Text

Application for Technical Specification Improvement Regarding Steam Generator Tube Integrity
	ML060890447
Person / Time
Site:	Vogtle
Issue date:	03/29/2006
From:	Grissette D; Southern Nuclear Operating Co
To:	; Document Control Desk, Office of Nuclear Reactor Regulation
References
	NL-06-0124
	Download: ML060890447 (69)
	v • d • e

Don E. Grissette Southern Nuclear Vice President Operating Company, Inc.

40 lnverness Center Parkway Post Office Box 1295 Birmingham. Alabama 35201

're1 205.992.6474 Fax 205.992.0341 SOUTHERN&

4 March 29, 2006 COMPANY Energy to Serve Your World" Docket Nos.: 50-424 NL-06-0 124 50-425 U. S. Nuclear Regulatory Commission A m : Document Control Desk Washington, D. C. 20555-0001 Vogtle Electric Generating Plant Application for Technical Specification Improvement Regarding Steam Generator Tube Integrity Ladies and Gentlemen:

On January 20,2006, the Nuclear Regulatory Commission (NRC) issued Generic Letter (GL) 2006-01, "Steam Generator Tube Integrity and Associated Technical Specifications," to the Southern Nuclear Operating Company (SNC) for Vogtle Electric Generating Plant (VEGP) Units 1 and 2. On February 11,2006, SNC submitted a required 30-day response for VEGP Units 1 and 2 pursuant to the requirements of GL 2006-01. The 30-day response contained a regulatory commitment for SNC to submit, by March 3 1,2006, a request to modify the steam generator (SG) portion the VEGP technical specifications (TS) that is consistent with NRC-approved Revision 4 to Technical Specification Task Force (TSTF) Standard Technical Specification Change Traveler, TSTF-449, "Steam Generator Tube Integrity."

Therefore, in accordance with the provisions of Section 50.90 of Title 10 of the Code of Federal Regulations (10 CFR), Southern Nuclear Operating Company (SNC) is submitting a request for an amendment to the technical specifications (TS) for Vogtle Electric Generating Plant (VEGP) Units 1 and 2.

The proposed amendment would revise the TS requirements related to steam generator tube integrity. The change is consistent with NRC-approved Revision 4 to TSTF-449.

The availability of this TS improvement was announced in the Federal Register on May 6, 2005 (70 FR 24.126) as part of the consolidated line item improvement process (CLIP).

Enclosure 1 provides a description of the proposed change and confirmation of applicability. This includes a description of the proposed changes, the confmnation of applicability, plant-specific verifications, the no significant hazards determination, and the environmental evaluation. Enclosure 2 provides the existing TS pages marked-up to show the proposed change. Enclosure 3 provides the clean-typed copies of the affected TS pages. Enclosure 4 provides the existing TS Bases pages marked-up to show the proposed change.

U. S. Nuclear Regulatory Commission NL-06-0 124 Page 2 In accordance with 10 CFR 50.91, a copy of this application, with enclosures, is being provided to the designated Georgia State official.

SNC requests approval of the proposed license amendments by September 2006. It is anticipated that the license amendment, as approved, will be effective upon issuance, to be implemented prior to restart from the VEGP Unit 1 fall 2006 maintenancelrefueling outage, scheduled to begin in September 2006.

Mr. D. E. Grissette states he is a Vice President of Southern Nuclear Operating Company, is authorized to execute this oath on behalf of Southern Nuclear Operating Company and to the best of his knowledge and belief, the facts set forth in this letter are true.

This letter contains no NRC commitments.

Respectfully submitted, SOUTHERN NUCLEAR OPERATING COMPANY Don E. Grissette Sworn to and subscribed before me this $? Jt;day of , 2006 gri r;wr i .> ! b !

i s3

\$i,

$ 3 ' 4 .*.

5 0

2 7

,**s

.: 2 @y commission expires:

., (c.$C Lt

-4 $-'b **'

.** DEGIDRGldai

Enclosures:

1. Description and Assessment

2. Mark-up of Technical Specification pages

3. Re-typed Technical Specification pages

4. Proposed Technical Specification Bases Changes (for information only)

U. S. Nuclear Regulatory Commission NL-06-0124 Page 3 cc: Southern Nuclear Operating Company Mr. J. T. Gasser, Executive Vice President Mr. T. E. Tynan, General Manager - Plant Vogtle RType: CVC7000 U. S. Nuclear Regulatory Commission Dr. W. D. Travers, Regional Administrator Mr. C. Gratton, NRR Project Manager - Vogtle Mr. G. J. McCoy, Senior Resident Inspector - Vogtle State of Georgia Mr. L. C. Barrett, Commissioner - Department of Natural Resources

Enclosure 1 Vogtle Electric Generating Plant Application for Technical Specification Improvement Regarding Steam Generator Tube Integrity Description and Assessment

Enclosure 1 Vogtle Electric Generating Plant Application for Technical Specification Improvement Regarding Steam Generator Tube Integrity DESCRIPTION AND ASSESSMENT

1.0 INTRODUCTION

The proposed license amendment revises the requirements in Technical Specifications (TS) related to steam generator tube integrity. The changes are consistent with NRC approved Technical Specification Task Force (TSTF) Standard Technical Specification Change Traveler, TSTF-449, "Steam Generator Tube Integrity," Revision 4. The availability of this technical specification improvement was announced in the Federal Register (70 FR 24126) on May 6,2005 as part of the consolidated line item improvement process (CLIP).

2.0 DESCRIPTION

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

Revised TS definition of LEAKAGE Revised TS 3.4.13, "RCS Operational LEAKAGE" New TS 3.4.17, "Steam Generator (SG) Tube Integrity" Revised TS 5.5.9, "Steam Generator (SG) Tube Surveillance Program" Revised TS 5.6.10, "Steam Generator Tube Inspection Report" Proposed revisions to the TS Bases are also included in this application. As discussed in the NRC's model safety evaluation, adoption of the revised TS Bases associated with TSTF-449, Revision 4 is an integral part of implementing this TS improvement. The changes to the affected TS Bases pages will be incorporated in accordance with the "TS Bases Control Program."

3.0 BACKGROUND

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

However, in addition to the background discussion in the documents listed above, it should be noted that TSTF-449 requires any site specific alternate tube repair criteria be listed in paragraph 5.5.9. Therefore, SNC listed a VEGP site specific alternate tube repair criteria in paragraph 5.5.9. This alternate tube repair was proposed by SNC letter NL 1420 dated August 12,2005 and approved by NRC SER on September 21,2005. SNC proposed a one-time change revising TS 5.5.9, "Steam Generator (SG) Tube Surveillance Program," to incorporate changes in the SG inspection scope for VEGP, Unit 2 during Refueling Outage 11 and the subsequent operating cycle. The proposed changes were applicable to Unit 2 only for inspections during Refueling Outage 11 and for the subsequent operating cycle. The proposed changes modified the inspection and plugging requirements for portions of SG tubes within the hot leg tubesheet region of the SGs. The Page 2 of 4 Application for Technical Specification Improvement Regarding Steam Generator Tube Integrity license for VEGP, Unit 1 was affected only due to the fact that Unit 1 and Unit 2 use common Technical Specifications.

4.0 REGULATORY REQULREMENTS 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 24 126) the NRC Notice for Comment published on March 2,2005 (70 FR 10298),

and TSTF-449, Revision 4.

5.0 TECHNICAL, ANALYSIS SNC 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 TSTF-449, and the changes associated with Revision 4 to TSTF-449. SNC has concluded that the justifications presented in the TSTF proposal and the SE prepared by the NRC staff are applicable to VEGP Units 1 and 2 and justify this amendment for the incorporation of the changes to the VEGP TS.

