/A N/A def~ee tubes-*-

100% o~f arett 6-4 NoneN/NA in ne fTZG ____________ __ ___

E-2 Plug or 6 None delfmeet tubes-end E-2 Plug-or i nspect-~O 10p9.6 of defectiv'e eerrestpond~fi area-tin E-3 tubes-.

Plug-or I

other-eS e defeetive Ea Plug-or 6-4 None defeeeve C2Plug-or 4nqpeet -1009 ef defeetqwe tubes-J eorrespe n~~

eree-3 otCher -OT5FSG. ~

Plug-or I defeetive

_______ubee-.

Crystal River Unit 3 5.0-26 Amendment No. G

Reporting Requi rements 5.7 5.7 Reporting Requirements 5.7.1.2 Not Used 5.7.2 Special Reports Special Reports shall be submitted in accordance with 10 CFR 50.4 within the time period specified for each report.

The following Special Reports shall be submitted:

a. When a Special Report is required by Condition B or F of LCO 3.3.17, "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.

b. Any abnormal degradation of the containment structure found during the inspection performed in accordance with ITS 5.6.2.8 shall be reported to the NRC within 30 days of the current surveillance completion. The abnormal degradation shall be defined as findings such as delamination of the dome concrete, widespread corrosion of the liner plate, corrosion of prestressing elements (wires, strands, bars) or anchorage components extending to more than two tendons and group tendons force trends not meeting the requirements of 10CFR50.55a(b)(2)(ix)(B). The report shall include the description of degradation, operability determination, root cause determination and the corrective actions.

initial entry into :MODE 4 following completion' of an.

nspection performed in accordance with' the Specificatiin

.6.2. 10, Stem Genea OTGPrga.he a..Lh report'shall

~nIclu'de: .- rt~ý .O$._rp Z Th e 8--' p~f Ii eahe

.N on ae structv xmnto te _nquel ut_ ized-,_fo re 0egradati on mechanism,

.,16Lcat on,* *6rintati`n_,( f I !-near)`zh ,an6mesurg's iz e s Ki f avai 1abl e) of service inducedications inspection odtage for each activeidegradationr (ichanisme (conti nued)

Crystal River Unit 3 5.0-28 Amendment No. 2-2-2

Reporting Requi rements 5.7 5.7 Reporting Requirements 5.7.2 Special Reports (continued) 6J__T6ftaiT ii6ibe r -arid' pgr'cntage ,of,-to- s eii ,d0 k'epai red _to date1 L.The' ~res _1s of 'e6ftditionWiiio'iitoring, '-in~ludji~n'",g'Ote

ýesults of tube~pulls and in-situ testi~ng Th 6fetv-e' luIgi pIe -rcIentag fo all plgging' and

~u~berpajxsineach QTSGJ, methFd

~~U7Repairi-A fifr~j number 6-f t,4es repiafre Iy _ach repai r method,

. ,Following each inservice inspection of steam generator Kurnh1I.j TU=3,1*1 rhel WEt~= I" IshaIl. oile rte eiw, prior to ascension into MODE 4 I

1. Number of tubes plugged and repaired,

2. Crack like indications and assessment of growthfo indications in the first span; situ pressure testing, if performed; and of in,-Results

--Number of tubes and axially oriented TEE indications left in service, the projected accident leakage, and anr assessment of growth for TEE indications.

(conti nued)

Crystal River Unit 3 5.0-29 Amendment No. 2-2-2

Reporting Requirements 5.7 5.7 Reporting Requirements 5.7.2 Spe-ial Reports (continued)-

d. Results of OTSG tube inspections that fall into Category C 3 shall be reported to the NRC in a-cordance with 1.OCR.".72.

The complete results of the OTSG tube ie*.rvice inspection

-l.sure following restart. The report shall in-lude;

1. Number and extent of tubes inspe"ted,

2. Location and percent of wall thickness penetrctidn for each indication of an imperfection,

+-ýO'.'Location, bobbin coil amplitude, and axial and circumferential extent (if determined) for each first span IGA indication, and

4. Identification of tubes plugged repired and

.specification of the repair methodoloagy imnplementedfo 4lNumber of as-found and as-left tubes with TEC indications, number of as-found and as-left TEC indications, the number of as-found and as-left TEC indications as a function of tubesheet radius, the as-found, as-left, probability of detection and new TEC leakage for upper and lower tubesheet indications. An assessment of the adequacy of the predictive methodology in Addendum C to Topical Report BAW-2346P, Revision 0, including assessing the distribution of indications found in each OTSG to ensure the assumption regarding the similarity of the distribution of indications remain consistent from one cycle to the next and that the assumption of a linear increase in leak rate remain valid. Corrective actions in the event that the assessment indicates the assumptions can not be fully supported.

Crystal River Unit 3 5.0-29 Amendment No. 2-2-Z

PROGRESS ENERGY FLORIDA, INC.

CRYSTAL RIVER UNIT 3 DOCKET NUMBER 50-302 / LICENSE NUMBER DPR-72 LICENSE AMENDMENT REQUEST #264, REVISION 0 Application to Modify Improved Technical Specifications Regarding Steam Generator Tube Integrity ATTACHMENT C Proposed Improved Technical Specification Changes (Revision Bar Format)

TABLE OF CONTENTS 3.3 INSTRUMENTATION (conti nued) 3.3.11 Emergency Feedwater Initiation and Control (EFIC) System Instrumentation ................ 3.3-26 3.3.12 Emergency Feedwater Initiation and Control (EFIC) Manual Initiation ...................... 3.3-30 3.3.13 Emergency Feedwater Initiation and Control (EFIC) Automatic Actuation Logic ............. 3.3-32 3.3.14 Emergency Feedwater Initiation and Control (EFIC)-Emergency Feedwater (EFW) -Vector Valve Logic ................................... 3.3-34 3.3.15 Reactor Building (RB) Purge Isolation-High Radiation ..................................... 3.3-35 3.3.16 Control Room Isolation-High Radiation .......... 3.3-36 3.3.17 Post Accident Monitoring (PAM) Instrumentation.. 3.3-38 3.3.18 Remote Shutdown System .......................... 3.3-42 3.4 REACTOR COOLANT SYSTEM (RCS) .................... ... 3.4-1 3.4.1 RCS Pressure, Temperature, and Flow Departure from Nucleate Boiling (DNB) Limits ........ I 3.4-1 3.4.2 RCS Minimum Temperature for Criticality ...... I 3.4-3 3.4.3 RCS Pressure and Temperature (P/T) Limits .... i 3.4-4 3.4.4 RCS Loops-MODE 3 ...................... 3.4-6 3.4.5 RCS Loops-MODE 4 ...................... 3.4-8 3.4.6 RCS Loops-MODE 5, Loops Filled ........ 3.4-10 3.4.7 RCS Loops-MODE 5, Loops Not Filled .... 3.4-13 3.4.8 Pressurizer ......................... 3.4-15 3.4.9 Pressurizer Safety Valves .............. 3.4-17 3.4.10 Pressurizer Power Operated Relief Valve (PORV) 3.4-19 3.4.11 Low Temperature Overpressure Protection (LTOP) System .......................... 3.4-21 3.4.12 RCS Operational LEAKAGE ................ 3.4-22 3.4.13 RCS Pressure Isolation Valve (PIV) Leak*iae ...... 3.4-24 3.4.14 RCS Leakage Detection Instrumentation ........... 3.4-27 3.4.15 RCS Specific Activity ......................... 3.4-30 3.4.16 Steam Generator (OTSG) Tube Integrity ............ 3.4-34 I 3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS) ........ B D 3.5-1 3.5.1 Core Flood Tanks (CFTs) ................... B I 3.5-1 3.5.2 ECCS-Operating ........................... m I 3.5-4 3.5.3 ECCS-Shutdown ............................ B I 3.5-7 3.5.4 Borated Water Storage Tank (BWST) ......... m 3.5-9 3.6 CONTAINMENT SYSTEMS .................... ............ 3.6-1 3.6.1 Containment ........... ..... ..... ............ 3.6-1 3.6.2 Containment Air Locks .......... ............ 3.6-3 3.6.3 Containment Isolation Valves ........ ............ 3.6-8 3.6.4 Containment Pressure ..... ...... ............ 3.6-15 3.6.5 Containment Air Temperature ......... ............ 3.6-16 (conti nued)

Crystal River Unit 3 ii Amendment No.

