Text

License Amendment Request: Technical Specification Improvement Regarding Steam Generator Tube Integrity Using the Consolidated Line Item Improvement Process
	ML051990345
Person / Time
Site:	Calvert Cliffs
Issue date:	07/13/2005
From:	Vanderheyden G; Constellation Energy Group
To:	; Document Control Desk, Office of Nuclear Reactor Regulation
References
	TAC M97855, TAC M97856
	Download: ML051990345 (46)
	v • d • e

I.

George Vanderheyden 1650 Calvert Cliffs Parkway Vice President Lusby, Maryland 20657 Calvert Cliffs Nuclear Power Plant 410.495.4455 Constellation Generation Group, LLC 410.495.3500 Fax 6I Constellation Energy July 13, 2005 U. S. Nuclear Regulatory Commission Washington, DC 20555 ATTENTION: Document Control Desk

SUBJECT:

Calvert Cliffs Nuclear Power Plant Unit Nos. I & 2; Docket Nos. 50-317 & 50-318 License Amendment Request: Technical Specification Improvement Regarding Steam Generator Tube Integrity Using the Consolidated Line Item Improvement Process Pursuant to 10 CFR 50.90, Calvert Cliffs Nuclear Power Plant, Inc. requests an amendment to Renewed Operating License Nos. DPR-53 and DPR-69. The proposed amendment would revise the Technical Specification requirements related to steam generator tube integrity. The change is consistent with Nuclear Regulatory Commission-approved Revision 4 to Technical Specification Task Force (TSTF)

Standard Technical Specification Change Traveler, TSTF-449, "Steam Generator Tube Integrity." The availability of this Technical Specification improvement was announced in the Federal Register on May 6, 2005 (70 FR 24126) as part of the consolidated line item improvement process.

Attachment (1) provides a description of the proposed change and confirmation of applicability.

Attachment (2) provides the existing TS pages marked up to show the proposed change.

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

We request approval of the proposed change as soon as possible and not later than December 6, 2005 to allow for changes in steam generator tube inspection requirements during the 2006 refueling outage.

These changes include addressing contractual and procedural issues and therefore, we request an implementation period of 60 days.

Document Control Desk July 13, 2005 Page 2 Should you have questions regarding this matter, please contact Mr. L. S. Larragoite at (410) 4954922.

Very trul STATE OF MARYLAND :

TO WIT:

COUNTY OF CALVERT :

1, George Vanderheyden, being duly sworn, state that I am Vice President - Calvert Cliffs Nuclear Power Plant, Inc. (CCNPP), and that I am duly authorized to execute and file this License Amendment Request on behalf of CCNPP. To the best of my knowledge and belief, the statements contained in this document are true and correct. To the extent that these statements are not based on Ty personal knowledge, they are based upon information provided by other CCNPP employees and/or onsultants. Such information has been reviewed in accordance with company practice and I bel it e reliable.

Suspcribd and qworn before me a Notary,Pii in and for the State of Maryland and County of B this /3 day of S 7 . 2005.

WiTNESS my Hand and Notarial Seal:

Notary Publi MCm .i - Epe My Commission Expires: - Date 600Z

{ Date GV/GT/bjd Attachments: (I) Description and Assessment (2) Proposed Technical Specification Changes cc: P. D. Milano, NRC Resident Inspector, NRC S. J. Collins, NRC R. I. McLean, DNR

ATTACHMENT (1)

DESCRIPTION AND ASSESSMENT TABLE OF CONTENTS

1.0 INTRODUCTION

2.0 PROPOSED CHANGE

3.0 BACKGROUND

4.0 REGULATORY REQUIREMENT AND GUIDANCE

5.0 TECHNICAL ANALYSIS

6.0 REGULATORY ANALYSIS

7.0 NO SIGNIFICANT HAZARDS EVALUATION 8.0 ENVIRONMENTAL EVALUATION 9.0 PRECEDENT

10.0 REFERENCES

Calvcrt Cliffs Nuclear Power Plant, Inc.

July 13,2005

ATTACHMENT (1)

DESCRIPTION AND ASSESSMENT

1.0 INTRODUCTION

The proposed license amendment revises the requirements in the Technical Specification (TS) related to steam generator tube integrity. The changes are consistent with Nuclear Regulatory Commission (NRC)-

approved Technical Specification Task Force (TSTF) Standard Technical Specification Change Traveler, TSTF-449, "Steam Generator Tube Integrity," Revision 4. The availability of this Technical Specification improvement was announced in the Federal Register on May 6, 2005 (70 FR 24126), as part of the consolidated line item improvement process (CLIIP).

2.0 PROPOSED CHANGE

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

Revised TS 1.1, definition of LEAKAGE

Revised TS 3.4.13, "RCS [Reactor Coolant System] Operational Leakage" Exception to TSTF-449, Revision 4 approved changes:

1. The current primary to secondary operational LEAKAGE limit of 100 gallons per day (gpd)/steam generator (SG) is already lower than the TSTF approved limit of 150 gpd/SG; therefore, it has not been changed.

2. For Surveillance Requirement (SR) 3.4.13.1, Note I has been added to be consistent with TSTF-449 approved Note for SR 3.4.13.2.

3. For SR 3.4.13.2, the LEAKAGE verification is for *100 gpd/SG, consistent with the limit in Item I above.

New TS 3.4.18, "Steam Generator (SG) Tube Integrity"

Revised TS 5.5.9, "Steam Generator Tube Surveillance Program"

Revised TS 5.6.9, "Steam Generator Tube Inspection Report"

Revised Table of Content pages to reflect the proposed changes above Proposed revisions to the TS Bases are also included in this application. Adjustments to the TSTF-449, Revision 4 approved Bases have been made to reflect the exceptions noted above. In addition, the Basis for the new TS 3.4.18 has been modified to incorporate plant specific information on steam generator tube rupture accident analysis. As discussed in the NRC's model safety evaluation, adoption of the revised TS Bases associated with TSTF-449, Revision 4 is an integral part of implementing this TS improvement.

The changes to the affected TS Bases pages will be incorporated in accordance with TS 5.5.14, Technical Specification 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 REOUIREMENTS 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.

I I

ATTACHMENT (1)

DESCRIPTION AND ASSESSMENT

5.0 TECHNICAL ANALYSIS

Calvert Cliffs Nuclear Power Plant, Inc. has reviewed the safety evaluation (SE) published on March 2, 2005 (70 FR 10298) as part of the CLIIP Notice for Comment. This included the NRC staffs SE, the supporting information provided to support TSTF449, and the changes associated with Revision 4 to TSTF-449. Calvert Cliffs Nuclear Power Plant, Inc. has concluded that the justifications presented in the TSTF proposal and the SE prepared by the NRC staff are applicable to Calvert Cliffs Units 1 and 2, and justify this amendment for the incorporation of the changes to the Calvert Cliffs TS. The only notable exception is the RCS operational primary to secondary LEAKAGE limit. The current Calvert Cliffs TS limit of 100 gpd/SG operational primary to secondary LEAKAGE is based on the current licensing basis for safety analysis assumptions approved in Reference 1. Hence, the less restrictive operational LEAKAGE limit of 150 gpd/SG approved in TSTF-449 has not been adopted.

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. Calvert Cliffs Units 1 and 2 Steam Generator Model(s): Babcock & Wilcox Replacement Steam Generators Effective Full Power Years (EFPY) of service Unit 1 1.76- 2004 refueling outage for currently installed SGs Unit 2 1.82 - 2005 refueling outage Tubing Material (e.g., 600M, 600TT, 660TT) 69017' Number of tubes per SG 8,471 Number and percentage of tubes plugged in Unit 1 SG 11 - 0 (0.00%), SG 12 - 0 (0.00%)

each SG Unit 2 SG 21 - 3 (0.04%), SG 22 - 29 (0.34%)

Number of tubes repaired in each SG Unit 1 SG 11 -0, SG 12-0 Unit 2 SG 21 - 0, SG 22 - 0 Degradation mechanism(s) identified 1. Upper bundle fan bar support wear

2. Loose part wear Current primary-to-secondary leakage limits: TS Criteria at room temperature:

No pressure boundary leakage

1 gpm unidentified leakage

10 gpm identified leakage

100 gpd primary to secondary leakage through any one SG Approved Alternate Tube Repair Criteria None Approved SG Tube Repair Methods None Performance criteria for accident leakage Primary to secondary leak rate values assumed in licensing basis accident analysis is 100 gpd per SG at room temperature conditions (Reference 1) 7.0 NO SIGNIFICANT HAZARDS EVALUATION Calvert Cliffs Nuclear Power Plant, Inc. has reviewed the proposed no significant hazards consideration determination published on March 2, 2005 (70 FR 10298) as part of the CLIIP. Calvert Cliffs Nuclear 2

ATTACHMENT (1)

DESCRIPTION AND ASSESSMENT Power Plant, Inc. has concluded that the proposed determination presented in the notice is applicable to Calvert Cliffs and the determination is hereby incorporated by Reference (2) to satisfy the requirements of 10 CFR 50.91(a).