6.0 REGULATORY ANALYSIS

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

6.1 VERIFICATION AND COMMITMENTS As discussed in the notice of availability published in the Federal Register on May 6, 2005 for this TS improvement, plant-specific verifications were performed andthe following information is provided to support the NRC staffs review of this amendment application:

Plant Name, Unit No. Vogtle Electric Generating Plant Unit 1 Steam Generator Model(s) Westinghouse Model F Effective Full Power Years (EFPY) of 15.68 EFPY as of end of fuel cycle 12 1 Tubing Material (e.g., 600M, 600TT, 660TT) Alloy 600 thermally treated (A600TI')

1 5626 1 Number of tubes per SG Nmber and Percentage of tubes plugged in SG 1 - 6 tubes (0.1 1%), SG 2 - 11 tubes each SG (0.20%), SG 3 - 22 tubes (0.39%), SG 4

- 16 tubes (0.28%)

Number of tubes repaired in each SG None Degradation mechanism(s) identified Primary water stress corrosion cracking (PWSCC); anti-vibration bar (AVB) wear; flow distribution baffle plate (FDB) wear: wear due to foreirm obi ects

Enclosure 1 Page 3 of 4 Application for Technical Specification Improvement Regarding Steam Generator Tube Integrity I Current primary-to-secondary leakage limits 1 500 gallons per day (technical i per SG specification limit)

Current primary-to-secondary leakage limits 1 gallon per minute through all SG's total (technical specification limit)

Leakage is evaluated at what temperature Room temperature condition?

I Approved Alternate Tube Repair Criteria 1 None (ARC)

Approved Tube Repair Methods None Performance Criteria for Accident Leakage - One gallon per minute combined total leakage through all four SGs with 0.35 gpm to the faulted SG

- Leakage is evaluated at 590 degrees Fahrenheit, 2250 psia Plant Name, Unit No. Vogtle Electric Generating Plant Unit 2 Steam Generator Model(s): Westinghouse Model F Effective Full Power Years (EFPY) of 14.57 EFPY as of end of fuel cycle 11 1 service for currentlv installed SGs ' 1 (911812005) I 9Number of tubes per SG

~ 1 1 600 5626 0 ~ 660TT)hermallytreated (A600TT)

Nmber and Percentage of tubes plugged in SG 1 - 5 tubes (0.09%), SG 2 - 12 tubes each SG (0.21%), SG 3 - 4 tubes (0.07%), SG 4 -

2 1 tubes (0.37%)

Number of tubes repaired in each SG None Degradation mechanism(s) identified Anti-vibration bar (AVB) wear; flow distribution baffle plate (FDB) wear; wear due to foreign objects Current primary-to-secondary leakage limits 500 gallons per day (technical per SG specification limit)

Current primary-to-secondary leakage limits 1 gallon per minute through all SG's total Leakage is evaluated at what temperature Room temperature condition?

Approved Alternate Tube Repair Criteria - Approved by amendment 117 to (ARC) technical specifications, dated September 21,2005.

- For Refueling Outage 2R11 and the subsequent operating cycle, degradation found in the portion of the tube below 17 inches from the top of the hot leg tubesheet does no; require plugging.

Approved Tube Repair Methods None Performance Criteria for Accident Leakage - One gallon per minute combined total leakage through all four SGs with 0.35 gpm to the faulted SG

- Leakage is evaluated at 590 degrees Fahrenheit. 2250 ~ s i a Page 4 of 4 Application for Technical Specification Improvement Regarding Steam Generator Tube Integrity 7.0 NO SIGNIFICANT HAZARDS CONSIDERATION SNC has reviewed the proposed no significant hazards consideration determination published on March 2,2005 (70 FR 10298) as part of the CLIIP. SNC has concluded that the proposed determination presented in the notice is applicable to VEGP Units 1 and 2 and the determination is hereby incorporated by reference to satisfy the requirements of 10 CFR 50.91(a).

8.0 ENVIRONMENTAL EVALUATION SNC has reviewed the environmental evaluation included in the model SE published on March 2,2005 (70 FR 10298) as part of the CLIP. SNC has concluded that the staffs findings presented in that evaluation are applicable to VEGP Units 1 and 2 and the evaluation is hereby incorporated by reference for this application.

9.0 PRECEDENT This application is being made in accordance with the CLIP. SNC is not proposing variations or deviations kom the TS changes described in TSTF-449, Revision 4, or the NRC staffs model SE published on March 2,2005 (70 FR 10298).

10.0 REFERENCES

Federal Register Notices:

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

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

Enclosure 2 Vogtle Electric Generating Plant Application for Technical Specification Improvement Regarding Steam Generator Tube Integrity Mark-up of Technical Specification Pages

TABLE OF CONTENTS (continued)

INSTRUMENTATION.......................................................................... 3.3.1.1 Reactor Trip System (RTS) Instrumentation .........................................

Engineered Safety Feature Actuation System (ESFAS)

Instrumentation .............................................................................

Post Accident Monitoring (PAM) Instrumentation..................................

Remote Shutdown System ...................................................................

4.16 kV ESF Bus Loss of Power (LOP) Instrumentation .......................

Containment Ventilation Isolation Instrumentation ................................

Control Room Emergency Filtration System (CREFS)

Actuation Instrumentation..............................................................

High Flux at Shutdown Alarm (HFASA) ................................................

REACTOR COOLANT SYSTEM (RCS) ............................................... 3.4.1 -1 RCS Pressure. Temperature. and Flow Departure From Nucleate Boiling (DNB) Limits .......................................................

RCS Minimum Temperature For Criticality............................................

RCS Pressure and Temperature (P/T) Limits........................................

RCS Loops -- MODES 1 and 2 .............................................................

RCS Loops -- MODE 3 .........................................................................

RCS Loops -- MODE 4 .........................................................................

RCS Loops -- MODE 5. Loops Filled ....................................................

RCS Loops -- MODE 5. Loops Not Filled..............................................

Pressurizer ...........................................................................................

Pressurizer Safety Valves .....................................................................

Pressurizer Power Operated Relief Valves (PORVs) ............................

Cold Overpressure Protection Systems (COPS) ...................................

RCS Operational LEAKAGE .................................................................

RCS Pressure Isolation Valve (PIV) Leakage .......................................

RCS Leakage Detection Instrumentation ..............................................

RCS Specific Activity ............................................................................

Steam Generator (SG) Tube lntearitv ...................................................

EMERGENCY CORE COOLING SYSTEMS (ECCS) .......................... 3.5.1.1 Accumulators ........................................................................................ 3.5.1 -1 ECCS - Operating ............................................................................... 3.5.2.1 ECCS - Shutdown ............................................................................... 3.5.3.1 Refueling Water Storage Tank (RWST) ................................................ 3.5.4-1 Seal Injection Flow............................................................................... 3.5.5.1 Recirculation Fluid pH Control System.................................................. 3.5.6.1 (continued)

Vogtle Units 1 and 2 Amendment No. 107 (Unit 1)

Amendment No. 85 (Unit 2)

TABLE OF CONTENTS (continued)

LIST OF TABLES MODES ............................................................................................... 1.I-7 Reactor Trip System Instrumentation.................................................... 3.3.1-1 4 Engineered Safety Feature Actuation System Instrumentation ............................................................................. 3.3.2-9 Post Accident Monitoring Instrumentation............................................ 313.3-6 Remote Shutdown System Instrumentation and Controls ..................... 3.3.4-3 Containment Ventilation Isolation Instrumentation ................................ 3.3.6-5 CREFS Actuation Instrumentation ........................................................ 3.3.7-6 Maximum Allowable Power Range Neutron Flux High Trip Setpoint with Inopemble Main Steam Safety Valves ..................... 3.7.1-3 3.7.1-2 Main Steam Safety Valve L i i Settings .................................................. 3.7.1-4

......................................... 'M w.