TABLE OF CONTENTS B 3.3 INSTRUMENTATION (continued)

B 3.3.12 Emergency Feedwater Initiation and Control (EFIC) Manual Initiation ................... B 3.3-100 B 3.3.13 Emergency Feedwater Initiation and Control (EFIC) Automatic Actuation Logic ........... B 3.3-105 B 3.3.14 Emergency Feedwater Initiation and Control (EFIC)-Emergency Feedwater (EFW) -Vector Valve Logic ................................ B 3.3-110 B 3.3.15 Reactor Building (RB) Purge Isolation-High Radiation ............................... B 3.3-114 B 3.3.16 Control Room Isolation-High Radiation ........ B 3.3-119 B 3.3.17 Post Accident Monitoring (PAM) Instrumentation B 3.3-124 B 3.3.18 Remote Shutdown System ........................ B 3.3-145 B 3.4 REACTOR COOLANT SYSTEM (RCS) .................... B 3.4-1 B 3.4.1 RCS Pressure, Temperature, and Flow Departure from Nucleate Boiling (DNB) Limits .......... B 3.4-1 3.4.2 RCS Minimum Temperature for Criticality ........ B 3.4-6 3.4.3 RCS Pressure and Temperature (P/T) Limits ...... B 3.4-9 3.4.4 RCS Loops-MODE 3 .............................. B 3.4-17 3.4.5 RCS Loops-MODE 4 .............................. B 3.4-22 3.4.6 RCS Loops-MODE 5, Loops Filled ................ B 3.4-27 3.4.7 RCS Loops-MODE 5, Loops Not Filled ............ B 3.4-33 3.4.8 Pressurizer .................................... B 3.4-37 3.4.9 Pressurizer Safety Valves ...................... B 3.4-43 3.4.10 Pressurizer Power Operated Relief Valve (PORV). B 3.4-47 3.4.11 Low Temperature Overpressure Protection (LTOP) System .................................. B 3.4-52 3.4.12 RCS Operational LEAKAGE ...................... B 3.4-53 3.4.13 RCS Pressure Isolation Valve (PIV) Leakage ..... B 3.4-58 3.4.14 RCS Leakage Detection Instrumentation .......... B 3.4-65 3.4.15 RCS Specific Activity .......................... B 3.4-71 3.4.16 Steam!Generator (OTSG) Tube Integrity ........... B 3.4-75 I

3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS) ............. B 3.5-1 3.5.1 Core Flood Tanks (CFTs) ........................ B 3.5-1 3.5.2 ECCS - Ope rating ................................ B 3.5-9 3.5.3 ECCS-Shutdown ................................. B 3.5-20 3.5.4 Borated Water Storage Tank (BWST) .............. B 3.5-24 B 3.6 CONTAINMENT SYSTEMS ................................ B 3.6-1 B 3.6.1 Containment .............................. B 3.6-1 B 3.6.2 Containment Air Locks .......................... B 3.6-6 B 3.6.3 Containment Isolation Valves ................... B 3.6-15 B 3.6.4 Containment Pressure ........................... B 3.6-29 B 3.6.5 Containment Ai r Temperature ................... B 3.6-32 B 3.6.6 Reactor Building Spray and Containment Cooling Systems ............................. B 3.6-35 (conti nued)

Crystal River Unit 3 vi Amendment No.

Definitions 1.1 1.1 Definitions LEAKAGE 3. Reactor Coolant System (RCS) LEAKAGE (continued) through a steam generator to the secondary system (primary to secondary LEAKAGE). I

b. Unidentified LEAKAGE All LEAKAGE that is not identified LEAKAGE.

c. Pressure Boundary LEAKAGE LEAKAGE (except primary to secondary LEAKAGE) through a non-isolable fault in an RCS I

component body, pipe wall, or vessel wall.

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.

NUCLEAR HEAT FLUX HOT FQ (Z) shall be the maximum local linear power CHANNEL FACTOR (FQ(Z)) density in the core divided by the core average fuel rod linear power density, assuming nominal fuel pellet and fuel rod dimensions.

NUCLEAR ENTHALPY RISE FAH shall be the ratio of the integral of linear HOT CHANNEL FACTOR (F[) power along the fuel rod on which minimum departure from nucleate boiling ratio occurs to the average fuel rod power.

OPERABLE-OPERABILITY A system, subsystem, train, component, or device shall be OPERABLE when it is capable of performing its specified safety function(s) and when all necessary attendant instrumentation, controls, normal or emergency electrical power, cooling and seal water, lubrication and other auxiliary equipment that are required for the system, subsystem, train, component, or device to perform its specified safety function(s) are also capable of performing their related support function(s).

PHYSICS TESTS PHYSICS TESTS shall be those tests performed to measure the fundamental nuclear characteristics of the reactor core and related instrumentation.

(continued)

Crystal River Unit 3 1.1-5 Amendment No.

RCS Operational LEAKAGE 3.4.12 3.4 REACTOR COOLANT SYSTEM (RCS) 3.4.12 RCS Operational LEAKAGE LCO 3.4.12 RCS operational LEAKAGE shall be limited to:

a. No pressure boundary LEAKAGE;

b. 1 gpm unidentified LEAKAGE;

c. 10 gpm identified LEAKAGE; and

d. 150 gpd of primary to secondary LEAKAGE through any one steam generator (OTSG).

APPLICABILITY: MODES 1, 2, 3, and 4.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. RCS operational A.1 Reduce LEAKAGE to 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months LEAKAGE not within within limits.

limits for reasons other than pressure boundary LEAKAGE or primary to secondary LEAKAGE.

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 not met. AND OR 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.

OR Primary to secondary LEAKAGE not within limit.

Crystal River Unit 3 3.4-22 Amendment No.

RCS Operational LEAKAGE 3.4.12 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.12.1 ---------------- NOTES--------------------

1. Not required to be performed in MODE 4.

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

2. Not applicable to primary to secondary LEAKAGE.

Verify RCS operational LEAKAGE is within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months limits by performance of RCS water inventory balance.

SR 3.4.12.2 --------------- 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.

Verify primary to secondary LEAKAGE is

150 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months gallons per day through any one steam generator.

Crystal River Unit 3 3.4-23 Amendment No.

OTSG Tube Integrity 3.4.16 3.4 REACTOR COOLANT SYSTEM (RCS) 3.4.16 Steam Generator (OTSG) Tube Integrity LCO 3.4.16 OTSG tube integrity shall be maintained.

AND All OTSG 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

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

Separate Condition entry is allowed for each OTSG tube.

CONDITION REQUIRED ACTION COMPLETION TIME A. One or more OTSG A.1 Verify tube integrity 7 days tubes satisfying the of the affected tube repair criteria tube(s) is maintained and not plugged or until the next repaired in refueling outage or accordance with the OTSG tube inspection.

Steam Generator Program. AND A.2 Plug or repair the Prior to entering affected tube(s) in MODE 4 following accordance with the the next refueling Steam Generator outage or OTSG Program. 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 AND not met.

B.2 Be in MODE 5. 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months OR OTSG tube integrity not maintained.

Crystal River Unit 3 3.4-34 Amendment No.

OTSG Tube Integrity 3.4.16 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.16.1 Verify OTSG tube integrity in accordance In accordance with with the Steam Generator Program. the Steam Generator Program SR 3.4.16.2 Verify that each inspected OTSG tube that Prior to entering satisfies the tube repair criteria is MODE 4 following a plugged or repaired in accordance with the OTSG tube Steam Generator Program. inspection Crystal River Unit 3 3.4-35 Amendment No.

Procedures, Programs and Manuals 5.6 5.6 Procedures, Programs and Manuals 5.6.2.10 Steam Generator (OTSG) Program A Steam Generator Program shall be established and implemented to ensure that OTSG 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 OTSG inspection outage, as determined from the inservice inspection results or by other means, prior to the plugging or repair of tubes.

Condition monitoring assessments shall be conducted during each outage during which the OTSG tubes are inspected, plugged, or repaired to confirm that the performance criteria are being met.

b. Performance criteria for OTSG tube integrity. OTSG 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 i ncl uded i n the design speci fi cation) 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.

(continued)

Crystal River Unit 3 5.0-13 Amendment No.

Procedures, Programs and Manuals 5.6 5.6 Procedures, Programs and Manuals 5.6.2.10 OTSG Program (continued)

2. Accident induced leakage performance criterion: The primary to secondary accident induced leakage rate for any design basis accident, other than an OTSG tube rupture, shall not exceed the leakage rate assumed in the accident analysis in terms of total leakage rate for all OTSGs and leakage rate for an individual OTSG.