8.0 ENVIRONMENTAL EVALUATION Calvert Cliffs Nuclear Power Plant, Inc. has reviewed the environmental evaluation included in the model SE published on March 2, 2005 (70 FR 10298) as part of the CLIIP. Calvert Cliffs Nuclear Power Plant, Inc. has concluded that the staff's findings presented in that evaluation are applicable to Calvert Cliffs and the evaluation is hereby incorporated by Reference (2) for this application.

9.0 PRECEDENT This application is being made in accordance with the CLIIP. Calvert Cliffs Nuclear Power Plant, Inc. is not proposing variations or deviations from the TS changes described in TSTF-449, Revision 4 (except as noted in Sections 2 and 5 above), or the NRC staffs model SE published on March 2, 2005 (70 FR 10298).

10.0 REFERENCES

1. Letter from Mr. A. W. Dromerick (NRC) to Mr. C. H. Cruse (BGE), dated May 23, 1998, "Issuance of Amendments for Calvert Cliffs Nuclear Power Plant Unit No. I (TAC No. M97855) and Unit No. 2 (TAC No. M97856)

2. Federal Register Notices:

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

Notice of Availability published on May 6, 2005 (70 FR 24126) 3

ATTACHMENT (2)

PROPOSED TECHNICAL SPECIFICATION CHANGES Mark-up Technical Specification Pages ii and iv 1.1-4 3.4.13-1 and 3.4.13-2 NEW 3.4-18-1 and 3.4.18-2 5.5-7 through 5.5-16 5.6-10 Bases Page ii B 3.4.4-2 B 3.4.5-3 B 3.4.6-3 B 3.4.7-4 B 3.4.13-2 through B 3.4.13-5 NEW B 3.4.18-1 through B 3.4.18-8 Calvert Cliffs Nuclear Power Plant, Inc.

July 13,2005

i TABLE OF CONTENTS 3.3.4 Engineered Safety Features Actuation System (ESFAS) Instrumentation ......... ............... 3.3.4-1 3.3.5 Engineered Safety Features Actuation System (ESFAS) Logic and Manual Actuation ....... ...... 3.3.5-1 3.3.6 Diesel Generator (DG)-Loss of Voltage Start (LOVS) .3.3.6-1 3.3.7 Containment Radiation Signal (CRS) .3.3.7-1 3.3.8 Control Room Recirculation Signal (CRRS) .3.3.8-1 3.3.9 Chemical and Volume Control System (CVCS)

Isolation Signal .3.3.9-1 3.3.10 Post-Accident Monitoring (PAM) Instrumentation . 3.3.10-1 3.3.11 Remote Shutdown Instrumentation .3.3.11-1 3.3.12 Wide Range Logarithmic Neutron Flux Monitor Channels .3.3.12-1 3.4 REACTOR COOLANT SYSTEM (RCS) .3.4.1-1 3.4.1 RCS Pressure, Temperature, and Flow Departure from Nucleate Boiling (DNB) Limits ....... ........... 3.4.1-1 3.4.2 RCS Minimum Temperature for Criticality ............ 3.4.2-1 3.4.3 RCS Pressure and Temperature (P/T) Limits .......... 3.4.3-1 3.4.4 RCS Loops - MODES 1 and 2 ........ ................. 3.4.4-1 3.4.5 RCS Loops - MODE 3 ............ .................... 3.4.5-1 3.4.6 RCS Loops - MODE 4 ............ .................... 3.4.6-1 3.4.7 RCS Loops - MODE 5, Loops Filled ...... ............ 3.4.7-1 3.4.8 RCS Loops - MODE 5, Loops Not Filled ...... ........ 3.4.8-1 3.4.9 Pressurizer ........................................ 3.4.9-1 3.4.10 Pressurizer Safety Valves .......................... 3.4.10-1 3.4.11 Pressurizer Power-Operated Relief Valves (PORVs) ... 3.4.11-1 3.4.12 Low Temperature Overpressure Protection (LTOP)

System ........................................ 3.4.12-1 3.4.13 RCS Operational LEAKAGE ............................ 3.4.13-1 3.4.14 RCS Leakage Detection Instrumentation .............. 3.4.14-1 3.4.15 RCS Specific Activity .............................. 3.4.15-1 3.4.16 Special Test Exception (STE) RCS Loops - MODE 2 .... 3.4.16-1 3.4.17 Special Test Exception (STE) RCS Loops - MODES 4 3.5.1 Safety Injection Tanks (SITs) ...................... 3.5.1-1 3.5.2 ECCS-Operating .................................... 3.5.2-1 3.5.3 ECCS-Shutdown ..................................... 3.5.3-1 3.5.4 Refueling Water Tank (RWT) ......................... 3.5.4-1 CALVERT CLIFFS - UNIT 1 ii Amendment No.-229-CALVERT CLIFFS - UNIT 2 Amendment No..2.04-

TABLE OF CONTENTS 3.8.8 Inverters-Shutdown ........... ..................... 3.8.8-1 3.8.9 Distribution Systems-Operating ...... .............. 3.8.9-1 3.8.10 Distribution Systems-Shutdown ....... .............. 3.8.10-1 3.9 REFUELING OPERATIONS ................................... 3.9.1-1 3.9.1 Boron Concentration ................................ 3.9.1-1 3.9.2 Nuclear Instrumentation ............................ 3.9.2-1 3.9.3 Containment Penetrations ........................... 3.9.3-1 3.9.4 Shutdown Cooling (SDC) and Coolant Circulation-High Water Level .... 3.9.4-1 3.9.5 Shutdown Cooling (SDC) and Coolant Circulation-Low Water Level ........... ..................... 3.9.5-1 3.9.6 Refueling Pool Water Level ......................... 3.9.6-1 4.0 DESIGN FEATURES ............................................ 4.0-1 4.1 Site Location .......................................... 4.0-1 4.2 Reactor Core ........................................... 4.0-1 4.3 Fuel Storage ........................................... 4.0-2 5.0 ADMINISTRATIVE CONTROLS .................................... 5.1-1.

5.1 Responsibility......................................... 5.1-1 5.2 Organization ........................................... 5.2-1 5.2.1 Onsite and Offsite Organizations ................... 5.2-1 5.2.2 Unit Staff ......................................... 5.2-2 5.3 Unit Staff Qualifications .............................. 5.3-1 5.4 Procedures ............................................. 5.4-1 5.5 Programs and Manuals ................................... 5.5-1 5.5.1 Offsite Dose Calculation Manual .................... 5.5-1 5.5.2 Primary Coolant Sources Outside Containment ........ 5.5-2 5.5.3 Not Used ........................................... 5.5-2 5.5.4 Radioactive Effluent Controls Program .............. 5.5-2 5.5.5 Component Cyclic or Transient Limit ................ 5.5-5 5.5.6 Concrete Containment Tendon Surveillance program... 5.5-6 5.5.7 Reactor Coolant Pump Flywheel Inspection Program... 5.5-6 5.5.8 Inservice T. Pro m.. .in 5.5-6 5.5.9 ( Steam Generator Survcillancz Tubc Program .. 5.5-7 5.5.10 Secondary Watergra .................. 5.5-17 5.5.11 Ventilation Filter Testing Program ................. 5.5-17 5.5.12 Explosive Gas and Storage Tank Radioactivity Monitoring Program ............. ................ 5.5-20 5.5.13 Diesel Fuel Oil Testing Program .................... 5.5-21 5.5.14 Technical Specifications Bases Control Program ..... 5.5-21 CALVERT CLIFFS - UNIT 1 iv Amendment No. 469i-CALVERT CLIFFS - UNIT 2 Amendment No. 246-

Definitions 1.1 1.1 Definitions LEAKAGE LEAKAGE shall be:

a. 'Identified LEAKAGE

1. 'LEAKAGE, such as that from pump seals or valve packing (except reactor coolant pump (RCP) seal'leakoff), that is.

captured and conducted to collection systems or a sump or collecting tank;

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

3. Reactor Coolant System (RC14EAKAGE through a steam generator to the Secondary System.

b. Unidentified LEAKAGE LEA gAK ,

All LEAKAGE (except RCP seal leakoff) that is nrnt iron+if4n4 I FAKAVM:F-PIu IV l1 II Ic ~u~nruso

c. Pressure Boundary LEAKAGE I LEAKAGE (exceptf1LEAKAGE) through a

.nonisolable 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 bolts specified in Table 1.1-1 with fuel in the reactor vessel.