(continued)

Vogtle Units 1 and 2 Amendment No. 133 (Unit 1)

Amendment No. 112 (Unit 2)

Definitions 1.1 1.1 Definitions (continued)

E - AVERAGE E shall be the average (weighted in proportion to DISINTEGRATION ENERGY the concentration of each radionuclide in the reactor coolant at the time of sampling) of the sum of the average beta and gamma energies per disintegration (in MeV) for isotopes, other than iodines, with half lives > 14 minutes, making up at least 95% of the total noniodine activity in the coolant.

ENGINEERED SAFETY The ESF RESPONSE TIME shall be that time FEATURE (ESF) RESPONSE interval from when the monitored parameter exceeds its TIME ESF actuation setpoint at the channel sensor until the ESF equipment is capable of performing its safety function (i.e.,

the valves travel to their required positions, pump discharge pressures reach their required values, etc.). Times shall include diesel generator starting and sequence loading delays, where applicable. The response time may be measured by means of any series of sequential, overlapping, or total steps so that the entire response time is measured.

In lieu of measurement, response time may be verified for selected components provided that the components and the methodology for verification have been previously reviewed and approved by the NRC.

LEAKAGE LEAKAGE shall be:

a. Identified LEAKAGE

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

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

3. Reactor Coolant System (RCS) LEAKAGE through a steam generator (SG) to the Secondary System lprimarv to secondarv LEAKAGE);

(continued)

Vogtle Units 1 and 2 Amendment No. 106 (Unit 1)

Amendment No. 84 (Unit 2)

Definitions 1.I 1.IDefinitions LEAKAGE b. Unidentified LEAKAGE (continued)

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

c. Pressure Boundarv LEAKAGE LEAKAGE ( e x c e p t s primarv to se<?ondaw LEAKAGE) I through a nonisolable fault in an RCS component body, pipe wall, or vessel wall.

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

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

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

OPERABLE- OPERABILITY A system, subsystem, train, component, or device shall be OPERABLE or have OPERABILITY 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. These tests are:

Vogtle Units 1 and 2 Amendment No. 96 (Unit 1)

Amendment No. 74 (Unit 2)

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

a. No pressure boundary LEAKAGE; 1 gpm unidentified LEAKAGE; 10 gpm identified LEAKAGE;&

. 150g89gallons per day primary to secondary LEAKAGE through any one steam aenerator ( S G W .

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

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. RCS omrational 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 ~rimarvto secondarv 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 of Condition A not -

AND met.

B.2 Be in MODE 5. 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months Pressure boundary LEAKAGE exists.

Primarv to secondary LEAKAGE not within

-limit.

I Vogtle Units 1 and 2 3.4.13-1 Amendment No. 96 (Unit 1)

Amendment No. 74 (Unit 2)

RCS Operational LEAKAGE 3.4.13 SURVEILLANCE REQUIREMENTS -

SURVEILLANCE FREQUENCY

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

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

-2. &Only required to be performed during steady state operation.

3. Not ap~licableto ~rimarv to secondaty LEAKAGE.

Perform RCS water inventory balance. Once within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after achieving steady state operation 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months thereafter

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

Not rewired to be ~erformeduntil 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after establishment of steadv state omration.

72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months LEAKAGE is < 150 qallons oer dav throuqh any one SG.

Vogtle Units I and 2 Amendment No. 96 (Unit 1)

Amendment No. 74 (Unit 2)

SG Tube Integrity 3.4.17 3.4 REACTOR COOLANT SYSTEM (RCS) 3.4.17 Steam Generator (SG) Tube Integrity LC0 3.4.17 SG tube integrity shall be maintained.

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

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

ACTIONS

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

Separate Condition entry is allowed for each SG tube.

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

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

Steam Generator Program. AND A.2 Plug [or repair] the affected Prior to entering tube(s) in accordance with MODE 4 following the the Steam Generator next refueling outage Program. or SG tube inspection B. Required Action and B. 1 Be in MODE 3. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months associated Completion Time of Condition A not AND met.

B.2 Be in MODE 5. 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months

-OR I SG tube integrity not maintained.

I Vogtle Units 1 and 2 3.4.17-1 Amendment No. xx (Unit 1)

Amendment No. xx (Unit 2)

SG Tube Integrity 3.4.17 SURVEILLANCE REQUIREMENTS SURVEILLANCE I FREQUENCY SR 3.4.17.1 Verify SG tube integrity in accordance with the In accordance Steam Generator Program. with the Steam Generator Program SR 3.4.1 7.2 Verify that each inspected SG tube that satisfies the Prior to entering tube repair criteria is plugged [or repaired] in MODE 4 following accordance with the Steam Generator Program. a SG tube inspection Vogtle Units 1 and 2 Amendment No. xx (Unit 1)

Amendment No. xx (Unit 2)

Programs and Manuals 5.5 5.5 Proarams and Manuals Inservice Testina Prwram (continued)

The provisions of SR 3.0.2are applicable to the above required Frequencies for performing inservice testing activities; The provisions of SR 3.0.3are applicable to inservice testing activities; and

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

Steam Generator (SG- Program INSERT 5.5.9 (continued)

Vogtle Units 1 and 2 Amendment No. 96 (Unit I)

Amendment No. 74 (Unit 2)

Programs and Manuals 5.5 Vogtle Units 1 and 2 Amendment No. 96 (Unit 1)

Amendment No. 74 (Unit 2)

Programs and Manuals 5.5 (continued)

Vogtle Units 1 and 2 Amendment No. 96 (Unit 1)

Amendment No. 74 (Unit 2)

Programs and Manuals 5.5 (continued)

Vogtle Units 1 and 2 Amendment No. 138 (Unit 1)

Amendment No. 117 (Unit 2)

Programs and Manuals 5.5 (continued)

Vogtle Units 1 and 2 Amendment No. 138 (Unit 1)

Amendment No. 117 (Unit 2)

Programs and Manuals 5.5 Vogtle Units 1 and 2 Amendment No. 96 (Unit I )

Amendment No. 74 (Unit 2)

Programs and Manuals 5.5 Vogtle Units 1 and 2 Amendment No. 96 (Unit 1)

Amendment No. 74 (Unit 2)

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 or plugged, to confirm that the performance criteria are being met.

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

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

2. Accident induced leakage performance criterion: The primary to secondary accident induced leakage rate for any design basis accident, other than a SG tube rupture, shall not exceed the leakage rate assumed in the accident analysis in terms of total leakage rate for all SGs and leakage rate for an individual SG. Leakage is not to exceed 1 gpm per SG, 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 LC0 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.

Page 1

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

depth based criteria:

1. For Unit 2 during Refueling Outage 11 and the subsequent operating cycle, degradation found in the portion of the tube below 17 inches from the top of the hot leg tubesheet does not require plugging.

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. For Unit 2 during Refueling Outage 11 and the subsequent operating cycle, the portion of the tube below 17 inches from the top of the hot leg tubesheet is excluded. 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. lnspect 100% of the tubes in each SG during the first refueling outage following SG replacement.