Leakage is not to exceed one gallon per minute per OTSG, except for specific types of degradation at specific locations as described in paragraph c of the Steam Generator Program.

3. The operational LEAKAGE performance criterion is specified in LCO 3.4.12, "RCS Operational LEAKAGE."

c. Provisions for OTSG tube repair criteria. Tubes found by inservice inspection to contain flaws with a depth equal to or exceeding 40% of the nominal tube wall thickness shall be plugged or repaired.

The following alternate tube repair criteria may be applied as an alternative to the 40% depth based criteria:

1. Inservice tubes with pit-like intergranular attack (IGA) indications in the first span of the B OTSG, identified in the OTSG Inservice Inspection Surveillance Procedure, must be inspected with bobbin and Motorized Rotating Pancake Coil (MRPC) eddy current techniques from the lower tube sheet secondary face to the bottom of the first tube support plate during each inservice inspection of the B OTSG. No credit is to be taken for this inspection in meeting minimum sample size requirements for the random inspection. Tubes found during this inspection that exceed the 40% of tube wall thickness repair criterion are to be plugged or sleeved. Degraded or defective tubes found during this inspection are not to be considered in determining the inspection results category for the random inspection, unless the degradation mechanism identified is a mechanism other than pit-like IGA.

(continued)

Crystal River Unit 3 5.0-14 Amendment No.

Procedures, Programs and Manuals 5.6 5.6 Procedures, Programs and Manuals 5.6.2.10 OTSG Program (continued)

2. Tubes in-service with axially oriented tube end cracks (TEC) are identified in the OTSG Inservice Inspection Surveillance procedure. The portion of the tube with the axial TEC must be inspected using the motorized rotating coil eddy current technique during each subsequent inspection. No credit is to be taken for this inspection for meeting the minimum sample size requirement for random sample inspection.

Tubes identified with TEC that meet the alternate repair criteria will be added to the existing list of tubes in the OTSG Inservice Inspection Surveillance procedure. Tubes identified with TEC during the previous inspection which meet the criteria to remain in-service will not be included when calculating the inspection category of the OTSG.

The inspection data for tubes with axially oriented TEC indications shall be compared to the previous inspection data to monitor the indications for growth.

Tubes with axially oriented TEC may be left in-service using the method described in Topical Report BAW-2346P, Revision 0, provided the combined projected leakage from all primary-to-secondary leakage, including axial TEC indications left in-service, does not exceed the Main Steam Line Break (MSLB) accident leakage limit of one gallon per minute, minus 150 gallons per day, per OTSG. The contribution to MSLB leakage rates from TEC indications shall be determined utilizing the methodology in Addendum B dated August 10, 2005 to Topical Report BAW-2346P, Revision 0. The projection of TEC leakage that may develop during the next operating cycle shall be determined using the methodology in Addendum C dated August 30, 2005 to Topical Report BAW-2346P, Revision 0.

If the plant is required to shut down due to primary-to-secondary leakage and the cause is determined to be degradation of the TEC portion of the tubes, 100% of the tubes with TEC in that OTSG shall be examined in the location of the TEC. If more than 1% of the examined tubes are defective, 100% of the tubes with TEC in the other OTSG shall be examined in the location of the TEC.

(continued)

Crystal River Unit 3 5.0-15 Amendment No.

Procedures, Programs and Manuals 5.6 5.6 Procedures, Programs and Manuals 5.6.2.10 OTSG Program (continued)

Tubes with crack-like indications within the carbon steel portion of the tubesheet shall be repaired or removed from service using the appropriate approved method. Tubes with circumferentially oriented TEC or volumetric indications within the Inconel clad region of the tubesheet shall be repaired or removed from service using the appropriate approved method.

d. Provisions for OTSG tube inspections. Periodic OTSG 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 0TSG tube integrity is maintained until the next OTSG inspection. An assessment of degradation shall be performed to determine the type and location of flaws to which the tubes may be susceptible and,'based on this assessment, to determine which inspection methods need to be employed and at what locations.

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

2. Inspect 100% of the tubes at sequential periods of 60 effective full power months. The first sequential period shall be considered to begin after the first inservice inspection of the OTSGs. No OTSG shall operate for more than 24 effective full power months or one refueling outage (whichever is less) without being inspected.

3. If crack indications are found in any OTSG tube, then the next inspection for each OTSG 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.

(continued)

Crystal River Unit 3 5.0-16 Amendment No.

Procedures, Programs and Manuals 5.6 5.6 Procedures, Programs and Manuals 5.6.2.10 OTSG Program (continued)

e. Provisions for monitoring operational primary to secondary LEAKAGE.

f. Provisions for OTSG tube repair methods. Steam generator tube repair methods shall provide the means to reestablish the RCS pressure boundary integrity of OTSG tubes without removing the tube from service. For the purposes of these Specifications, tube plugging is not a repair. All acceptable tube repair methods are listed below.

1. Sleeve installation in accordance with the B&W process (or method) described in report BAW-2120P. No more than five thousand sleeves may be installed in each OTSG.

2. Installation of repair rolls in the upper and lower tubesheets in accordance with BAW-2303P, Revision 4.

The repair process (single, overlapping, or multiple roll) may be performed in each tube. The repair roll area will be examined using eddy-current methods following installation. The repair roll must be free of imperfections and degradation for the repair to be considered acceptable.

The repair roll in each tube will be inspected during each subsequent inservice inspection while the tube with a repair roll is in service.

(continued)

Crystal River Unit 3 5.0-17 Amendment No.

Procedures, Programs and Manuals 5.6 THIS PAGE INTENTIONALLY LEFT BLANK Crystal River Unit 3 5.0-24 Amendment No.

Procedures, Programs and Manuals 5.6 THIS PAGE INTENTIONALLY LEFT BLANK Crystal River Unit 3 5.0-25 Amendment No.

Procedures, Programs and Manuals 5.6 THIS PAGE INTENTIONALLY LEFT BLANK Crystal River Unit 3 5.0-26 Amendment No.

Reporting Requirements 5.7 5.7 Reporting Requirements 5.7.1.2 Not Used 5.7.2 Special Reports Special Reports shall be submitted in accordance with 10 CFR 50.4 within the time period specified for each report.

The following Special Reports shall be submitted:

a. When a Special Report is required by Condition B or F of LCO 3.3.17, "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.

b. Any abnormal degradation of the containment structure found during the inspection performed in accordance with ITS 5.6.2.8 shall be reported to the NRC within 30 days of the current surveillance completion. The abnormal degradation shall be defined as findings such as delamination of the dome concrete, widespread corrosion of the liner plate, corrosion of prestressing elements (wires, strands, bars) or anchorage components extending to more than two tendons and group tendons force trends not meeting the requirements of 10CFR50.55a(b)(2)(ix)(B). The report shall include the description of degradation, operability determination, root cause determination and the corrective actions.

c. 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 5.6.2.10, Steam Generator (OTSG) Program. The report shall include:

1. The scope of inspections performed on each OTSG,

2. Active degradation mechanisms found,

3. Nondestructive examination techniques utilized for each deg radati on mechanism,

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

Crystal River Unit 3 5.0-28 Amendment No.

Reporting Requirements 5.7 5.7 Reporting Requirements 5.7.2 Special Reports (continued)

5. Number of tubes plugged or repaired during the inspection outage for each active degradation mechanism,

6. Total number and percentage of tubes plugged or repaired to date,

7. The results of condition monitoring, including the results of tube pulls and in-situ testing,

8. The effective plugging percentage for all plugging and tube repairs in each OTSG,

9. Repair method utilized and the number of tubes repaired by each repair method,

10. Location, bobbin coil amplitude, and axial and circumferential extent (if determined) for each first span IGA indication, and

11. Number of as-found and as-left tubes with TEC indications, number of as-found and as-left TEC indications, the number of as-found and as-left TEC indications as a function of tubesheet radius, the as-found, as-left, probability of detection and new TEC leakage for upper and lower tubesheet indications. An assessment of the adequacy of the predictive methodology in Addendum C to Topical Report BAW-2346P, Revision 0, including assessing the distribution of indications found in each OTSG to ensure the assumption regarding the similarity of the distribution of indications remain consistent from one cycle to the next and that the assumption of a linear increase in leak rate remain valid. Corrective actions in the event that the assessment indicates the assumptions can not be fully supported.

Crystal River Unit 3 5.0-29 Amendment No.

PROGRESS ENERGY FLORIDA, INC.