OPERABLE-OPERABILITY A system, subsystem, train, component, or device shall be OPERABLE or have OPERABILITY when it is CALVERT CLIFFS - UNIT 1 1.1-4 Amendment No. 144-CALVERT CLIFFS - .UNIT.2 Amendment No. 248-

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

a. No pressure boundary LEAKAGE;

b. 1 gpm unidentified LEAKAGE;

c. 10 gpm identified LEAKAGE;

d. 100 gallons per day primary to secondary LEAKAGE through any one steam generator.

k-999 APPLICABILITY: MODES 1, 2, 3, and 4.

ACTIONS CONDITION I REQUIRED ACTION J COMPLETION TIME A.

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

reasons other than pressure boundary Or 1 a? .71ew I9lAA'

-/v LEAKAGE. 1='*h I 1-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 WIJPressure boundary LEAKAGE exists.

CALVERT CLIFFS - UNIT 1 3.4.13-1 Amendment No. Z -

CALVERT CLIFFS - UNIT 2 Amendment No. 4201-'

CALVERT CLIFFS - UNIT 1 3.4.13-2 Amendment No. {Sh CALVERT CLIFFS - UNIT 2 Amendment No. 2.04-

SG Tube Integrity 3.4.18 3.4 REACTOR COOLANT SYSTEM (RCS) 3.4.18 Steam Generator (SG) Tube Integrity LCO 3.4.18 SG tube integrity shall be maintained.

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

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

ACTIONS

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

Separate Condition entry is allowed for each SG tube.

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

Program. AND A.2 Plug the affected Prior to tube(s) in accordance entering MODE 4 with the Steam following the Generator Program. next refueling outage or SG tube inspection CALVERT CLIFFS - UNIT 1 3.4.18-1 Amendment No.

CALVERT CLIFFS - UNIT 2 Amendment No.

SG Tube Integrity 3.4.18 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME 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 SG tube integrity not maintained.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.18.1 Verify SG tube integrity in accordance with In accordance the Steam Generator Program. with the Steam Generator Program SR 3.4.18.2 Verify that each inspected SG tube that Prior to satisfies the tube repair criteria is entering MODE 4 plugged in accordance with the Steam following a SG Generator Program. tube inspection CALVERT CLIFFS - UNIT 1 3.4.18-2 Amendment No.

CALVERT CLIFFS - UNIT 2 Amendment No.

Programs and Manuals 5.5 5.5 Programs and Manuals

a. Testing frequencies specified in Section XI of the ASME Boiler and Pressure Vessel Code and applicable Addenda as follows:

ASME Boiler and Pressure Vessel Code and applicable Addenda terminology for Required Frequencies inservice testing for performing inservice activities testing activities Weekly At least once per 7 days Monthly At least once per 31 days Quarterly or every 3 months At least once per 92 days Semiannually or every 6 months At least once per 184 days Every 9 months At least once per 276 days Yearly or annually At least once per 366 days Biennially or every 2 years At least once per 731 days

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

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

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

-i(ffiC:6 ~)

5.5.9 CALVERT CLIFFS - UNIT 1 5.5-7 Amendment No. 259-

- CALVERT CLIFFS - UNIT 2 Amendment No. 236

Programs and Manuals 5.5 5.5 Programs and Manuals egr of this portion of the Reactor Coolant System is mai tained. The program shall contain the requirements listed belo

' a. Ste Generator Sample Selection and Inspection - The inimum numbers of steam generators to be inspected shall be determn ed as specified in Table 5.5.9-1.

b. Steam Gene ator Tube Sample Selection and Ins ction - The steam genertor tube minimum sample size, i pection result classificatio and the corresponding acti n required shall be as specifie in Tables 5.5.9-2 and 5. 9-3. The inservice inspection of st m generator tubes sh 1 be performed at the Frequencies speci

d in Specificati 5.5.9.c and the inspected tubes shal be verified ceptable per the acceptance criteria a Specifica on 5.5.9.d. When applying the exceptions of 5.5.9 .1 th ugh 5.5.9.b.3, previous defects or imperfections*n e area repaired by sleeving are not considered an area req ring reinspection. The tubes selected for each inservi e spection shall include at least 3%of the total number tube in all steam generators; the tubes selected for th e inspec *ons shall be selected on a random basis except 1., Where experence in similar pla s with similar water chemistry indicates critical area to be inspected, then at leas 50% of the tubes inspecte shall be from these

)criti 1 areas.

2. T first inservice inspection (subsequ t to the reservice inspection) of each steam gene tor shall

' lude:

i. All nonplugged tubes that previously had tectable wall'penetrations (> 20%); and ii. *Tubes in those areas where experience has indic ted potential problems.

CALVERT CLIFFS - UNIT 1 5.5-8 Amendment No. 259-CALVERT CLIFFS - UNIT 2 ' Amendment No. 236-

Programs and Manuals 5.5 5.5 Programs and Manuals The second and third inservice inspections may-be les than a full tube inspection by concentrating (selec ng at least 50% of the tubes to be inspected) the inspection on those areas of the tube sheet arra and on t ose portions of the tubes where tubes with im erfections were previously found.

The result of each sample inspection shall be lassified into .one o the three categories specified b ow. In all

-inspections, reviously degraded tubes mus exhibit significant (> 10%) further wall penetra ons to be included in the percenta e calculations.

Category In 4ection Results C-1 Less than % of the total tubes inspect are degraded tubes and none

/ f th inspected tubes aredefective.

C-2 On or more tubes, but not more than

'-' o the total tubes inspected, are defectve, or between 5% and 10% of the tot 1 tubes inspected are degraded

\ - / ' tubes.

C-3 More than'1 % of the total tubes

-inspected ar degraded tubes, or more than 1% of the inspected tubes are defective.

c. Ins ec on Frequencies - The above requir d inservice\

insp tions of steam generator tubes shall e performed at th following Frequencies:

The first inservice inspection shall be pe formed after

/ / 6 Effective Full Power Months, but within 2 calendar months of initial criticality. Subsequent i ervice inspections shall be performed at intervals o not less than 12 nor'more than 24 calendar months after e previous inspection. If at least 20 percent of t e CALVERT CLIFFS - UNIT 1 '5.5-9 ' Amendment No. .4H9 CALVERT CLIFFS - UNIT 2 ' Amendment No. 236fB

Programs and Manuals 5.5 5.5 Programs and Manuals C Category, or if at least 40 percent of the tri tw s

w inspected and were in the C-2 Category during the preiou caprego *ns etio nthedtersls us inspection, next wereno in theC3Caeo inspection may be extended nup t edmaximum of 30 months in order to correspond th pthe ne ts Tefueling outage ifnthe results of the t previousa spections were not in the C-3 Categoisy t

/ ~However, il the results of either of the :pr:!ii s two inspections ere in the C-2 Category, an yeering assessment sen be performed before opera n beyond 24 months andp al provide assuranceth all tubes