2. lnspect 100% of the tubes at sequential periods of 120, 90, and, thereafter, 60 effective full power months. The first sequential period shall be considered to begin after the first inservice inspection of the SGs. In addition, inspect 50% of the tubes by the refueling outage nearest the midpoint of the period and the remaining 50% by the refueling outage nearest the end of the period. No SG shall operate for more than 48 effective full power months or two refueling outages (whichever is less) without being 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 nondestructive 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.

Page 2

Reporting Requirements 5.6 5.6 Rewrtina Reauirements 5.6.9 Tendon Surveillance ReD0rt Any abnormal degradation of the containment structure detected during the tests required by the Prestressed 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.

Steam Generator Tube lns~ectionRe~ort INSERT 5.6.10 Vogtle Units 1 and 2 Amendment No. 96 (Unit 1)

Amendment No. 74 (Unit 2)

INSERT 5.6.10 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,

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.

Page 1

Enclosure 3 Vogtle Electric Generating Plant Application for Technical Specification Improvement Regarding Steam Generator Tube Integrity Re-typed Technical Specification Pages

TABLE OF CONTENTS INSTRUMENTATION ........................................................................... 3.3.1.1 Reactor Trip System (RTS) Instrumentation.......................................... 3.3.1.1 Engineered Safety Feature Actuation System (ESFAS)

Instrumentation ............................................................................. 3.3.2.1 Post Accident Monitoring (PAM) Instrumentation .................................. 3.3.3.1 Remote Shutdown System .................................................................... 3.3.4.1 4.16kV ESF Bus Loss of Power (LOP) Instrumentation........................ 3.3.5.1 Containment Ventilation Isolation Instrumentation................................. 3.3.6.1 Control Room Emergency Filtration System (CREFS)

Actuation Instrumentation.............................................................. 3.3.7.1 High Flux at Shutdown Alarm (HFASA) ................................................. 3.3.8.1 REACTOR COOLANT SYSTEM (RCSL ............................................... 3.4.1.1 RCS Pressure. Temperature. and Flow Departure From Nucleate Boiling (DNB) Limits .......................................................

RCS Minimum Temperature For Criticality ............................................

RCS Pressure and Temperature (P/T) Limits........................................

RCS Loops - MODES 1 and 2 .............................................................

RCS Loops -- MODE 3 .........................................................................

RCS Loops -- MODE 4 .........................................................................

RCS Loops -- MODE 5,Loops Filled ....................................................

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

Pressurizer............................................................................................

Pressurizer Safety Valves .....................................................................

Pressurizer Power Operated Relief Valves (PORVs) ............................

Cold Overpressure Protection Systems (COPS) ...................................

RCS Operational LEAKAGE .................................................................

RCS Pressure Isolation Valve (PIV) Leakage .......................................

RCS Leakage Detection Instrumentation ..............................................

RCS Specific Activity .............................................................................

Steam Generator (SG) Tube Integrity ...................................................

EMERGENCY CORE COOLING SYSTEMS (ECCS) .......................... 3.5.1.1 Accumulators ........................................................................................ 3.5.1.1 ECCS - Operating................................................................................ 3.5.2.1 ECCS - Shutdown................................................................................ 3.5.3.1 Refueling Water Storage Tank (RWST) ................................................ 3.5.4.1 Seal Injection Flow ................................................................................ 3.5.5.1 Recirculation Fluid pH Control System .................................................. 3.5.6.1 (continued)

Vogtle Units 1 and 2 Amendment No. (Unit 1)

Amendment No. (Unit 2)

TABLE OF CONTENTS (continued)

LIST OF TABLES MODES ................................................................................................

Reactor Trip System Instrumentation ....................................................

Engineered Safety Feature Actuation System Instrumentation .............................................................................

Post Accident Monitoring Instrumentation .............................................

Remote Shutdown System Instrumentation and Controls .....................

Containment Ventilation Isolation Instrumentation.................................

CREFS Actuation Instrumentation.........................................................

Maximum Allowable Power Range Neutron Flux High Trip Setpoint with Inoperable Main Steam Safety Valves ......................

Main Steam Safety Valve Lift Settings ..................................................

(continued)

Vogtle Units 1 and 2 Amendment No. (Unit 1)

Amendment No. (Unit 2)

Definitions 1.1 1.1 Definitions (continued)

E - AVERAGE E shall be the average (weighted in proportion to DISINTEGRATION ENERGY the concentration of each radionuclide in the reactor coolant at the time of sampling) of the sum of the average beta and gamma energies per disintegration (in MeV) for isotopes, other than iodines, with half lives > 14 minutes, making up at least 95% of the total noniodine activity in the coolant.

ENGINEERED SAFETY The ESF RESPONSE TIME shall be that time FEATURE (ESF) RESPONSE interval from when the monitored parameter exceeds its TIME ESF actuation setpoint at the channel sensor until the ESF equipment is capable of performing its safety function (i.e.,

the valves travel to their required positions, pump discharge pressures reach their required values, etc.). Times shall include diesel generator starting and sequence loading delays, where applicable. The response time may be measured by means of any series of sequential, overlapping, or total steps so that the entire response time is measured.

In lieu of measurement, response time may be verified for selected components provided that the components and the methodology for verification have been previously reviewed and approved by the NRC.

LEAKAGE LEAKAGE shall be:

a. Identified LEAKAGE

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

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

3. Reactor Coolant System (RCS) LEAKAGE through a steam generator to the Secondary System (primary to secondary LEAKAGE);

(continued)

Vogtle Units 1 and 2 Amendment No. (Unit 1)

Amendment No. (Unit 2)

Definitions 1.1 1.1 Definitions LEAKAGE b. Unidentified LEAKAGE (continued)

All LEAKAGE (except RCP seal water ipjection or leakoff) that is not identified LEAKAGE;

c. Pressure Boundary LEAKAGE LEAKAGE (except primary to secondary LEAKAGE) I through a nonisolable fault in an RCS component body, pipe wall, or vessel wall.

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

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

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.l-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 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@)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. These tests are:

(continued)

Vogtle Units 1 and 2 Amendment No. (Unit 1)

Amendment No. (Unit 2)

RCS Operational LEAKAGE 3.4.13 3.4 REACTOR COOLANT SYSTEM (RCS) 3.4.13 RCS Operational LEAKAGE LC0 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; and I

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

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

ACTIONS CONDITION I REQUIRED ACTION I 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 associated Completion B.1 Be in MODE 3. , 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months Time of Condition A not A N met.

B.2 Be in MODE 5. 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months Pressure boundary LEAKAGE exists.

Primary to secondary LEAKAGE not within limit.

Vogtle Units 1 and 2 3.4.13-1 Amendment No. (Unit 1)

Amendment No. (Unit 2)

RCS Operational LEAKAGE 3.4.13 SURVEILLANCE REQUIREMENTS SLIRVEILLANCE FREQUENCY SR 3.4.13.1 .......................... NOTES......................

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

2. Only required to be performed during steady state operation.

3. Not applicable to primary to secondary LEAKAGE.

Perform RCS water inventory balance. Once within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after achieving steady state operation 1 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months thereafter SR 3.4.13.2 ......................... 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 5 150 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months gallons per day through any one SG.

Vogtle Units 1 and 2 Amendment No. (Unit 1)

Amendment No. (Unit 2)

SG Tube lntegrity 3.4.17 3.4 REACTOR COOLANT SYSTEM (RCS) 3.4.17 Steam Generator (SG) Tube Integrity LC0 3.4.17 SG tube integrity shall be maintained.

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

APPLICABII-ITY: MODES 1, 2, 3, and 4.

ACTIONS

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

Separate Condition entry is allowed for each SG tube.