CRYSTAL RIVER UNIT 3 DOCKET NUMBER 50-302 / LICENSE NUMBER DPR-72 LICENSE AMENDMENT REQUEST #264, REVISION 0 Application to Modify Improved Technical Specifications Regarding Steam Generator Tube Integrity ATTACHMENT D Proposed Improved Technical Specification Bases Pages (Mark-up) gtf~eut teK indicates deleted text.

.h...edte . indicates added text.

RCS Operational LEAKAGE B 3.4.12 B 3.4 REACTOR COOLANT SYSTEM (RCS)

B 3.4.12 RCS Operational LEAKAGE BASES BACKGROUND During the life of the plant, the joint and valve interfaces contained in the RCS can produce varying amounts of reactor coolant LEAKAGE, through either normal operational wear or mechanical deterioration. The purpose of the RCS Operational LEAKAGE LCO is to limit system operation in the presence of LEAKAGE from these sources to amounts that do not compromise safety. This LCO specifies the types and amounts of LEAKAGE.

10 CFR 50, Appendix A, GDC 30 (Ref. 1), requires means for detecting and, to the extent practical, identifying the source of reactor coolant LEAKAGE. Regulatory Guide 1.45 (Ref. 2) describes acceptable methods for selecting leakage detection systems. OPERABILITY of the leakage detection systems is addressed in LCO 3.4.14, "RCS Leakage Detection Instrumentation."

The safety significance of RCS LEAKAGE varies widely depending on its source, rate, and duration. Therefore, detecting, monitoring, and quantifying reactor coolant LEAKAGE is critical. Quickly separating the identified LEAKAGE from the unidentified LEAKAGE is necessary to provide quantitative information to the operators, allowing them to take corrective action should a leak occur.

A limited amount of leakage inside containment is expected from auxiliary systems that cannot be made 100% leaktight.

Leakage from these systems should be detected, located, and isolated from the containment atmosphere, if possible, to not interfere with RCS leakage detection.

APPLICABLE Except for primary to secondary LEAKAGE, the safety analyses SAFETY ANALYSES do not address operational LEAKAGE. However, other operational LEAKAGE is related to the safety analyses for a LOCA in that 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 assumes 1 gp..primary to secondary LEAKAGE as the initial cndition.

(continued)

Crystal River Unit 3 B 3.4-53 Revision No. 10

RCS Operational LEAKAGE B 3.4.12 BASES APPLICABLE phay secohry LEARAGE from ;al steam generators SAFETY ANALYSES OTSGs) is one gallon per minute' or increases to one gallon (continued) er minute as a result of accident induced conditions. The CO requirement to limit primary to secondary LEAKAGE hrough any one OTSG to less than or equal to 150 gal6hi er day is significantly less. than, the conditions assumed in the saf~ty_ analysi~s;,

The FSAR (Ref. 3) analysis for steam generator tube rupture (SGTR) assumes the contaminated secondary fluid is only briefly released via safety valves and the majority is steamed to the condenser. The gpm primary to secondary LEAKAGE 64W yfassumptonq

- is relatively inconsequential in terms of offsite dose.

The safety analysis for the Steam Line Break (SLB) accident assumes khediire' 1 gpm primary to secondary LEAKAGE in one Dgfhrou*gh.the *e ff generator as an initial condition (Ref. 4). The dose consequences resulting from the SLB accident meet the acceptance criteria defined in 10 CFR 50.67.

RCS operational LEAKAGE satisfies Criterion 2 of the NRC Policy Statement.

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 in higher LEAKAGE.

Violation of this LCO could result in continued degradation of the reactor coolant pressure boundary (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 that the containment atmosphere and sump level monitoring equipment can detect within a reasonable time period.

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

(continued)

Crystal River Unit 3 B 3.4-54 Revision No. 37

RCS Operational LEAKAGE B 3.4.12 BASES LCO C. Identi fied LEAKAGE Up to 10 gpm of identified LEAKAGE is considered allowable because LEAKAGE is from known sources that do not interfere with the 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 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. - .... t . S eendarvy L-,,,G th u ,, A,,y O,,e Ste ,,,

.,This LEAKAGE limit is established to ensure that tubes initilyl*eakin, during normal operation do not a consiervative limit whih is eonsistent wit 12!

eet44.1 t

M I.*-I dena ......

d .= --- he 150..4.,*f.- ._J'* kl Critera C a h'as elected t19 voluntarily .d0pt t his conservative limit to esr plnt shutd*own n timel manrinrsnet detection of primary to i denti fied LEAKAG-E.

eqiement is mtbsaifigthe au-mented 2.1 ona-.

in vic i0).inse pect 2. equ re me ts f t eeSteam io Ge nratomra T e-u-6rnv-eil-lEEA Progr7 am(S eifc aOTio he operational LEAKAGE performance criterionL in;NEI 7-06, .Steam Generator Program Gui deli nes (Ref -.. 5)."

he Steam Generator-Program operational: ýLEAKAGE, erformance criterion nNEI;97-06 states, "TheWCS perational primary to secondary leakage through any ne SG'shall be6 limited to 150 gallons per day" The imit is based on operating experience with OTSG tube egradation mechanisms that result in tube leakage..

he operational leakage ra-te criterion in conjunctibri lith the implementation of :the, Steam Generator Prografij Saneffectiveneasure forl*mInimizin4 the frequencyof (conti nued)

Crystal River Unit 3 B 3.4-55 Revision No. 4

RCS Operational LEAKAGE B 3.4.12 BASES ACTIONS A.1 If unidentified LEAKAGET- identified LEAKAGE, or primary to secondary LEAKAGE are in excess of the LCO limits, the LEAKAGE 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.1 and B.2 If any pressure boundary LEAKAGE exists ýr Primar-y' to

ec LEAAEs not w-'it hinjiikj or i f uni denti fied r identified, or primary to secondary LEAKAGE cannot be 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 placed in a lower pressure condition to reduce the severity of the LEAKAGE and its potential consequences. The reactor must be placed in 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 stresses that tend to degrade the pressure boundary.

The Completion Times allowed are reasonable, based on operating experience, to reach the required 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 3.4.12.1 REQUIREMENTS Verifying RCS LEAKAGE within the LCO limits ensures that 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.

Unidentified LEAKAGE and identified LEAKAGE are determined by performance of an RCS water inventory balance. Pri-ma-ry to seondary LEAKAGE is also measured by performance of an RES water inventory blanc..e conjunction with efflue.t monitoring within the secondary steam and condensate systems.n (conti nued)

Crystal River Unit 3 B 3.4-56 Revision No. IG

RCS Operational LEAKAGE B 3.4.12 BASES SURVEILLANCE SR 3.4.12.1 (continued)

REQUIREMENTS The RCS water inventory balance must be performed with the reactor at steady state operating conditions and with RCS temperature greater than 4000 F. The test must be performed I prior to entry into MODE 2 if it has not been performed within the past 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months near normal operating pressure.

This surveillance is ioaifieaytwopotes.

Note. !states h is not required to be performed for entry into MODE 4 or MO*E 3. or for non-steady state conditions in MODE 3, but must be performed in MODE 3 above 400°F if 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months of steady state operation are achieved. If the test is not performed prior to all other requirements for entry into MODE 2 being satisfied, entry into MODE 2 must be delayed until steady state operation is established and the requirements of SR 3.0.4 are satisfied.

Steady state operation is required to perform a meaningful water inventory balance; calculations during maneuvering are not useful. 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 pump seal injection and return flows.

e2t2 tatas i S R i s nost -ap-pl! c e to primary; t jecondary LEAKAGE because LEAKAGE of 150 gallons per day inventory annot be eaýgsured accurately-by an, RCSwatr_

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

SR 3.4.12.2 This SR provides the means necessary to determine OTSG OPERABILITY' in an operational MODE. The requirement to demonstrate OTSG tube integrity in a.cordan.e with the Steam Generator Tube Surveillaneerogram emphasizes the importance of OTSG tube integrity, even though this Srveillance cannot be performed at normal operating enditionsr (continued)

Crystal River Unit 3 B 3.4-57 Revision No. 30

RCS Operational LEAKAGE B 3.4.12 BASES ihsRveHr ies that primary to secona Lt ,IS rless han or: equal to 150 gallons per day through any one OTSG.'

atisfying the primary to secondary LEAKAGE I mit ensures hat the operational LEAKAGE performance criterion in t*he team Generator Program is, met. Ifthis SR is not met, 6hmpli'ance with LCO 3.4.16,', Steam Generator Tube ntegrity," should be evaluated,. The 150 gallons per_ day imit is measured at room temperature as described in eference 6. The operational LEAKAGE rate limit applie-si ito

.AKAGE through any one OTSG.,If it is not practical to ssign the LEAKAGE to an individual OTSG, all the primary, tP-be secondary LEAKAGE should be conservativelyassumed-ror9mdPnle.j9TSG..