/will retain ade ~te structural margin against burst

/throughout normal perating, transie <,and accident

/ -conditions until t Eend of the fue cycle or 30 months, whichever occurs fir, -If two cnecutive inspections following service under all-voll e treatment conditions, not inclu reservice inspection

. result in all 'inspection' elts falling into the C-1

-/category or-if two consec ^ e inspections demonstrate

/ that previously obs reAeg adation has not continued

/and no additional deg dtio ts occurred, the

/inspection interval fa be et Add to a maximum of once CRC Fper 40 mon10 A N

2. If the ins-i inspection results f a steam generator conducted in ~ccordance with Tabl1es §k.9-2 and 5.5.9-3

at 40-mont intervals fall in Category-3, the inspecti # requency shall be increased o at least once per 20 .onths. The increase in inspectio frequency/

/shall/aply until the subsequent inspectin satisfy the /

/crit ria of Specification 5.5.9.c.1; the int ral may t hn be extended to a maximum of once per 30 ok40

/ nths, as applicable.\

Additional, unscheduled inservice inspections shal be

-/ performed on each steam generator in accordance with the /

first sample inspection specified in Tables 5.5.9-2ad -

CALVERT CLIFFS - UNIT 1 - 5.5-10 Amendment NO. LJ9 CALVERT CLIFFS - UNIT 2. Amendment No. 2a6W

Programs and Manuals 5.5 5.5 Programs and Manuals

5. .9-3 during the shutdown subsequent to fol owing conditions:

i. imary-to-secondary tube leaks (not including 1 ks originating from tube-to-tube sheet we s) in ex ss of the limits of Specification 3.4. ;

ii. A se mic occurrence greater than the 0 rating Basis arthquake; iii. A loss- -coolant accident requir g actuation of the engi ered safeguards; or iv. A main ste line or feedwa r line break.

4. The provisions of pecificaV n SR 3.0.2 do not apply for extending the equency for performing inservice inspections as stat in pecifications 5.5.9.c.1 and 5.5.9.c.2.

d. AcceDtance Criteria - A s d in this Specification:

1. Tubing or Tube ans tha portion of the tube or sleeve which forms t primary s tem to secondary system pressure bo dary.

2. Im erfec on means an except n to the dimension, finish or contour of a tube om that required by fabr ation drawings or specif ations. Eddy-current te ing indications below 20% o the nominal tube wall ickness, if detectable, may be onsidered as imperfections.

Degradation means a service-induced racking, wastage, wear, or general corrosion occurring n either inside or outside of a tube.

4. Degraded Tube means a tube containing i erfections 2 20% of the nominal wall thickness caus by degradation.

CALVERT CLIFFS - UNIT 1 5.5-11 Amendment No. 2S9--

CALVERT CLIFFS - UNIT 2 Amendment No. 236-

Programs and Manuals 5.5 5.5 Programs and Manuals

/'5 %Deqradation means the percentage of the tube wall\

{ \ ~thickness affected or removed by degradation. '

6. fect means an imperfection of such severity that t

-exc es the~plugging or repair limit. A tube co gining

/a d at is defective. Any tube which does no permit the pa sage of the eddy-current inspection pr e shall be deem a defective tube.

7. Pluain o Re air Limit means the imper ction depth at or beyond whNch the tube shall be remo ed from service by plugging, o repaired by sleeving n the affected area because itay become unservi able prior to the next inspection. The plugging or/repair limit

.imperfection depth are specifi d in percentage of nominal wall thickne s as fol ws:

i. original tube wall V40%

/ii. ABB-Combustion En ne ing leak tight

sleeve wall (Uni 2 thr ugh Cycle 14 only.'

Not applicable or Unit ) 28%

iii. .ABB-Combus on Engineering loy 800 leak-limi ng sleeve wall(Uni 2 through Cycle 1 only. Not applicable or Unit 1.) 35%

8. Unservice le describes the condition o a tube if it leaks o contains a defect large enough affect its struc ral integrity in'the event of an Op rating Basis Ear quake, a loss-of-coolant-accident, or steam line or eedwater line break as specified in 5.5.9 c.3 above.

9. Tube Inspection means an inspection of the steam

/ generator tube from the point of entry (hot leg si e) completely around the U-bend to the top support of.-che CALVERT CLIFFS - UNIT 25.5-12 1 Amendment No. i25 CALVERT CLIFFS - UNIT 2 Amendment No. 2376

Programs and Manuals 5.5 5.5 Programs and Manuals

/thrro Eineering teReport ugh Cy 14onlowinCEN-630-P, proese-Revis 01, fo\ni "Repair

/lcal of.4 O.D. Steam Generator Tubes sing Leak Tight Sleeve, August 1996. A post- d heat treatment

.len during sciei stallation as de bewill thebe pPhroprietary formed..

ABB-ob (Unit 2 in

. '-mbEngineerin ng Report CEN-63 3-PReiiH0,"Rpi ion O.D Sea Revi'of Generator Tube sigRepair Forh

.. mbst on ii. ABB-Combustio lev\"Ags Engineerg 1996 Alloy 800 heantswtreatmen A post-ed leak-limiting

-3/4-~.048 Inc Wall Inc el 600 Tubes Using Leak Limiting A oy800 Slee ' October 1998. (Unit 2 through Cle 14 only. No applicable for Unit 1.)

Tube rep includes the removal o ugs that were prev io ly insfalled as a correctiv rpreventive meas e.uA tube inspection per 5.5.9. 9 is required pror to returning previously plugged tub to service.

e Su llance Coipletion - The Steam Generator Tub rveillance Program-is' met after completing the orresponding actions (plug or repair all tubes exce ng the plugging limit and all tubes containing through-wallerks) required by Tables 5.5.9-2 and 5.5.9-3.

CALVERT CLIFFS -.UNIT 1'4 5.5-13 Amendment No.' 257 CALVERT CLIFFS -UNIT 2 Amendment No. 23 Programs and Manuals 5.5 5.5 Programs and Manuals...

Table 5.5.9-1 Minimum Number of Steam Generatorsto be.

Inspected During Inservice Inspection Preservi c Inspection No Ye No. Steam Gterators per Unit Two Three Four Two ree Four First Inservicb Inspection All One,/ Two Two Second & Subseque Inservice Inspections Onel One' One One' Table Notation:\/'

' The inservice inspection may e limite o one steam generator on a rotating schedule encompassing N % f the tubes (where N is the number of steam generators in the plant) f the results of the first or previous

. inspections indicate that all eam enerators are performing in a like manner. Note that under son circumst ces, the operating conditions in one or more steam generat s may be foun to be more severe than those in other steam generators /Under such circums nces, the sample sequence shall be modified to nspect the most severe c ditions.

2 The other stea generator not inspected during the rst inservice inspection s 11be inspected. The third and subsequ t inspections should fo ow the instructions described in 1 above.

l Eac

f the other two steam generators not inspected during t first i ervice inspections shall be inspected .during the second and t ird inspections. The fourth and subsequent inspections shall follow t instructions described in 1 above.

CALVERT CLIFFS - UNIT 1 5.5-14 Amendment No. 25 CALVERT CLIFFS - UNIT 2 ' Amendment No. .6t'

Programs and Manuals 5.5 Table 5.5.9-2 steam generator Plug repair defective tubes and ect Plug or repair defecti1 additional 2S t in tubes and inspect this steam generato additional 4S tubes in I I this steam gener form Inspect all tubes in this steam generator, generate plug or repair defective C-1 /

tubes and inspect 2S MStie steam i tubes in each other generators C-2 steam generat but no additional steam 24 vrbal generator are C-tification to NRC 3 with written follow-up Additional steam Inspect all tubes in each pursuant to generator is C-3 steam generator and plug Specification 5.6.9.c or repair defective tubes.

24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months verbal notification to NRC with written follow-up pursuant to Specification 5.6.9.c S = 3 - % Where N is the number of steam generators in the unit, and n is the number of steam generators inspected during an inspection.

n CALVERT CLIFFS - UNIT 1 5.5-15 Amendment No.