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

Steam Generator Program.

A.2 Plug the affected tube(@ in Prior to entering accordance with the Steam MODE 4 following the Generator Program. next refueling outage or SG tube inspection B. Required Action and B.l Be in MODE 3. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months associated Completion Time of Condition A not A m 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.

Vogtle Units 1 and 2 3.4.17-1 Amendment No. (Unit 1)

Amendment No. (Unit 2)

SG Tube Integrity 3.4.17 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.17.1 Verify SG tube integrity in accordance with the In accordance with Steam Generator Program. the Steam Generator Program SR 3.4.17.2 Verify that each inspected SG tube that satisfies Prior to entering the tube repair criteria is plugged in accordance MODE 4 following a with the Steam Generator Program. SG tube inspection Vogtle Units 1 and 2 Amendment No. (Unit 1)

Amendment No. (Unit 2)

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.8 Inservice Testing Proaram This program provides controls for inservice testing of ASME Code Class 1, 2, and 3 components. The program shall include the following:

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 Required Frequencies for Addenda terminology for performing inservice inservice testinq activities testinq 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 At least once per 184 days 6 months 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 testirrg activities; and

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

Vogtle Units 1 and 2 5.5-6 Amendment No.

Amendment No. (Unit 2)

Programs and Manuals 5.5 5.5 Proarams and Manuals (continued) 5.5.9 Steam Generator (SG) Proqram 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 foundn condition of the tubing with respect to the performance criteria for structural integrity and accident induced leakage. The "as foundn 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 or plugged to confirm that the performance criteria are being met.

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

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-secondarypressure differential and a safety factor of 1.4 against burst applied to the design basis accident primary-to-secondarypressure 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)

Vogtle Units 1 and 2 5.5-7 Amendment No. (Unit 1)

Amendment No. (Unit 2)

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.9 Steam Generator (SG) Program (continued)

2. Accident induced leakage performance criterion: The primary to secondary accident induced leakage rate for any design basis accident, other than a SG tube rupture, shall not exceed the leakage rate assumed in the accident analysis in terms of total leakage rate for all SGs and leakage rate for an individual SG. Leakage is not to exceed 1 gpm per SG, 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 LC0 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.

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

1. For Unit 2 during Refueling Outage 11 and the subsequent operating cycle, degradation found in the portion of the tube below 17 inches from the top of the hot leg tubesheet does not require plugging.

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. For Unit 2 during Refueling Outage 11 and the subsequent operating cycle, the portion of the tube below 17 inches from the top of the hot leg tubesheet is excluded. 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.

(continued)

Vogtle Units 1 and 2 5.5-8 Amendment No. (Unit 1)

Amendment No. (Unit 2)

Programs and Manuals 5.5 5.5 Programs and Manuals Steam Generator (SG) Program (continued)

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

Inspect 100% of the tubes at sequential periods of 120, 90, and, thereafter, 60 effective full power months. The first sequential period shall be considered to begin after the first inservice inspection of the SGs. In addition, inspect 50% of the tubes by the refueling outage nearest the midpoint of the period and the remaining 50% by the refueling outage nearest the end of the period. No SG shall operate for more than 48 effective full power months or two refueling outages (whichever is less) without being 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 nondestructive testing, or engineering evaluation indicates that a crack-like indication is not associated with a crack@),then the indication need not be treated as a crack.

e. Provisions for monitoring operational primary to secondary LEAKAGE.

Secondarv Water Chemistrv Program This program provides controls for monitoring secondary water chemistry to inhibit SG tube degradation. The program shall include:

a. ldentification of a sampling schedule for the critical variables and control points for these variables;

b. ldentification of the procedures used to measure the values of the critical variables;

c. ldentification of process sampling points;

d. Procedures for the recording and management of data;

e. Procedures defining corrective actions for all off control point chemistry conditions; and (continued)

Vogtle Units 1 and 2 5.5-9 Amendment No. (Unit 1)

Amendment No. (Unit 2)

Programs and Manuals 5.5 5.5 Programs and Manuals Secondary Water Chemistry Program (continued)

f. A procedure identifying the authority responsible for the interpretation of the data and the sequence and timing of administrative events, which is required to initiate corrective action.

Ventilation Filter Testinq Proqram (VFTP)

A program shall be established to implement the following required testing of Engineered Safety Feature (ESF) filter ventilation systems at the frequencies specified in accordance with Regulatory Guide 1.52, Revision 2, and ASME N510-1980:

a. Demonstrate for each of the ESF systems that an inplace test of the high efficiency particulate air (HEPA) filters shows a penetration and system bypass 5 0.05% when tested in accordance with Regulatory Guide 1.52, Revision 2, and ASME N510-1980 at the system flow rate specified below

10%.

ESF Ventilation System Flow Rate Control Room Emergency Filtration System (CREFS) 19,000 CFM Piping Penetration Area Filtration and Exhaust (PPAFES) 15,500 CFM

b. Demonstrate for each of the ESF systems that an inplace test of the charcoal adsorber shows a penetration and system bypass 50.05% when tested in accordance with Regulatory Guide 1.52, Revision 2, and ASME N510-1980 at the system flow rate specified below 10%.

ESF Ventilation System Flow Rate CREFS 19,000 CFM PPAFES 15,500 CFM

c. Demonstrate for each of the ESF systems that a laboratory test of a sample of the charcoal adsorber, when obtained as described in Regulatory Guide 1.52, Revision 2, shows the methyl iodide penetration less than or equal to the value specified below when tested in accordance with ASTM D3803-1989 at a temperature of 30°C and greater than or equal to the relative humidity specified below.

(continued)

Vogtle Units 1 and 2 5.5-10 Amendment No.

Amendment No. (unit (Unit 2) I

Programs and Manuals 5.5 5.5 Proarams and Manuals 5.5.1 1 Ventilation Filter Testiuq Proaram (VFTP) (continued)

ESF Ventilation System Penetration RH CREFS PPAFES

d. Demonstrate for each of the ESF systems that the pressure drop across the combined HEPA filters, the charcoal adsorbers, and CREFS cooling coils is less than the value specified below when tested in accordance with Regulatory Guide 1.52, Revision 2, and ASME N510-1989 at the system flow rate specified below 10%.

ESF Ventilation System Delta P Flow Rate CREFS 7.1 in. 19,000 CFM water gauge PPAFES 6 in. 15,500 CFM water gauge

e. Demonstrate that the heaters for the CREFS dissipate 2 95 kW when corrected to 460 V when tested in accordance with ASME N510-1989.

The provisions of SR 3.0.2 and SR 3.0.3 are applicable to the VFTP test frequencies.

5.5.1 2 Ex~losiveGas and Storaae Tank Radioactivitv Monitoring Proaram This program provides controls for potentially explosive gas mixtures contained in the Gaseous Waste Processing System, the quantity of radioactivity contained in each Gas Decay Tank, and the quantity of radioactivity contained in unprotected outdoor liquid storage tanks. The gaseous radioactivity quantities shall be determined following the methodology in Branch Technical Position (BTP) ETSB 11-5, "Postulated Radioactive Release due to Waste Gas System Leak or Failure." The liquid radwaste quantities shall be limited to 10 curies per outdoor tank in accordance with Standard Review Plan, Section 15.7.3, "Postulated Radioactive Release due to Tank Failures."

The program shall include:

(continued)

Vogtle Units 1 and 2 5.5-1 1 Amendment No.