K6Sbr've i I Ian 'eI md if 1e-71by,"a- N6 -i- ihi~c h s' ta teIs that he Surveillance is not required to be performed until 12 ours after establishment of steady state operation. For CS primary to secondary LEAKAGE determination, steady tate is defined as stable RCS pressure, temperature,-power evel, pressurizer and makeup tank levels, makeup_ and .

1etowne.rand RCP seal injoo an I ows.;

e Su-6,r-v eI 1a n-ce Fr-eqii nicy of-T hf7ou6-rs - Ii >a-re-a-si n a b1 e trvlto trend iprimary to secondary LEAKAGE and ecognizes the importance of early leakage detection"n the 1revention of accidents., The primary to secondary LEAKAGE s determined using contihnuous process radiation monitorsi'

ýr radio6chemical grab samplin9_jjaccordance with the EURI REFERENCES 1. 10 CFR 50, Appendix A, GDC 30.

2. Regulatory Guide 1.45, May 1973.

3. FSAR, Section 14.2.2.2.

4. FSAR, Section 14.2.2.1.

ak Guodeljnes."

Crystal River Unit 3 B 3.4-58 Revision Amendment No. 149

~TSG~q, I#Weg ri ty S3416

~34~ RtOR COOLANTSYST1M1(RSY PI..a teamGn M. ~ o! TSG -u t~geý ty-VASES 0A GOUND 111 e rn i~-

genratr -(6TSCG)b7t6&ý-ari i-iI~T hin tiZ~&

Palled tubes that carry primary coolant through the pimary

,osecondary heat exchanges. The OTSG tubes have a number f important safety functions. Steam generator tubes are n integral part of the reactor coolant pressure boundary RCPB) and, as such, are relied on to maintain the primary ystem's pressure and inventory. The OTSG tubes isolate he radioactive fission products in the primary coolant

,rom the secondary system. :In addition, as part of the CPB, the OTSG tubes are.unique in that they act as the eat transfer surface between the primary andI secondary ystems to remove heat from ithe primary system. This Ipecification addresses only the RCPB integrity functi6ro-6&

he OTSG. The OTSG heat removal function is addressed by

ýCO 3.4.4', "RCS Loops - MODE 3 LCO 3.4.5, "RCSLolops -

ODE 4," LCO 3.4.6, "RCS Loops - MODE 5, Loops Filled," :iia s implicitly required in MODES 1 and 2 in order to preent AReactor Protection System 4ctuation (LC"934.

K'tiube fin6te-g- ty meansth`attetes arcapable of

.rforming their intended.RCPB safety function consisteht ith the icensinRg basi's,Z jIncl udi ri app i jAb _rguatr tea ene o ting is s ect to a varie egradation mechanisms. Steam generator tubes may xperience tube degradation related.to corrosion p.e.n.ena, uch as wastage, pitting, interg ranular attack, and stress orrosion cracking, along with other mechanically induced henomena such as denting and wear. These degradatioxi echanisms can impair tube integrity if they arenobt anaged effectively. The OTSG performancecrit*.ri*aiI sed to manage~S A4ýiq

-pf-it-fionf5-6. 2710F(-15)-"rgrrý

[equi res that a .program be established and implemented to nsure that OTSG tube integrity is maintained. Pursuant to pecification 5.6.2.10, .tube integrity is maintained .when-he`.0TSG performance criteria:are met. There are three performance criteria; structural i*ntegrity, accide) n'duced 1ý e,,,,Ld opýraj~aThe_~, OTSG (conti nued)

Crystal River Unit 3 B 3.4-75 Revision No. XX

OTSG Tube Integrity B 3.4.16 BASES BA-CKGRO-(rND ....p af cri-rtiieria -a.re--des'cri bedi*-Bi .n- 1ca.i...

.Spie&....

L ciUUed..)*p5.6.2.10. Meeting the OTSG performance citperiac Tprovion Peasonable assurance of maintaining-,tt.be* n'tegrity~a piorma1 and accident conditions.ý procses s use4a &omeet Se pormancet ria

ýre defined by 'heSteam GeDneatoyI'rogram Guiidelines KIPPLICA-LE ~The--s16am -g-e-h-rat6'io .tbe i r-u-p':thUF6(sctR &i-c-Te-tWf--thie-.

4AFETY, limiting design basis event for OTSG tubesand avoidinganh ALYSES ___ SGTR is the basis for this Specification. ýThe analysis of a SGTR event assumes a bounding primary to secondary EAKAGE rate equal to the operational LEAKAGE rate limits n LCO 3.4.12, "RCS Operational LEAKAGE," pl us the leakage

'ate associated with a*adouble-ended rupture of a single ube. The accident analysis for a SGTR assumes the

ontaminated secondary fluid is 0only briefly releasodto he atmosphere via safety valves a*the maipri .

isj'cf4arged to the main, conde11s9e,,- r I , an al y-sl s To r de's-'g-n- ba s is -a~ccid entis a~nja t ran-sien ts ther than a SGTR assume the OTSG tubes retain their tructural integrity' (i.e., they areI assumed not to

,upture)-. In these analyses, the steam discharge -to' the tmosphere is based on the total primary to secondary EAKAGE from all OTSGs of one gallon per minte or 'is ssumed to increase to one gallion per minute as a resul-Ifif ccident induced conditions. For accidents that do not nvolve fuel damage, the primary coolant activity levelbf O)SE EQUIVALENT I-131 -is assumed to be equal to the LCO

-. 4.15, RCS pecific Activity," l4mitsl For accidents hat assume fuel damage, 'the primary coolant activityjsj nction ýofthe 'mountof activity releastd from the amaged fuel. The dose consequences of these eventsa ithin the limits of GDC-19 (Ref. 2), 10 CFR 50.67 (Ref 3) r the NRC approved licens*ingJases (e,,g,.g .a smallTf racti o f.these- ,1ij-its)-,.

earn generator ftuely sat*eg*e syCri*eon 0 L4q`6i§7Vh tCWart-Vufr ub Thtg -YS r it e-n.i~ i iiii dI~

She LCO also requires.- that all OTSC tubes thatsatisfy tfhd

[epair criteria be pluggd or r an hqL5tea,,Generator. 'Program.

(continued)

Crystal River Unit 3 B 3.4-76 Revision No. XX

BASES

CO :: Dur~n`g`-`ani 0TGS nspe in,- any i:1nspect tu *at (conti nued)

satisfies the Steam Generator, Program repair critei is

.epaired or removed from service by plugging. If a tube vas determined to satisfy the repair criteria but'Lni lugged or repaired, the tuybe _ma still have tube 5ntegr"Jty.

e1icontet o:f this ipec* aton, an 01S, -tube As lefined

ube wall, as*and entire the any length

repairs made tube,

of totheit, including between the the tube-to-*

ubesheet weld at the tube inlet and the tube-to-tubesheet reld1.at,the tube outlet. The tube-to-tubesheet weldiisn f 0nsýdered ~part o9f-the tube.

o n 6TSG hubebias tube integrfty wnen it:s sties t e erformance criteria. 'The OTSG :performance: criteria are rOgram," and describe' acceptable OTSG tube performfei.;

he Steam Generator Program also provides ,the evaluati.oO rocess for determining* co*flfrmne*with e erformance1,criielria..

here are~t'he TCpif tac? e~~t~i~l Sntegrity, accident induced leakage, and operational EAKAGE. Failure to meet any one of these .criteria is

'onsideredfailure to me'et.the LCO.

ne strutu purall ntegrity: perormance r e oen piovi e.sj argin of safety against tube burst or collapse under ormal and accidenhtconditions, and ensures structura ntegri ty of the OTSG tubes -under all anti cipated ransients i'nclUded in the design specification. ITube urst is defined as, "The gross structural failur of th*e ube wall. The condition typically corresponds. to an nstable opening displacement (e.g.., opening Iarea increasegd n response to constant pressure) accompanied by ductile plastic) tearing of the tube material at the :ends of thi egradation.," Tube collapse is defi ned as, "For the6S load isplacement curve for a given structure, collapse occurs t the top of the load versus displacement., curve where the lope of the curve becomes .zero." The structural integrity erformance criterion provides gui dance on assessing loadsi hat have a significant effect on burst or collapse. In hat context, the term "significant" is defined as "Arh cci dent_1oadijg ~~n dition other than diffeeia oipssure (conti nued)

Revision No. XX B 3.4-77 Crystal River Unit 3 River Unit 3 B 3.4-77 Revision No. XX

OTSG Tube Integrity B 3.4.16 BASES

~isTons erea~~{ sin i~en t adiftio~n of slhtoacfs-a niued) in the assessment of the structural integrity performance riterion could cause a lower structural limit ,orý limiting urst/collapse condition to be established." Forýtqube rnntegrity evaluations, except for circumferential.

eegradation, axial thermal loads are classified -as econdary loads., For circumferential degradation, ie1.

assificationof axial thermal loads as primary or-,

econdary loads will be evaluated on a~case-by-case b~asis'.