CALVERT CLIFFS - UNIT 2 Amendment No. 23&-

Programs and Manuals 5.5

.5.5 Programs and Manuals Table 5.5.9-3 Steam Generator Repaired Tube Inspection 1ST SAMPLE INSPECTION 2ND SAMPLE INSPECTION Sample S Result_ Required

.Action Result Acti o uired A Minimum of 20% of C-1 None N/A ._.__-'_N/Al repaired tubesf1)(2) - Plug defective repaired tubes and C-i None

. ect 100% of the repaired tubes Plug defective repaired

.. .- in t-sS. .- '~ .tubesL

. ...- lC-3 Perform action-for C-3l

/ . - ' - rresult of first~sample C-3 Inspect all re tube n this Other SG is C-1 None_-_l SG, plu ective tubes and Other SG is C-2 Perform action for C-2

... insecEt 20% of the repaired tubes ¢_.result of first sample

. in the other SG. Othe is C-3 Inspect all repaired

. . . . . .~s~s_ tubes in each SG and plug.\.

.24-Hour verbal notification to NRC reetve tubes. 24-hour

/.with written follow-up, pursuant to . ification e to(

. ,'.. .10 CFR 50.4 .NCwt iten follow-V . . . .up, pursuant o

._ _. __ . . . . 10 CFR 50.4

" Each repair method is considered a separate population for determination of scope expansion.

(2) The inspection of repaired tubes may be performed on tubes from either SG based on outage plans.

CALVERT CLIFFS - UNIT 1 5.5-16 Amendment No. 259-CALVERT CLIFFS - UNIT 2. ; Amendment No. 236-:

Reporting Requirements 5.6 5.6 Reporting Requirements 5.6.8 Tendon Surveillance Report Any abnormal degradation'of the containment structure detected during the tests required by the Pre-Stressed Concrete Containment Tendon Surveillance Program shall be'reported to the NRC within 30 days. The report shall include a description of the tendon condition, the condition of the concrete (especially at tendon anchorages), the inspection procedures, the tolerances on cracking, and the corrective action taken.

5.6.9 Steam Generator Tube Inspection Report

a. llowing each inservice inspection of steam generator tube

3. number of tubes plugged or repaired in each steam

< ,> g at or shall be reported to the NRC within 15 day<

b. The'c e results of the steami generators tubi frvice inspectio ring the report period shall e mitted to the A prior to byh 1 of eaph year. This prtshall v / ~~include:\/'/

K'1. Number and ex en f tube < ected;

2. Location and percent wall-thickness penetration for r each indicatiovd a ncip ction; and co3.Identificd c of tube plu r repaired.

c. Results o eam generator ture inspec which fall into Cateo Ue -3 require verbal notification NRCRegional AdI strator by telephone within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months a 'to smption'of plant operation. The written foll >-p of this /

' '/ report shall provide a description of investigatioal

/ ~conducted to determine cause-of the tube degradation

/corrective measures taken to prevent recurrence and shal

.S.

CALVERT-CLIFFS -UNIT 1 5.6-10 Ame'ndment.No. ,71-CALYERT CLIFFS --BUNIT 2 Amendment No. 24e--:

TABLE OF CONTENTS B 3.3.8 Control Room Recirculation Signal (CRRS) ......... B 3.3.8-1 B 3.3.9 Chemical and Volume Control System (CVCS)

Isolation Signal ............. ................ B 3.3.9-1 B 3.3.10 Post-Accident Monitoring (PAM) Instrumentation... B 3.3.10-1 B 3.3.11 Remote Shutdown Instrumentation .................. B 3.3.11-1 B 3.3.12 Wide Range Logarithmic Neutron Flux Monitor Channels ...................... B 3.3.12-1 B 3.4 REACTOR COOLANT SYSTEM (RCS) ...................... B 3.4.1-1 B 3.4.1 RCS Pressure, Temperature, and Flow Departure from Nucleate Boiling (DNB) Limits ...... ..... B 3.4.1-1 B 3.4.2 RCS Minimum Temperature for Criticality .......... B 3.4.2-1 B 3.4.3 RCS Pressure and Temperature (P/T) Limits ........ B 3.4.3-1 B 3.4.4 RCS Loops - MODES 1 and 2 ........... ............ B 3.4.4-1 B 3.4.5 RCS Loops - MODE 3 .............................. B 3.4.5-1 B 3.4.6 RCS Loops - MODE 4 .............................. B 3.4.6-1 B 3.4.7 RCS Loops - MODE 5, Loops Filled ....... ......... B 3.4.7-1 B 3.4.8 RCS Loops - MODE 5, Loops Not Filled ...... ...... B 3.4.8-1 B 3.4.9 Pressurizer .................................. B 3.4.9-1 B 3.4.10 Pressurizer Safety Valves ........................ B 3.4.10-1 B 3.4.11 Pressurizer Power-Operated Relief Valves (PORVs). B 3.4.11-1 B 3.4.12 Low Temperature Overpressure Protection (LTOP)

System ....................................... B 3.4.12-1 B 3.4.13 RCS Operational LEAKAGE .......................... B 3.4.13-1 B 3.4.14 RCS Leakage Detection Instrumentation ............ B 3.4.14-1 B 3.4.15 RCS Specific Activity ............................ B 3.4.15-1 B 3.4.16 Special Test Exception (STE) RCS Loops - MODE 2.. B 3.4.16-1 B 3.4.17 Special Test Exception (STE) RCS Loops - MODES 4 d -3.4.17-1 B 3.5 EMERGENCY CORE COOLINiSYEM ECS...................B 3.5.1-1 B 3.5.1 Safety Injection Tanks (SITs) .................... B 3.5.1-1 B 3.5.2 ECCS - Operating ................................. B 3.5.2-1 B 3.5.3 ECCS - Shutdown ................................. B 3.5.3-1 B 3.5.4 Refueling Water Tank (RWT) .......... ............. B 3.5.4-1 B 3.5.5 Trisodium Phosphate (TSP) ........................ B,3.5.5-1 B 3.6 CONTAINMENT SYSTEMS .................................. B 3.6.1-1 B 3.6.1 Containment .................................... B 3.6.1-1 B 3.6.2 Containment Air Locks ............................ B 3.6.2-1 B 3.6.3 Containment Isolation Valves ..................... B 3.6.3-1 B 3.6.4 Containment Pressure ............................. B 3.6.4-1 CALVERT CLIFFS - UNITS 1 & 2 ii Revision 2-a

RCS Loops - MODEs 1 and 2 B 3.4.4 BASES safety analyses are based on initial conditions at high core power or zero power. The accident analyses that are of most importance to RCP operation are loss of coolant flow and seized rotor (Reference 1).

RCS Loops - MODEs 1 and 2 satisfy 10 CFR 50.36(c)(2)(ii),

Criteria 2 and 3.

LCO The purpose of this LCO is to require adequate forced flow for core heat removal. Flow is represented by having both RCS loops with both RCPs in each loop in operation for removal of heat by the two SGs. To meet safety analysis acceptance criteria for .DNB, four pumps are required at rated power.

Each OPERABLE loop consists of two RCPs providing forced flow for heat transport to an SG that is OPERABLEQ11-gBILITY with regard to SG water level is ensured by the RPS in MODEs 1 and 2. A reactor trip places the plant in MODE 3 if any SG level is 2 50 inches below normal water level' as sensed by the RPS. The minimum water level to declare the SG OPERABLE is < 50 inches below normal water level*.

APPLICABILITY In MODEs 1 and 2, the reactor is critical and thus has the potential to produce maximum THERMAL POWER. Thus, to ensure that the assumptions of the accident analyses remain valid, all RCS loops are required to be OPERABLE, and in operation in these MODEs to prevent DNB and core damage.

The decay heat production rate is much lower than the full power heat rate. As such, the forced circulation flow and heat sink requirements are reduced for lower, noncritical MODEs as indicated by the LCOs for MODEs 3, 4, 5, and 6.

Operation in other MODEs is covered by: LCO 3.4.5, LCO 3.4.6, LCO 3.4.7, LCO 3.4.8, LCO 3.9.4, and LCO 3.9.5.

For Unit 2, the value shall remain 10 inches below the top of the feed ring through Cycle 14.

Revision 4-.