Amendment No. (Unit (unit 2) I

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.12 Explosive Gas and Storaqe Tank Radioactivity Monitoring Proqram (continued)

a. The limits for concentrations of hydrogen and oxygen in the Gaseous Waste Processing System and a surveillance program to ensure the limits are maintained. Such limits shall be appropriate to the system's design criteria (i.e., whether or not the system is designed to withstand a hydrogen explosion);

b. A surveillance program to ensure that the quantity of radioactivity contained in each gas decay tank is less than the amount that would result in a whole body exposure of 2 0.5 rem to any individual in an unrestricted area, in the event of an uncontrolled release of the tanks' contents; and

c. A surveillance program to ensure that the quantity of radioactivity contained in all outdoor liquid radwaste tanks that are not surrounded by liners, dikes, or walls, capable of holding the tanks' contents and that do not have tank overflows and surrounding area drains connected to the Liquid Radwaste Treatment System is limited to 5 10 curies per tank, excluding tritium and dissolved or entrained noble gases. This surveillance program provides assurance that in the event of an uncontrolled release of the tank's contents, the resulting concentrations would be less than the limits of 10 CFR 20, Appendix B, Table 2, Column 2, at the nearest potable water supply and the nearest surface water supply in an unrestricted area.

The provisions of SR 3.0.2 and SR 3.0.3 are applicable to the Explosive Gas and Storage Tank Radioactivity Monitoring Program surveillance frequencies.

5.5.13 Diesel Fuel Oil Testing Proqram A diesel fuel oil testing program to implement required testing of both new fuel oil and stored fuel oil shall be established. The program shall include sampling and testing requirements, and acceptance criteria, all in accordance with applicable ASTM Standards. The purpose of the program is to establish the following:

a. Acceptability of new fuel oil for use prior to addition to storage tanks by determining that the fuel oil has:

1. an API gravity or an absolute specific gravity within limits, or an API gravity or specific gravity within limits when compared to the supplier's certificate;

2. a flash point within limits for ASTM 2D fuel oil, and, if gravity was not determined by comparison with supplier's certification, a kinematic viscosity within limits for ASTM 2D fuel oil; and (continued)

Vogtle Units 1 and 2 5.5- 12 Amendment No.

Amendment No. (unit 2)

(Unit I

Programs and Manuals 5.5 5.5 Proarams and Manuals Diesel Fuel Oil Testinq Program (continued)

3. a clear and bright appearance with proper color.

b. Other properties for ASTM 2D fuel oil are within limits within 30 days following sampling and addition to storage tanks; and

c. Total particulate concentration of the fuel oil is 5 10 mgll when tested every 31 days.

The provisions of SR 3.0.2and SR 3.0.3are applicable to the Diesel Fuel Oil Testing Program surveillance frequencies.

5.5.14 Technical S~ecifications(TS) Bases Control Proaram This program provides a means for processing changes to the Bases of these Technical Specifications.

a. Changes to the Bases of the TS shall be made under appropriate administrative controls and reviews

b. Licensees may make changes to Bases without prior NRC approval provided the changes do not require either of the following:

1. a change in the TS incorporated in the license; or

2. a change to the updated FSAR or Bases that requires NRC approval pursuant to 10 CFR 50.59.

c. The Bases Control Program shall contain provisions to ensure that the Bases are maintained consistent with the FSAR.

d. Proposed changes that meet the criteria of (b) above shall be reviewed and approved by the NRC prior to implementation. Changes to the Bases implemented without prior NRC approval shall be provided to the NRC on a frequency consistent with 10 CFR 50.71(e).

5.5.15 Safetv Function Determination Proqram (SFDP)

This program ensures loss of safety function is detected and appropriate actions taken. Upon entry into LC0 3.0.6,an evaluation shall be made to determine if loss of safety function exists. Additionally, other appropriate actions may be taken as a result of the support system inoperability and corresponding exception to (continued)

Vogtle Units 1 and 2 5.5-13 Amendment No.

Amendment No. (Unit 2)

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.15 Safetv Function Determination Proqram (SFDP) (continued) entering supported system Condition and Required Actions. This program implements the requirements of LC0 3.0.6. The SFDP shall contain the following:

a. Provisions for cross train checks to ensure a loss of the capability to perform the safety function assumed in the accident analysis does not go undetected;

b. Provisions for ensuring the plant is maintained in a safe condition if a loss of function condition exists;

c. Provisions to ensure that an inoperable supported system's Completion Time is not inappropriately extended as a result of multiple support system inoperabilities; and

d. Other appropriate limitations and remedial or compensatory actions.

A loss of safety function exists when, assuming no concurrent single failure, a safety function assumed in the accident analysis cannot be performed. For the purpose of this program, a loss of safety function may exist when a support system is inoperable, and:

a. A required system redundant to the system(s) supported by the inoperable support system is also inoperable; or

b. A required system redundant to the system(s) in turn supported by the inoperable supported system is also inoperable; or

c. A required system redundant to the support system(s) for the supported systems (a) and (b) above is also inoperable.

The SFDP identifies where a loss of safety function exists. If a loss of safety function is determined to exist by this program, the appropriate Conditions and Required Actions of the LC0 in which the loss of safety function exists are required to be entered.

MS and RN Piping Inspection Proqram This program shall provide for the inspection of the four Main Steam and Feedwater lines from the containment penetration flued head outboard welds, up to the first five-way restraint. The extent of the inservice examinations completed during each inspection interval (ASME Code Section XI) shall provide 100%

(continued)

Vogtle Units 1 and 2 5.5-14 Amendment No.

Amendment No. (Unit 2)

Programs and Manuals 5.5 5.5 Programs and Manuals (continued)

MS and FW Pipinu lns~ectionProqram (continued) volumetric examination of circumferential and longitudinal welds to the extent practical. This augmented inservice inspection is consistent with the requirements of NRC Branch Technical Position MEB 3-1, "Postulated Break and Leakage Locations in Fluid System Piping Outside Containment," November 1975 and Section 6.6 of the FSAR.

Containment Leakaqe Rate Testinq Proqram A program shall be established to implement the leakage rate testing of the containment as required by 10 CFR 50.54(0) and 10 CFR 50, Appendix J, Option B, as modified by approved exemptions. This program shall be in accordance with the guidelines contained in Regulatory Guide 1.I 63, "Performance-BasedContainment Leak-Testing Program," dated September 1995, as modified by the following exceptions:

1. Leakage rate testing for containment purge valves with resilient seals is performed once per 18 months in accordance with LC0 3.6.3, SR 3.6.3.6 and SR 3.0.2.

2. Containment personnel air lock door seals will be tested prior to reestablishing containment integrity when the air lock has been used for containment entry. When containment integrity is required and the air lock has been used for containment entry, door seals will be tested at least once per 30 days during the period that containment entry(ies) is (are) being made.

3. The visual examination of containment concrete surfaces intended to fulfill the requirements of 10 CFR 50, Appendix J, Option B testing, will be performed in accordance with the requirements of and frequency specified by ASME Section XI Code, Subsection IWL, except where relief has been authorized by the NRC. At the discretion of the licensee, the containment concrete visual examinations may be performed during either power operation, e.g., performed concurrently with other containment inspection-related activities such as tendon testing, or during a maintenancelrefueling outage.

4. A one time exception to NEI 94-01, Rev. 0, "Industry Guidelines for Implementing Performance-BasedOption of 10 CFR 50, Appendix J":

Section 9.2.3: The next Type A test, after the March 2002 test (continued)

Vogtle Units 1 and 2 5.5-15 Amendment No.

Amendment No. (Unit 2)

Programs and Manuals 5.5 5.5 Programs and Manuals Containment Leakaqe Rate Testing Proqram (continued) for Unit 1 and the March 1995 test for Unit 2, shall be performed within 15 years.