Ihe 'divi sion between primary I and secondary classi ficati ons ill be based qq,, ad~i e ~~yssan/ ~es Ing.ý tikicurafl nteg~rý y requires t at e primarymembrane tress intensity in a tubeý ,not exceed the yield strengtfi or all ASME Code,* Section III, Service Level A (normal pbnormal p conditions),and perating conditions) -Service Level B-(upset ore, transients included in the desi'g__

pecification. This includes safety factors ,and applicEae esign basis loads based on ASME Code,Section III,.

Ubsection NBr (Ref. 4)adjrf euatoryGuide 1A~21 RRef .5.)

hat the a*sis acciprimary to secondary'LEAkAGE dent,: other caused by than :a SGTR, ii S.within desig6 th~e aacci den*

nalysis assumptions. The accident analysis assumes tha, ccident induced leakage does not:exceed one gallon per inute per OTSG, except for specific types of:degradatioin t specific locations where the NRC.has apProved greater*

ccident induced leakage. The accident induced leakage ate includes any primary to secOndary LEAKAGE existing nror to the accident in addition to:,primaryyto secondary

[EAKAGE induc~ed durin g!e.aacident.

h&"perat~ionai LEA1KAGlEr 6r~ rmne criterion prvie an

,bservable indicati on of OTSG tube condi tions dur,"i ng plant,,

,peration. The limit on operational LEAKAGE is cont'ained n:LCO 3.4.12,

-rimary ",RCS Operationalr LEAKAGE,` and' limi ts to secondaryLEAKAGE thhrough any one ',OTSG to I37 allons per day., This limit'iis based on the assumption hat a single crack leaking -hi-s amount would not propagate o a SGTR under the stress conditions of a LOCA or a main team line break. If:.this , amount- of ,.LEAKAGE ,is due to more han' one crack, the cracks' are 1heaove Cr pton is,conservativ -e (conti nued)

Crystal River Unit 3 B 3.4-78 Revision No. XX

OTSG Tube Integrity B 3.4.16 BASES

PpLICA IL dSte am generator tube integtriy is cnai enged wnenn the

ressure differential across the tubes is large. Large i fferential pressures across OTSG tubes ,ica'nrily: b

,xerienced in MODE 1 2, 3or 4.

S on~ns re ar es ch~[ Tng~ng n MO~DES*an*d 6

han during MODES 1, 2,-3, and 4. In MODES 5 and 6,.

jri-mary to secondary differential pressure is low,ý fresulting in*lower stressesand* reduced potential, fo6r ACTIORUS "Th m_ýdi fi e-&6%T--' Not-e-.cEa'r-fy'ing "tha-t the-a--j'5ýre6 onditions may ;be entered independently for each OTSGtub his is acceptable because the Required Actions provide ppropriate compensatory actions for each affected OTSG ube. Complying with the Required Actions may allow for_

ontinued operation, and subsequent affected OTSG tubes a:

ove~rned by subsequent Condition entry 4noM ica~tjon of stoci atedoýRReqi.red Acti ons Vf.'i ad A.2'

-onadl1on A rapplies ViiT is di cove eodthat:6one- or more TSG tubes examined in an inservice inspection satisfy the ube repair criteria but were not plugged or repaired inr ccorcance with the Steam Generator Program as required by R 3.4.16.2. An evaluation of OTSG tube integrity ofjthe ffectecl tube(s) must be made. Steam generator tube

.ntegrity is based on meeting the OTSG .performance c-riti*]er-ia escribed in the Steam Generator Progranm. The-OTSG-repair riteria define limits on OTSG tube degradation that allow or flaw *rowth between inspections whl.e still providing ssurance that the OTSG performance criteriia willcontjnq

,if an tube tube that be met.

0ohould In .order have been to determine plugged or repaired has .TSG ihtegrity7--

valuation must be completed that demonstrates that the SG performance criteriawill continue to be met unti 1I te ext refueling outageor OTSG-tube inspection.- .The tube ntegrity determination is based on the estimated, conditi{&n ff the tube at the :time the .is situation discovered and the stimated

ub e growth of the ' d e e degradationmý d prior to the next ,OTSG Ie-.... i _

ube inspection. If it is determined that tub-ejnre _gry

.snot being maiC d io(conti-A (conti nued)

Crystal River Unit 3 B 3.4-79 Revision No. XX

OTSG Tube Integrity B 3.4.16 BASES TIONS__ _* A.1 nd A.*(op72 i-6*)e.dY

&MTleo n1-Time dI7',Jdays is- iiffOicient to m.ril et .....

the aluation while minimizing the risk of plant operation ithk n OTSG ~tubhatm~ay no .have. itube, 1ntngrW ftheevlUation etermes tahat e a fected eetu7 ne dsii ube integrity, Required Action A.2 allows plant operation

,ocontinue untill the th next refueling i nspe~ctio0n outage' or iinterval cni OTSG nues"to*b~e nspection prvde

'upported by an operational assessment that reflects the ffected tubes. However,'the affected tube(s) must be lugged or repaired prior to enteri ng MODE 4 fol lowing the fext refueling outage or OTSG inspection. This Completion ime is acceptable since operation until the next

-- pectionfl1 5 i 'ted.y t e ..

_ratP.ionaas sepssment.

.i and B."2-

.t-he Requitred Actions 'an aTsiociatea womp 'Times, o rondition A are not met or if OTSG tube integrity is not pei~ng maintained, the-,reactor must be broughtj to MODE 3 bvithin 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and MODE 5 Within 36-hour.

I~h e ,ai dowei-d' etion i mes are reaso nable-, Dasedon

perating experience, to r reach the desired plant condtli'ons

~rom full pwrcnitions i~nan-orderly mianner. .a~d-withou y this SR and the Steam Generator Program. NEI- 97-06 team Generator Program Guidelines (Ref.1)and it*

eferenced EPRI Guidelines, establ shthe content ofihe team Generator Program. Use oIf, the -Steam:Generator rogram ensures that the inspection is approprate in8d nsseqj with acceptied indust~rY--prac1ti c-s uring OT*G inspecions a cond.t on. monitoring assessiit tubes is performed.

Pf the OTSGdetermines The condition m6nitor'ing lssessmenv the "as found" condition of ,the OTSd

-ubes'. The purpose *of the cbndition monitoring assessmenI that the OTSG performance criteria haveý itoensure beer et for the~preious opeIrating(o enjd (conti nued)

Crystal River Unit 3 B 3.4-80 Revision No. XX

~TSTue Integrity S34. 1,6 BASES Ff ITR FMFfNTq BASES ,Te-__tea-_Generatoi r Program dtrmi nes scope o- ihe, inspection and the methodts' uS ed :to determine whether the tubes contain. flaws satisfying the tube repair criteria" Enspection scope * (i.e., which tubes or areas of tubing ithin the OTSG are to be inspected) is a function of xisting and potential degradation locations. .The Ste enerator Program also specifies the inspection methods td e used to find potential degradation. Inspection methods re a function of degradation morphology, non-destructive xamination_,E technique capabilitiesj and inspection locati ons.

e.Steam*Generato rhem defnes Program Frequency o SR

.*4.16.1.The Frequency is determined by the operational ssessment and other limits in the OTSG examination' Juidelines (Ref. 6). -The Steam. Generator Program uses nnformation on existing degradati ons and growth rates to eetermine an inspectionFrequency that provides reasonabNh tsurance that the tubing will meet the OTSG performance riteria at the next scheduled inspection. In addition,ý Opecification 5.6.2.10 containsi prescriptive requi rementt 0oncerning inspection intervals -to. provide added assuraancle

hatl the OTSG performance criteria wjll be met between

~chedUl ed -Lnspepctions.ý

~R 3 4_.16:21 I n64 uing an S G -nspecti on, any ns pecteo',a,7 t a-t .

atisfies the Steam ,Generator Program -repair criteria is epai red or removed, from ervi ce by plu-gging.' The tube epair *c riteria delineated in Speci ficatiion 5.6.2.10_are intended to. ensure that tubes accepted for continued ervice satisfy the OTSG performance criteria with ll.owance for error in' the flaw..sizeI measurement 4anTi o-F uture flaw growth. In additionthe tube n ,conjunctionwith other elements of the Steam Generator repair criteriA rogram ensure that the OTSG performance cri teria willi'° ontinue .to be' met until the next ihspection df the subIikt ube(s). Reference 1 provides ,.guidaice for pe rformi n g_

perational assessments to .verify that the tubes remainin n s 1ervice will contiu to .etthe OT .