CLIFFS - UNITS CALVERT CLiFFS -

& 2 I &

UNITS I 2 B 3.4.4-2 B 3.4.4-2 Revision N--3

RCS Loops - MODE 3 B 3.4.5 BASES An OPERABLE loop consists of at least one OPERABLE RCP and an SG that is OPEAn Sie-!APQ ror b~ane RLE if is able to provide forced flow, if required.

APPLICABILITY In MODE 3, the heat load is lower than at power; therefore, one RCS loop in operation is adequate for transport and heat removal. A second RCS loop is required to be OPERABLE but not in operation-for redundant heat removal capability.

Operation in other MODEs is covered by: LCO 3.4.4, LCO 3.4.6, LCO 3.4.7, LCO 3.4.8, LCO 3.9.4, and LCO 3.9.5.

ACTIONS A.1 If one required RCS loop is inoperable, redundancy for forced flow heat removal is lost. The Required Action is restoration of the required RCS loop to OPERABLE status within a Completion Time of 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . This time allowance is a justified period to be without the redundant, nonoperating loop, because a single loop in operation has.a heat transfer capability greater than that needed to remove the decay heat produced in the reactor core.

B.1 If restoration is not possible within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months , the unit must be placed in MODE 4 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months . In MODE 4, the plant may be placed on the Shutdown Cooling (SDC) System.

The Completion Time of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months is compatible with required operation to achieve cooldown and depressurization from the existing plant conditions in an orderly manner and without challenging plant systems.

C.1 and C.2 If no RCS loop is in operation, except as provided in Note 1 in the LCO section, all operations involving introduction of water into the RCS with a boron concentration less than that required to meet the minimum SDM of LtO 3.1.1 must be immediately suspended. Action to restore one RCS loop to OPERABLE status and operation shall be initiated immediately and continued until one RCS loop is restored to OPERABLE Revision 49-CALVERT CLIFFS - UNITS CALVERT -

I &

UNITS 1 &2 2 B 3.4.5-3 B 3.4.5-3 Revision 49-

RCS Loops - MODE 4 B 3.4.6 BASES An OPERABLE RCS loop consists of at least one OPERABLE RCP and an SG~tais OPERABLEKuv-cardae;;iL t-an a the-minimum wa eseci evl e i S . ..2.

Similarly, for the SDC System, an OPERABLE SDC loop is composed of the OPERABLE SDC pump(s) capable of providing forced flow to the SDC heat exchanger(s). Reactor coolant pumps and SDC pumps are OPERABLE if they are capable of being powered and are able to provide flow if required.

APPLICABILITY In MODE 4, this LCO applies because It Is possible to remove core decay heat and to provide proper boron mixing with either the RCS loops and SGs, or the SDC System.

Operation In other MODEs is covered by: LCO 3.4.4, LCO 3.4.5, LCO 3.4.7, LCO 3.4.8, LCO 3.9.4, and LCO 3.9.5.

. ACTIONS A.i If only one required RCS loop is OPERABLE and in operation, and no SDC loops are OPERABLE, redundancy for heat removal is lost. Action must be initiated immediately to restore a second loop to OPERABLE status. The immediate Completion Time reflects the importance of maintaining the availability of two paths for decay heat removal.

B.1 If one required SDC loop is OPERABLE and in operation and no RCS loops are OPERABLE, redundancy for heat removal is lost.

The plant must be placed in MODE 5 within the next 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

Placing the plant in MODE 5 is a conservative action with regard to decay heat removal. With only one SDC loop OPERABLE, redundancy for decay heat removal is lost and, in the event of a loss of the remaining SDC loop, it would be safer to initiate that loss from MODE 5 (< 2001F) rather than MODE 4 (> 200'F to < 300F). The Completion Time of 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months is reasonable, based on operating experience, to reach MODE 5 from MODE 4, with only one SDC loop operating, in an orderly manner and without challenging plant systems.

Revision CALVERT CLIFFS - UNITS CALVERT -

&2 I &

UNITS 1 2 B 3.4.6-3 B 3.4.6-3 Revision At'

RCS Loops - MODE 5, Loops Filled B 3.4.7 BASES An OPERABLE SDC loop is composed of an OPERABLE SDC pump and an OPERABLE SDC heat exchanger.

SDC pumps are OPERABLE if they are capable of being pwered -

and are able to provide flow if required. SG can perform as a heat sink when it has an a r level and is OPERABLE APPLICABILITY In MODE 5 with RCS loops filled, this LCO requires forced circulation to remove decay heat from the core and to provide proper boron mixing. One SDC loop provides sufficient circulation for these purposes.

Operation in other MODEs is covered by: LCO 3.4.4, LCO 3.4.5, LCO 3.4.6, LCO 3.4.8, LCO 3.9.4, and LCO 3.9.5.

ACTIONS A.1 and A.2 If the required SDC loop is inoperable and any SGs have secondary side water levels < -50 inches, redundancy for heat removal is lost. Action must be initiated immediately to restore a second SDC loop to OPERABLE status or to restore the water level in the required SGs. Either Required Action A.1 or Required Action A.2 will restore redundant decay heat removal paths. The immediate Completion Times reflect the importance of maintaining the availability of two paths for decay heat removal.

B.1 and B.2 If no SDC loop is in operation, except as permitted in Note 1, all operations involving introduction of water into the RCS with a boron concentration less than that required to meet the minimum SDM of LCO 3.1.1 must be suspended.

Action to restore one SDC loop to OPERABLE status and place it in operation must be initiated. The required margin to criticality must not be reduced in this type of operation.

Suspending the introduction of water into the RCS with a boron concentration less than that required to meet the minimum SDM of LCO 3.1.1 is required to assure continued safe operation. When water is added without forced circulation, unmixed coolant could be introduced to the core, however water added with a boron concentration meeting Revision '+0-CALVERT CLIFFS - UNITS CALVERT -

&2 I &

UNITS 1 2 B 3.4.7-4 B 3.4.7-4 Revision 49

RCS Operational LEAKAGE B 3.4.13 BASES Except for primary to secondary LEAKAGE, the safety analyses do not address operational LEAKAGE. However, other operational LEAKAGE is related to the safety analyses for a LOCA; 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 a 100 gpd/SG primary to secondary LEAKAGE as the initial condition.

Primary to secondary LEAKAGE is a factor in the dose releases outside the Containment Structure resulting from a steam line break accident. To a lesser extent, other accidents or transients involve secondary steam release to the atmosphere, such as a SGTR. The leakage contaminates the secondary fluid.

Reference 1, Section 14.15 analysis for SGTR assumes the contaminated secondary fluid is released via the atmospheric dump valves and main steam safety valves. Most of the released radiation is due to the ruptured tube. The 100 gpd/SG primary to secondary LEAKAGE is relatively inconsequential.

The steam line break is more limiting for site radiation releases. The safety analysis for the steam line break accident assumes 100 gpd/SG primary to secondary LEAKAGE as an initial condition. The dose consequences resulting from the steam line break accident are described in Reference 1, Section 14.14.

Reactor Coolant System operational LEAKAGE satisfies 10 CFR 50.36(c)(2) (ii), Criterion 2.

LCO Reactor Coolant System 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 RCPB. LEAKAGE past seals and gaskets is not pressure boundary LEAKAGE.

CALVERT CLIFFS - UNITS 1 & 2 B 3.4.13-2 Revision Her0

RCS Operational LEAKAGE B 3.4.13 BASES

b. Unidentified LEAKAGE One gpm of unidentified LEAKAGE is allowed as a reasonable minimum detectable amount that the containment air monitoring and containment 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.

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 Structure from specifically known and located sources; but does not include pressure boundary LEAKAGE or controlled RCP seal leakoff (a normal function not considered LEAKAGE). Violation of this LCO could result in continued degradation of a

~s-->_>component or system.

S g at d--4iiary to Secondary LEAKAGE throuoh Anv One Sem

.13A ~ GenertW~--___-~~

The 10gallon re to secondary e LEAKA g ny one SG is consistent wi ving commitments.