The peak calculated primary containment internal pressure for the design basis loss of coolant accident, Pa, is 37 psig.

The maximum allowable containment leakage rate, La,at Pa, is 0.2% of primary containment air weight per day.

Leakage rate acceptance criteria are:

a. Containment overall leakage rate acceptance criteria are 5 1.0 La. During the first unit startup following testing in accordance with this program, the leakage rate acceptance criteria are I 0.60 Lafor the combined Type B and Type C tests, and I 0.75 Lafor Type A tests;

b. Air lock testing acceptance criteria are:

1) Overall air lock leakage rate is 5 0.05 Lawhen tested at 2 Pa,

2) For each door, the leakage rate is I 0.01 Lawhen pressurized to 2 Pa.

The provisions of SR 3.0.2 do not apply to the test frequencies specified in the Containment Leakage Rate Testing Program.

'The provisions of SR 3.0.3 are applicable to the Containment Leakage Rate Testing Program.

5.5.1 8 Confinuration Risk Manaqement Proaram The Configuration Risk Management Program (CRMP) provides a proceduralized risk-informed assessment to manage the risk associated with equipment inoperability. The program applies to technical specification structures, systems, or components for which a risk-informed allowed outage time has been granted. The program shall include the following elements:

a. Provisions for the control and implementation of a Level 1 at power internal events PRA-informed methodology. The assessment shall be capable of evaluating the applicable plant configuration.

(continued)

Vogtle Units 1 and 2 5.5-16 Amendment No.

Amendment No. (Unit 2) I

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.18 Confiquration Risk Management Proaram (continued)

b. Provisions for performing an assessment prior to entering the LC0 Condition for preplanned activities.

c. Provisions for performing an assessment after entering the LC0 Condition for unplanned entry into the LC0 Condition.

d. Provisions for assessing the need for additional actions after the discovery of additional equipment out of service conditions while in the LC0 Condition.

e. Provisions for considering other applicable risk significant contributors such as Level 2 issues and external events, qualitatively or quantitatively.

5.5.1 9 Batterv Monitoring and Maintenance Proqram This program provides for restoration and maintenance, based on the recommendations of IEEE Standard 450-1995, "IEEE Recommended Practice for Maintenance, Testing, and Replacement of Vented Lead-Acid Batteries for Stationary Applications," of the following:

a. Actions to restore battery cells with float voltage < 2.13 V, and b Actions to equalize and test battery cells that had been discovered with electrolyte level below the top of the plates.

Vog'tle Units 1 and 2 Amendment No.

Amendment No. (Unit 2) I

Programs and Manuals 5.5 Sample Size Criteria Time After Initial Structural Integrity Testing of Containment, Years (Lift-Off Testing Schedule, Containment No. 1)

Time After Initial Structural Integrity Testing of Containment, Years (Lift-Off Testing Schedule, Containment No. 2)

Schedule to be used provided:

a. The containments are identical in all aspects such as size, tendon system, design, materials of construction, and method of construction. The tendon system for Unit 2 does not provide for detensioning. Detensioning can be performed only on the Unit 1 tendon system.

b. The l-year inspection for Unit 2 will consist of a visual inspection only. No lift-off testing will be performed on Unit 2 until the 3-year inspection.

c. There is no unique situation that may subject either containment to a different potential for structural or tendon deterioration.

d. The Unit 1 and Unit 2 surveillances may be performed back-to-back to facilitate detensioning of Unit 1 tendons during the Unit 2 surveillance.

Figure 5.5.6-1 Schedule of Lift-Off Testing for Two Containments at a Site Vogtle Units 1 and 2 Amendment No.

Amendment No. (Unit 2)

(Unit I

Reporting Requirements 5.6 5.6 Reporting Requirements 5.6.9 Tendon Surveillance Report Any abnormal degradation of the containment structure detected during the tests required by the Prestressed 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.

Steam Generator Tube Inspection Report 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,

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.

Vogtle Units 1 and 2 Amendment No. (Unit 1)

Amendment No. (Unit 2)

Enclosure 4 Vogtle Electric Generating Plant Application for Technical Specification Improvement Regarding Steam Generator Tube Integrity Proposed Technical Specification Bases Changes

TABLE OF CONTENTS REACTOR COOLANT SYSTEM (RCS) ........................................ B 3.4.1.1 RCS Pressure. Temperature. and Flow Departure from Nucleate Boiling (DNB) Limits........................................

RCS Minimum Temperature for Criticality ......................................

RCS Pressure and Temperature (PTT) Limits ................................

RCS Loops -- MODES 1 and 2 ......................................................

RCS Loops -- MODE 3 ..................................................................

RCS Loops -- MODE 4 ..................................................................

RCS Loops -- MODE 5. Loops Filled .............................................

RCS Loops -- MODE 5. Loops Not Filled.......................................

Pressurizer ....................................................................................

Pressurizer Safety Valves ..............................................................

Pressurizer Power Operated Relief Valves (PORVs) .....................

Cold Overpressure Protection Systems (COPS)............................

RCS Operational LEAKAGE ..........................................................

RCS Pressure Isolation Valve (PIV) Leakage ................................

RCS Leakage Detection Instrumentation.......................................

RCS Specific Activity .....................................................................

Steam Generator (SG) Tube Intearitv............................................

EMERGENCY CORE COOLING SYSTEMS (ECCS) ................... B 3.5.1.1 Accumulators .................................................................................

ECCS . Operating ........................................................................

ECCS -- Shutdown ........................................................................

Refueling Water Storage Tank (RWST) ........................................

Seal Injection Flow.........................................................................

Recirculation Fluid pH Control System...........................................

CONTAINMENT SYSTEMS...........................................................

Containment ..................................................................................

Containment Air Locks...................................................................

Containment Isolation Valves ........................................................

Containment Pressure ...................................................................

Containment Air Temperature........................................................

Containment Spray and Cooling Systems (Atmospheric and Dual) ...............................................................................

Deleted .........................................................................................

(continued)

Vogtle Units 1 and 2 Rev. 2-3/05

RCS Loops -MODES 1 and 2 B 3.4.4 BASES APPLICABLE All of the accidenvsafety analyses performed at full rated thermal SAFETY ANALYSES power assume that all four RCS loops are in operation as an initial (continued) condition. Some accidenvsafety analyses have been performed at zero power conditions assuming only two RCS loops are in operation to conservatively bound lower modes of operation. The events which assume only two RCPs in operation include the uncontrolled RCCA (Bank) withdrawal from subcritical and the rod ejection events. While all accidenvsafety analyses performed at full rate thermal power assume that all the RCS loops are in operation, selected events examine the effects resulting from a loss of RCP operation. These include the complete and partial loss of forced RCS flow, reactor coolant pump rotor seizure, and reactor coolant pump shaft break events. For each of these events, it is demonstrated that all the applicable safety criteria are satisfied. For the remaining accidenvsafety analyses, operation of all four RCS loops during the transient up to the time of reactor trip is assumed thereby ensuring that all the applicable acceptance criteria are satisfied. Those transients analyzed beyond the time of reactor trip were examined assuming that a loss of offsite power occurs which results in the RCPs coasting down.

By ensuring that the plant operates with all RCS loops in operation in MODES 1 and 2, adequate heat transfer is provided between the fuel cladding and the reactor coolant.

RCS Loops -MODES 1 and 2 satisfy Criterion 2 of 10 CFR 50.36 (cX2Xii).