~epi rmetod asdesri edin the Steam GeneraoPrgm.

(conti nued)

Crystal River Unit 3 B 3.4-81 Revision No. XX

sG ub

-- Inte rii~

BASES e qunc f prior to ten er1oiTi f a Ot e rnspection'en~sures that the Surveillance has been complet-A

.d all1 tubes meeting the repair -criteria are ýplugged or pa'ir'ed prior to subjectingi the OTSG tubes to sInifian~t pi~m~ary to 5e~ondary presure diffe6rential.

97EERNCEt, "~--m'.e-e7d-trP-~ iines Y

~~~j~i* & '5 0',Appe 'di x AIP AN- 8il' aind -Ptessure Ve'ss-'el ction M."',

Soe,

ýub~sectjn. NB.

Tgulatory Guie 1J~.121, BTs r, uggi g 1

Ppraded Steam Generator Tubes1 ' _Aug4s 97~6'.

RI, res ri Water Reactor ~Steam Gene raor~

Crystal River Unit 3 B 3.4-82 Revision No. XX

PROGRESS ENERGY FLORIDA, INC.

CRYSTAL RIVER UNIT 3 DOCKET NUMBER 50-302 / LICENSE NUMBER DPR-72 LICENSE AMENDMENT REQUEST #264, REVISION 0 Application to Modify Improved Technical Specifications Regarding Steam Generator Tube Integrity ATTACHMENT E Proposed Improved Technical Specification Bases Pages (Revision Bar Format)

RCS Operational LEAKAGE B 3.4.12 B 3.4 REACTOR COOLANT SYSTEM (RCS)

B 3.4.12 RCS Operational LEAKAGE BASES BACKGROUND During the life of the plant, the joint and valve interfaces contained in the RCS can produce varying amounts of reactor coolant LEAKAGE, through either normal operational wear or mechanical deterioration. The purpose of the RCS Operational LEAKAGE LCO is to limit system operation in the presence of LEAKAGE from these sources to amounts that do not compromise safety. This LCO specifies the types and amounts of LEAKAGE.

10 CFR 50, Appendix A, GDC 30 (Ref. 1), requires means for detecting and, to the extent practical, identifying the source of reactor coolant LEAKAGE. Regulatory Guide 1.45 (Ref. 2) describes acceptable methods for selecting leakage detection systems. OPERABILITY of the leakage detection systems is addressed in LCO 3.4.14, "RCS Leakage Detection Instrumentation."

The safety significance of RCS LEAKAGE varies widely depending on its source, rate, and duration. Therefore, detecting, monitoring, and quantifying reactor coolant LEAKAGE is critical. Quickly separating the identified LEAKAGE from the unidentified LEAKAGE is necessary to provide quantitative information to the operators, allowing them to take corrective action should a leak occur.

A limited amount of leakage inside containment is expected from auxiliary systems that cannot be made 100% leaktight.

Leakage from these systems should be detected, located, and isolated from the containment atmosphere, if possible, to not interfere with RCS leakage detection.

APPLICABLE Except for primary to secondary LEAKAGE, the safety analyses SAFETY ANALYSES do not address operational LEAKAGE. However, other operational LEAKAGE is related to the safety analyses for a LOCA in that 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 assumes Inud (cont (conti nued)

Crystal River Unit 3 B 3.4-53 Revision No.

RCS Operational LEAKAGE B 3.4.12 BASES APPLICABLE that primary to secondary LEAKAGE from all steam generators SAFETY ANALYSES (OTSGs) is one gallon per minute or increases to one gallon (continued) per minute as a result of accident induced conditions. The LCO requirement to limit primary to secondary LEAKAGE through any one OTSG to less than or equal to 150 gallons per day is significantly less than the conditions assumed in the safety analysis.

The FSAR (Ref. 3) analysis for steam generator tube rupture (SGTR) assumes the contaminated secondary fluid is only briefly released via safety valves and the majority is steamed to the condenser. The 1 gpm primary to secondary LEAKAGE safety analysis assumption is relatively inconsequential in terms of offsite dose.

The safety analysis for the Steam Line Break (SLB) accident assumes the entire 1 gpm primary to secondary LEAKAGE is through the affected generator as an initial condition (Ref. 4). The dose consequences resulting from the SLB accident meet the acceptance criteria defined in 10 CFR 50.67.

RCS operational LEAKAGE satisfies Criterion 2 of the NRC Policy Statement.

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 in higher LEAKAGE.

Violation of this LCO could result in continued degradation of the reactor coolant pressure boundary (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 that the containment atmosphere and sump level monitoring equipment can detect within a reasonable time period.

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

(continued)

Crystal River Unit 3 B 3.4-54 Revision No.

RCS Operational LEAKAGE B 3.4.12 BASES LCO c. Identified LEAKAGE Up to 10 gpm of identified LEAKAGE is considered allowable because LEAKAGE is from known sources that do not interfere with the 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 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. Primary to Secondary LEAKAGE through Any One OTSG The limit of 150 gallons per day per OTSG is based on the operational LEAKAGE performance criterion in NEI 97-06, Steam Generator Program Guidelines (Ref. 5).

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 OTSG 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.

(continued)

Crystal River Unit 3 B 3.4-55 Revision No.

RCS Operational LEAKAGE B 3.4.12 BASES ACTIONS A.1 If unidentified LEAKAGE or identified LEAKAGE is in excess of the LCO limits, the LEAKAGE 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.1 and B.2 If any pressure boundary LEAKAGE exists or primary to secondary LEAKAGE is not within limits, or if unidentified or identified LEAKAGE cannot be 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 placed in a lower pressure condition to reduce the severity of the LEAKAGE and its potential consequences. The reactor must be placed in MODE 3 within 6 hours 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 stresses that tend to degrade the pressure boundary.

The Completion Times allowed are reasonable, based on operating experience, to reach the required 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 3.4.12.1 REQUIREMENTS Verifying RCS LEAKAGE within the LCO limits ensures that 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.

Unidentified LEAKAGE and identified LEAKAGE are determined by performance of an RCS water inventory balance.

(conti nued)

Crystal River Unit 3 B 3.4-56 Revi sion No.

RCS Operational LEAKAGE B 3.4.12 BASES SURVEILLANCE SR 3.4.12.1 (continued)

REQUIREMENTS The RCS water inventory balance must be performed with the reactor at steady state operating conditions and with RCS temperature greater than 400°F. The test must be performed prior to entry into MODE 2 if it has not been performed within the past 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months near normal operating pressure.

This surveillance is modified by two notes. Note 1 states that it is not required to be performed for entry into MODE 4 or for non-steady state conditions in MODE 3, but must be performed in MODE 3 above 400°F if 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months of steady state operation are achieved. If the test is not performed prior to all other requirements for entry into MODE 2 being satisfied, entry into MODE 2 must be delayed until steady state operation is established and the requirements of SR 3.0.4 are satisfied.

Steady state operation is required to perform a meaningful water inventory balance; calculations during maneuvering are not useful. 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 pump seal injection and return flows.

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.

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

SR 3.4.12.2 This SR verifies that primary to secondary LEAKAGE is less than or equal to 150 gallons per day through any one OTSG.

Satisfying the primary to secondary LEAKAGE limit ensures that the operational LEAKAGE performance criterion in the Steam Generator Program is met. If this SR is not met, compliance with LCO 3.4.16, "Steam Generator Tube Integrity," should be evaluated. The 150 gallons per day limit is measured at room temperature as described in Reference 6. The operational LEAKAGE rate limit applies to (continued)

Crystal River Unit 3 B 3.4-57 Revision No.

RCS Operational LEAKAGE B 3.4.12 BASES SURVEILLANCE SR 3.4.12.2 (continued)

REQUIREMENTS LEAKAGE through any one OTSG. If it is not practical to assign the LEAKAGE to an individual OTSG, all the primary to secondary LEAKAGE should be conservatively assumed to be from one OTSG.

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. 6).

REFERENCES 1. 10 CFR 50, Appendix A, GDC 30.

2. Regulatory Guide 1.45, May 1973.

3. FSAR, Section 14.2.2.2.

4. FSAR, Section 14.2.2.1.

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

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

Crystal River Unit 3 B 3.4-58 Revision No.

OTSG Tube Integrity B 3.4.16 B 3.4 REACTOR COOLANT SYSTEM (RCS)

B 3.4.16 Steam Generator (OTSG) Tube Integrity BASES BACKGROUND Steam generator (OTSG) tubes are small diameter, thin walled tubes that carry primary coolant through the primary to secondary heat exchanges. The OTSG 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 OTSG tubes isolate the radioactive fission products in the primary coolant from the secondary system. In addition, as part of the RCPB, the OTSG 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 OTSG. The OTSG heat removal function is addressed by LCO 3.4.4, "RCS Loops - MODE 3," LCO 3.4.5, "RCS Loops -