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

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

ACTIONS A.1 AKAGE dentified LEA KAGK f Lin excess of the LCO limits must be limits within four hours. This Completion Time allows time to verify leakage rates and either identify unidentified LEAKAGE or reduce LEAKAGE to within limits CALVERT CLIFFS - UNITS 1 & 2 B 3.4.13-3 Rev isi on r

RCS Operational LEAKAGE B 3.4.13 BASES 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 ary exists or if unidentifiedg-identitfi i------- LEAKAGE cannot be reduced to hours, the reactor must be brought to lower pressure conditions to reduce the severity of the LEAKAGE and its potential consequences. 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 to MODE 5 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months . This action reduces the LEAKAGE and also reduces the factors that tend to degrade the pressure boundary.

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

SURVEILLANCE SR 3.4.13.1 REQUIREMENTS Verifying RCS LEAKAGE to be within the LCO limits ensures the integrity of the RCPB is maintained. Pressure boundary LEAKAGE would first appear as unidentified LEAKAGE and can 4,beM4k 7tAunrt..,pow only be positively identified by inspection. Unidentified'

.eE 4 A6L) grcs s a s(LEAKAGE and identified LEAKAGE are determined by performance My44- Pamu44k e' of an RCS water inventory balance.

014J4W1 04,oW)X anee ofan RGS wate

<__s____^<_,^__->_-- (inventory balanee 4n conjunction with effluent monitoring The RCS water inventory balance must be perf rmed with the reactor at steady-state operating condition and4near operating pressure.

Steady-state operation is required to perform a proper 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 CALVERT CLIFFS - UNITS 1 & 2 B 3.4.13-4 Revision4-2

RCS Operational LEAKAGE B 3.4.13 BASES pressure, temperature, power level, pressurizer and makeup tank levels, makeup and letdown, and RCP seal leakoff flows.

An early warning of pressure boundary LEAKAGE or unidentified LEAKAGE is provided by the automatic systems that monitor the containment atmosphere radioactivity and the containment sump level. These leakage detection systems are specified in LCO 3.4.14.

The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Frequency is a reasonable interval to trend LEAKAGE and recognizes the importance of early leakage detection in the prevention of accidents. 'I 0 PETY in an operational MODE. The requirement A,_>,_--->>___ dmonstra t ube integrity in accordance wibfe ta

/ r /Generator Tube. aeillance Program emph the importance of SG tu tegrity, e ough this 8.2 '.k /3 .surveillance test cannot med at normal operating In the ev or more SGs are determine not meet the req nts of the Steam Generator Tube Survei e ogram at anytime in MODEs 1 through 4, action to co th LO . 3mu e n REFERENCES 1. UFSAR

2. Regulatory Guide 1.45, Reactor Coolant Pressure 0 Boundary Leakage Detection Systems, May 1973 Revision-S---

UNITS 1 CALVERT CLIFFS - UNITS 1 &&2 2 B 3.4.13-5 B 3.4.13-5 Revision 6

SG Tube Integrity B 3.4.18 B 3.4 REACTOR COOLANT SYSTEM (RCS)

B 3.4.18 Steam Generator (SG) Tube Integrity BASES BACKGROUND Steam Generator tubes are small diameter, thin walled tubes that carry primary coolant through the primary to secondary heat exchangers. The SG tubes have a number of important safety functions. Steam generator tubes are an integral part of the RCPB and, as such, are relied on to maintain the primary system's pressure and inventory. The SG tubes isolate the radioactive fission products in the primary coolant from the secondary system. In addition, as part of the RCPB, the SG tubes are unique in that they act as the heat transfer surface between the primary and secondary systems to remove heat from the primary system. This specification addresses only the RCPB integrity function of the SG. The SG heat removal function is addressed by LCO 3.4.4, LCO 3.4.5, LCO 3.4.6, and LCO 3.4.7.

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

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

Specification 5.5.9, requires that a program be established and implemented to ensure that SG tube integrity is maintained. Pursuant to Specification 5.5.9, tube integrity is maintained when the SG performance criteria are met.

There are three SG performance criteria: structural integrity, accident induced leakage, and operational LEAKAGE. The SG performance criteria are described in Specification 5.5.9. Meeting the SG performance criteria provides reasonable assurance of maintaining tube integrity at normal and accident conditions.

B 3.4.18-1 Revision XX UNITS 1 CALVERT CLIFFS - UNITS & 2 1& 2 B 3.4.18-1 Revision XX

SG Tube Integrity B 3.4.18 BASES The processes used to meet the SG performance criteria are defined by Reference 1.

APPLICABLE The SGTR accident is the limiting design basis event for SG SAFETY ANALYSES tubes and avoiding an SGTR is the basis for this Specification. The analysis of a SGTR event assumes a bounding primary to secondary LEAKAGE rate equal to the operational LEAKAGE rate limits in LCO 3.4.13, 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 released to the atmosphere via safety valves.

The analysis for design basis accidents and transients other than a SGTR assume SG tubes retain their structural integrity (i.e., they are assumed not to rupture.) In these analyses, the steam discharge to the atmosphere is based on the total primary to secondary LEAKAGE from all SGs of 100 gpd/SG or is assumed to increase to 100 gpd/SG 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 limits assuming the relevant Iodine spiking factors. 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 General Design Criteria (GDC) 19 (Reference 2), 10 CFR Part 100 (Reference 3), or the NRC approved licensing basis (e.g., a small fraction of these limits).

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

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

During an SG inspection, any inspected tube that satisfies the Steam Generator Program repair criteria is removed from service by plugging. If a tube was determined to satisfy Revision XX B 3.4.18-2 B

CALVERT CLIFFS -

UNITS 1 CLIFFS - UNITS 1&& 22 3.4.18-2 Revision XX I

SG Tube Integrity B 3.4.18 BASES the repair criteria but was not plugged, the tube may still have tube integrity.

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

A SG tube has tube integrity when it satisfies the SG performance criteria. The SG performance criteria are defined in Specification 5.5.9, and described acceptable SG tube performance. The Steam Generator Program also provides the evaluation process for determining conformance with the SG performance criteria.

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

The structural integrity performance criterion provides a margin of safety against tube burst or collapse under normal and accident conditions, and ensures structural integrity of the SG tubes under all anticipated transients included in the design specification. Tube burst is defined as, "The gross structural failure of the tube wall. The condition typically corresponds to an unstable opening displacement (e.g., opening area increased in response to constant pressure) accompanied by ductile (plastic) tearing of the tube material at the ends of the degradation." Tube collapse is defined as, "For the load displacement curve for a given, structure, collapse occurs at the top of the load versus displacement curve where the slope of the curve becomes zero." The structural integrity performance criterion provides guidance on assessing loads that have a significant effect on burst or collapse. In that context, the term "significant" is defined as, "An accident loading condition other than differential pressure is considered significant when the addition of such loads in the assessment of the structural integrity performance criterion could cause a lower structural limit or limiting burst/collapse condition to be established." For tube integrity evaluations, except for circumferential CALVERT CLIFFS - UNITS 1 & 2 B 3.4.18-3 Revision XX

SG Tube Integrity B 3.4.18 BASES 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 References 4 and 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 the total accident leakage does not exceed 100 gpd/SG.

The operational LEAKAGE performance criterion provides an observable indication of SG tube conditions during plant operation. The limit on operational LEAKAGE is contained in LCO 3.4.13 and limits primary to secondary LEAKAGE through any one SG to 100 gpd. This limit is based on the assumption that a single crack leaking this amount would not propagate to a SGTR under the stress conditions of a LOCA or a main steam line break. If this amount of LEAKAGE is due to more than one crack, the cracks are very small, and the above assumption is conservative.

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

Reactor Coolant System 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.

Revision XX I B 3.4.18-4 B t UNITS 1 CALVERT CLIFFS - UNITS 1 &

&22 3.4.18-4 Revision XX I

SG Tube Integrity B 3.4.18 BASES ACTIONS The ACTIONS are modified by a Note clarifying that the Conditions may be entered independently for each SG tube.

This is acceptable because the required Actions provide appropriate compensatory actions for each affected SG tube.

Complying with the Required Actions may allow for continued operation, and subsequent affected SG tubes are governed by subsequent Condition entry and application of associated Required Actions.