MODE 4," LCO 3.4.6, "RCS Loops - MODE 5, Loops Filled," and is implicitly required in MODES 1 and 2 in order to prevent a Reactor Protection System actuation (LCO 3.3.1).

OTSG 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 OTSG performance criteria are used to manage OTSG tube degradation.

Specification 5.6.2.10, "Steam Generator (OTSG) Program,"

requires that a program be established and implemented to ensure that OTSG tube integrity is maintained. Pursuant to Specification 5.6.2.10, tube integrity is maintained when the OTSG performance criteria are met. There are three OTSG performance criteria: structural integrity, accident induced leakage, and operational LEAKAGE.

(continued)

Crystal River Unit 3 B 3.4-75 Revision No.

OTSG Tube Integrity B 3.4.16 BASES BACKGROUND The OTSG performance criteria are described in (continued) Specification 5.6.2.10. Meeting the OTSG performance criteria provides reasonable assurance of maintaining tube integrity at normal and accident conditions.

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

APPLICABLE The steam generator tube rupture (SGTR) accident is the SAFETY limiting design basis event for OTSG tubes and avoiding an ANALYSES 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 3.4.12, "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 is only briefly released to the atmosphere via safety valves and the majority is discharged to the main condenser.

The analysis for design basis accidents and transients other than a SGTR assume the OTSG 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 OTSGs of one gallon per minute or is assumed to increase to one gallon per minute as 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 3.4.15, "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 50.67 (Ref. 3) or the NRC approved licensing bases (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 OTSG tube integrity be maintained.

The LCO also requires that all OTSG tubes that satisfy the repair criteria be plugged or repaired in accordance with the Steam Generator Program.

(continued)

Crystal River Unit 3 B 3.4-76 Revision No.

OTSG Tube Integrity B 3.4.16 BASES LCO During an OTSG inspection, any inspected tube that (continued) satisfies the Steam Generator Program repair criteria is repaired or removed from service by plugging. If a tube was determined to satisfy the repair criteria but was not plugged or repaired, the tube may still have tube integrity.

In the context of this Specification, an OTSG tube is defined as the entire length of the tube, including the tube wall and any repairs made to 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 the tube.

An OTSG tube has tube integrity when it satisfies the OTSG performance criteria. The OTSG performance criteria are defined in Specification 5.6.2.10, "Steam Generator Program," and describe acceptable OTSG tube performance.

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

There are three OTSG 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 OTSG 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 (continued)

Crystal River Unit 3 B 3.4-77 Revision No.

OTSG Tube Integrity B 3.4.16 BASES LCO is considered significant when the addition of such loads (continued) 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 one gallon per minute per OTSG, except for specific types of degradation at specific locations where the NRC has approved greater accident induced leakage. The 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.

The operational LEAKAGE performance criterion provides an observable indication of OTSG tube conditions during plant operation. The limit on operational LEAKAGE is contained in LCO 3.4.12, "RCS Operational LEAKAGE," and limits primary to secondary LEAKAGE through any one OTSG 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.

(continued)

Crystal River Unit 3 B 3.4-78 Revision No.

OTSG Tube Integrity B 3.4.16 BASES APPLICABILITY Steam generator tube integrity is challenged when the pressure differential across the tubes is large. Large differential pressures across OTSG 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 OTSG tube.

This is acceptable because the Required Actions provide appropriate compensatory actions for each affected OTSG tube. Complying with the Required Actions may allow for continued operation, and subsequent affected OTSG 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 OTSG tubes examined in an inservice inspection satisfy the tube repair criteria but were not plugged or repaired in accordance with the Steam Generator Program as required by SR 3.4.16.2. An evaluation of OTSG tube integrity of the affected tube(s) must be made. Steam generator tube integrity is based on meeting the OTSG performance criteria described in the Steam Generator Program. The OTSG repair criteria define limits on OTSG tube degradation that allow for flaw growth between inspections while still providing assurance that the OTSG performance criteria will continue to be met. In order to determine if an OTSG tube that should have been plugged or repaired has tube integrity, an evaluation must be completed that demonstrates that the OTSG performance criteria will continue to be met until the next refueling outage or OTSG 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 OTSG tube inspection. If it is determined that tube integrity is not being maintained, Condition B applies.

(conti nued)

Crystal River Unit 3 B 3.4-79 Revision No.

OTSG Tube Integrity B 3.4.16 BASES ACTIONS A.1 and A.2 (continued)

A Completion Time of 7 days is sufficient to complete the evaluation while minimizing the risk of plant operation with an OTSG 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 OTSG 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 or repaired prior to entering MODE 4 following the next refueling outage or OTSG 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 OTSG 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 SR 3.4.16.1 REQUIREMENTS During shutdown periods the OTSGs 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 OTSG inspections a condition monitoring assessment of the OTSG tubes is performed. The condition monitoring assessment determines the "as found" condition of the OTSG tubes. The purpose of the condition monitoring assessment is to ensure that the OTSG performance criteria have been met for the previous operating period.

(conti nued)

Crystal River Unit 3 B 3.4-80 Revision No.

OTSG Tube Integrity B 3.4.16 BASES SURVEILLANCE SR 3.4.16.1 (continued)

REQUIREMENTS 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 OTSG 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.

The Steam Generator Program defines the Frequency of SR 3.4.16.1. The Frequency is determined by the operational assessment and other limits in the OTSG 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 OTSG performance criteria at the next scheduled inspection. In addition, Specification 5.6.2.10 contains prescriptive requirements concerning inspection intervals to provide added assurance that the OTSG performance criteria will be met between scheduled inspections.

SR 3.4.16.2 During an OTSG inspection, any inspected tube that satisfies the Steam Generator Program repair criteria is repaired or removed from service by plugging. The tube repair criteria delineated in Specification 5.6.2.10 are intended to ensure that tubes accepted for continued service satisfy the OTSG 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 OTSG 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 OTSG performance criteria.

Steam generator repairs are only performed using approved repair methods as described in the Steam Generator Program.

(continued)

Crystal River Unit 3 B 3.4-81 Revi sion No.

OTSG Tube Integrity B 3.4.16 BASES SURVEILLANCE SR 3.4.16.2 (continued)

REQUIREMENTS The Frequency of prior to entering MODE 4 following a OTSG inspection ensures that the Surveillance has been completed and all tubes meeting the repair criteria are plugged or repaired prior to subjecting the OTSG tubes to significant primary to secondary pressure differential.

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

2. 10 CFR 50 Appendix A, GDC 19.

3. 10 CFR 50.67.

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 Exami nation Gui deli nes."

Crystal River Unit 3 B 3.4-82 Revision No.

3F0506-03, License Amendment Request 264, Revision 0, Application to Modify Improved Technical Specifications Regarding Steam Generator Tube Integrity

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Text

Subject:

References:

Dear Sir:

1.0 INTRODUCTION

2.0 DESCRIPTION

3.0 BACKGROUND

5.0 TECHNICAL ANALYSIS

6.0 REGULATORY ANALYSIS

10.0 REFERENCES

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3F0506-03, License Amendment Request 264, Revision 0, Application to Modify Improved Technical Specifications Regarding Steam Generator Tube Integrity

Text

Subject:

References:

Dear Sir:

1.0 INTRODUCTION

2.0 DESCRIPTION

3.0 BACKGROUND

5.0 TECHNICAL ANALYSIS

6.0 REGULATORY ANALYSIS

10.0 REFERENCES

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