A.1 and A.2 Condition A applies if it is discovered that one or more SG tubes examined in an inservice inspection satisfy the tube repair criteria but were not plugged in accordance with the Steam Generator Program as required by SR 3.4.18.2. An evaluation of SG tube integrity of the affected tube(s) must be made. Steam generator tube integrity is based on meeting the SG performance criteria described in the Steam Generator Program. The SG repair criteria define limits on SG tube degradation that allow for flaw growth between inspections while still providing assurance that the SG performance criteria will continue to be met. In order to determine if a SG tube that should have been plugged has tube integrity, an evaluation must be completed that demonstrates that the SG performance criteria will continue to be met until the next refueling outage or SG tube inspection. The tube integrity determination is based on the estimated condition of the tube at the time the situation is discovered and the estimated growth of the degradation prior to the next SG tube inspection. If it is determined that tube integrity is not being maintained, Condition B applies.

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

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

&2 B 3.4.18-5 B ,

UNITS 1 CLIFFS - UNITS CALVERT CLIFFS 1 & 2 3.4.18-5 Revision XX I

SG Tube Integrity B 3.4.18 BASES operation until the next inspection is supported by the operational assessment.

B.1 and B.2 If the Required Actions and associated Completion Times of Condition A are not met or if SG tube integrity is not being maintained, the reactor must be brought to MODE 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and MODE 5 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months .

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

SURVEILLANCE SR 3.4.18.1 REQUIREMENTS During shutdown periods the SGs are inspected as required by this SR and the Steam Generator Program. Reference 1 and its referenced EPRI Guidelines, establish the content of the Steam Generator Program. Use of the Steam Generator Program ensures that the inspection is appropriate and consistent with accepted industry practices.

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

The Steam Generator Program determines the scope of the inspection and the methods used to determine whether the tubes contain flaws satisfying the tube repair criteria.

Inspection scope (i.e., which tubes or areas of tubing within the SG are to be inspected) is a function of existing and potential degradation locations. The Steam Generator Program also specifies the inspection methods to be used to find potential degradation. Inspection methods are a function of degradation morphology, non-destructive examination technique capabilities, and inspection locations.

I CALVERT CLIFFS - UNITS 1 & 2 B 3.4.18-6 Revision XX I

SG Tube Integrity B 3.4.18 BASES The Steam Generator Program defines the Frequency of SR 3.4.18.1. The Frequency is determined by the operational assessment and other limits in the SG examination guidelines (Reference 6). The Steam Generator Program uses information on existing degradations and growth rates to determine an inspection Frequency that provides reasonable assurance that the tubing will meet the SG performance criteria at the next scheduled inspection. In addition, Specification 5.5.9 contains prescriptive requirements concerning inspection intervals to provide added assurance that the SG performance criteria will be met between scheduled inspections.

SR 3.4.18.2 During an SG inspection, any inspected tube that satisfies the Steam Generator Program repair criteria is removed from service by plugging. The tube repair criteria delineated in Specification 5.5.9 are intended to ensure that tubes accepted for continued service satisfy the SG performance criteria with allowance for error in the flaw size measurement and for future flaw growth. In addition, the tube repair criteria, in conjunction with other elements of the Steam Generator Program, ensure that the SG performance criteria will continue to be met util the next inspection of the subject tube(s). Reference 1 provides guidance for performing operational assessment to verify that the tubes remaining in service will continue to meet the SG performance criteria.

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

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

2. 10 CFR Part 50, Appendix A, GDC 19,

3. 10 CFR Part 100

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 B 3.4.18-7 Revision XX I CALVERT CLIFFS -

UNITS 1 CLIFFS - UNITS 1&& 2 2 B 3.4.18-7 Revision XX I

I SG Tube Integrity B 3.4.18 BASES

6. EPRI, Pressurized Water Reactor Steam Generator Examination Guidelines Revision XX B 3.4.18-8 B

I &

UNITS 1 CALVERT CLIFFS - UNITS & 2 2 3.4.18-8 Revision XX I

INSERT 3.4.13 A

______- ------ ----- NOTES----------_ _ --

1. 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.

2. Not applicable to primary to secondary LEAKAGE.

INSERT 3.4.13 B Not-required-to-be-erformed-until-1 NO etl TE---r 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.

INSERT B 3.4.13 A

d. Primary to Secondary LEAKAGE through Any One Steam Generator The limit of 100 gallons per day per SG is based on safety analysis assumption. This limit is more conservative than the 150 gpd/SG operational LEAKAGE performance criterion in Nuclear Energy Institute (NEI) 97-06, Steam Generator Program Guidelines (Reference 3). The Steam Generator Program operational LEAKAGE performance criterion in NEI 97-06 states, "The RCS operational primary to secondary leakage through any one SG shall be limited to 150 gallons per day." The limit is based on operating experience with SG tube degradation mechanisms that result in tube leakage. The operational leakage rate criterion in conjunction with the implementation of the Steam Generator Program is an effective measure for minimizing the frequency of steam generator tube ruptures.

INSERT B 3.4.13 B The surveillance is modified by two Notes. Note I states that this SR is not required to be performed until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after establishing steady state operation. The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months allowance provides sufficient time to collect and process all necessary data after stable plant conditions are established.

INSERT B 3.4.13 C Note 2 states that this SR is not applicable to primary to secondary LEAKAGE because LEAKAGE of 100 gallons per day cannot be measured accurately by an RCS water inventory balance.

INSERT B 3.4.13 D This SR verifies that primary to secondary LEAKAGE is less or equal to 100 gallons per day through any one SG. Satisfying the primary to secondary LEAKAGE limit ensures that the operational LEAKAGE performance criterion in the Steam Generator Program is met. If this SR is not met, compliance with LCO 3.4.18, "Steam Generator Tube Integrity," should be evaluated. The 100 gallons per day limit is measured at room temperature as described in Reference 4. The operational LEAKAGE rate limit applies to LEAKAGE through any one SG. If it is not practical to assign the LEAKAGE to an individual SG, all the primary to secondary LEAKAGE should be conservatively assumed to be from one SG.

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

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 Electric Power Research Institute (EPRI) guidelines (Reference 4).

INSERT B 3.4.13 E

3. NEI 97-06, Steam Generator Program Guidelines

4. EPRI, Pressurized Water Reactor Primary-to-Secondary Leak Guidelines INSERT 5.5.9 A Steam Generator Program shall be established and implemented to ensure that SG tube integrity is maintained. In addition, the Steam Generator Program shall include the following provisions:

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

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

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

2. Accident induced leakage performance criterion: The primary to secondary accident induced leakage rate for any design basis accident, other than a SG tube rupture, shall not exceed the leakage rate assumed in the accident analysis in terms of total leakage rate for all SGs and leakage rate for an individual SG. Leakage is not to exceed 100 gpd per SG.

w

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

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

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

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

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

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

e. Provisions for monitoring operational primary to secondary LEAKAGE.

INSERT 5.6.9 A report shall be submitted within 180 days after the initial entry into MODE 4 following completion of an inspection performed in accordance with the Specification 5.5.9, Steam Generator (SG) Program. The report shall include:

a. The scope of inspections performed on each SG,

b. Active degradation mechanisms found,

c. Nondestructive examination techniques utilized for each degradation mechanism,

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

e. Number of tubes plugged during the inspection outage for each active degradation mechanism,

f. Total number and percentage of tubes plugged to date,

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

h. The effective plugging percentage for all plugging in each SG

v t e Letter Sequence Request
TAC:MC8067, Steam Generator Tube Integrity (Open)
Initiation Request Acceptance Supplement Administration Questions 17 October 2005 23 December 2005 Answers 29 November 2005 20 January 2006 Results Approval... Other: ML060460089, ML072620215
MONTHYEAR2005-07-13 [Table View]

ML051990345

Text

SUBJECT:

1.0 INTRODUCTION

2.0 PROPOSED CHANGE

3.0 BACKGROUND

5.0 TECHNICAL ANALYSIS

6.0 REGULATORY ANALYSIS

10.0 REFERENCES

1.0 INTRODUCTION

2.0 PROPOSED CHANGE

3.0 BACKGROUND

5.0 TECHNICAL ANALYSIS

6.0 REGULATORY ANALYSIS

10.0 REFERENCES

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