The purpose of this LC0 is to require an adequate forced flow rate for core heat removal. Flow is represented by the number of RCPs in operation for removal of heat by the SGs. To meet safety analysis acceptance criteria for DNB, four pumps are required at rated power.

An OPERABLE RCS loop consists of an OPERABLE RCP in operation providing forced flow for heat transport and an OPERABLE S G S w.

(continued)

Vogtle Units 1 and 2 Rev. 1-10/01

RCS Loops -MODE 3 B 3.4.5 BASES LC0 change to the flow characteristics of the RCS, the input (continued) values of the coastdown curve must be revalidated by conducting the test again.

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

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

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

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

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

APPLICABILITY In MODE 3, this LC0 ensures forced circulation of the reactor coolant to remove decay heat from the core and to provide proper boron mixing. The most stringent condition of the LCO, that is, two RCS loops OPERABLE and two RCS loops in operation, applies to MODE 3 with RTBs in the closed position. The least stringent condition, that is, two RCS loops OPERABLE and one RCS loop in operation, applies to MODE 3 with the RTBs open.

Operation in other MODES is covered by:

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

LC0 3.4.6, "RCS LOOPS-MODE 4";

LC0 3.4.7, "RCS Loops -MODE 5, Loops Filled";

LC0 3.4.8, "RCS Loops -MODE 5, Loops Not Filled";

LC0 3.9.5, "Residual Heat Removal (RHR) and Coolant Circulation -High Water Level" (MODE 6); and LC0 3.9.6, "Residual Heat Removal (RHR) and Coolant Circulation -Low Water Level" (MODE 6).

(continued)

Vogtle Units 1 and 2 Revision No. 0

RCS Loops -MODE 4 B 3.4.6 BASES LC0 An OPERABLE RCS loop is comprised of an OPERABLE RCP and (continued) an OPERABLE S s

-which has the minimum water level specified in SR 3.4.6.2, and the necessary aspects of the Auxiliary Feedwater and Condensate Storage Tank Systems available to provide feedwater. Additionally, the OPERABILITY of an SG must include a means by which the decay heat may be removed (i.e., the capability of the atmospheric relief valve to stroke or the condenser is available).

Similarly for the RHR System, an OPERABLE RHR loop comprises an OPERABLE RHR pump capable of providing forced flow to an OPERABLE RHR heat exchanger. RCPs and RHR pumps are OPERABLE if they are capable of being powered and are able to provide forced flow if required.

APPLICABILITY In MODE 4, this LC0 ensures forced circulation of the reactor coolant to remove decay heat from the core and to provide proper boron mixing. One loop of either RCS or RHR provides sufficient circulation for these purposes. However, two loops consisting of any combination of RCS and RHR loops are required to be OPERABLE to meet single failure considerations.

Operation in other MODES is covered by:

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

LC0 3.4.5, "RCS Loops - MODE 3";

LC0 3.4.7, "RCS Loops - MODE 5, Loops Filled";

LC0 3.4.8, "RCS Loops - MODE 5, Loops Not Filled";

LC0 3.9.5, "Residual Heat Removal (RHR) and Coolant Circulation - High Water Level" (MODE 6); and LC0 3.9.6, "Residual Heat Removal (RHR) and Coolant Circulation - Low Water Level" (MODE 6).

ACTIONS If one required RCS loop is inoperable and two RHR loops are inoperable, redundancy for heat removal is lost. Action must be initiated to restore a second RCS or RHR loop to OPERABLE status. The immediate Completion Time reflects the importance of maintaining the availability of two paths for heat removal.

(continued)

Vogtle Units 1 and 2 B 3.4.6-3 Revision No. 0

RCS Loops -MODE 5, Loops Filled B 3.4.7 BASES LC0 Utilization of Note 1 is permitted provided the following conditions are (continued) met, along with any other conditions imposed by initial startup test procedures:

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

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

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

Note 2 allows one RHR loop to be inoperable for a period of up to 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months , provided that the other RHR loop is OPERABLE and in operation. This permits periodic surveillance tests to be performed on the inoperable loop during the only time when such testing is safe and possible.

Note 3 requires that the secondary side water temperature of each SG be < 50°F above each of the RCS cold leg temperatures before the start of a reactor coolant pump (RCP) during MODE 5 with the RCS loops filled. This restriction is to prevent a low temperature overpressure event due to a thermal transient when an RCP is started.

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

RHR pumps are OPERABLE if they are capable of being powered and are able to provide flow if required. A F F W E W B S SG can perform as a heat sink when it has an adequate water level and is O P E R A B L E E

. Additional requirements for an SG to be available as a heat sink are:

a. RCS loops and reactor pressure vessel filling and venting complete; and (continued)

Vogtle Units 1 and 2 B 3.4.7-3 Revision No. 0

RCS Operational LEAKAGE B 3.4.13 BASES (continued)

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 LOCA; the amount of leakage can affect the probability of such an event. The safety analyses for an event resulting in steam discharge to the atmosphere The RCS operational LEAKAGE satisfies Criterion 2 of 10 CFR 50.36 (cX2Xii).

I RCS operational LEAKAGE shall be limited to:

a. Pressure Boundary LEAKAGE No pressure boundary LEAKAGE is allowed, being indicative of an off-normal condition. LEAKAGE of this type is unacceptable as the leak itself could cause further deterioration, resulting in higher LEAKAGE. Violation of this LC0 could result in continued degradation of the RCPB. LEAKAGE past seals and gaskets is not pressure boundary LEAKAGE.

b. Unidentified LEAKAGE One gallon per minute (gpm) of unidentified LEAKAGE is allowed as a reasonable minimum detectable amount that the containment air monitoring and containment sump level monitoring equipment can detect within a reasonable time period. Violation of this LC0 could result in continued degradation of the RCPB, if the LEAKAGE is from the pressure boundary.

.: Identified LEAKAGE Up to 10 gprn of identified LEAKAGE is considered allowable 1 because LEAKAGE is from known sources that do not interfere with detection of unidentified LEAKAGE and is well within the capability of the RCS Makeup System. Identified LEAKAGE includes LEAKAGE to the containment from specifically known and located sources, but does not include pressure boundary Vogtle Units 1 and 2 Revision No. 0

RCS Operational LEAKAGE B 3.4.13 LEAKAGE or controlled reactor coolant pump (RCP) seal leakoff (a normal function not considered LEAKAGE). Violation of this LC0 could result in continued degradation of a component or system.

d.

Primarv to Secondarv LEAKAGE Throush Anv One SG The limit of 150 qallons per dav per SG is based on the operational LEAKAGE performance criterion in NEI 97-06, Steam Generator Prosram Guidelines (Ref. 4). The Steam Generator Prosram operational LEAKAGE performance criterion in NEI 97-06 states, "The RCS operational primarv to secondarv leakaqe throush anv one SG shall be limited to 150 gallons per dav." The limit is based on operatins experience with SG tube deqradation mechanisms that result in tube leakase. The o~erationalleakase rate criterion in coniunction with the implementation of the Steam Generator Prosram is an effective measure for minimizins the fresuencv of steam senerator tube ruptures.

APPLICABILITY In MODES I, 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.

LC0 3.4.14, "RCS Pressure Isolation Valve (PIV) Leakage,"

measures leakage through each individual PIV and can impact this LCO. Of the two PlVs in series in each isolated line, leakage measured through one PIV does not result in RCS LEAKAGE when the other is leak tight. If both valves leak and result in a loss of mass Vogtle Units 1 and 2 Revision No. 0

RCS Operational LEAKAGE B 3.4.13 from the RCS, the loss must be included in the allowable identified LEAKAGE.

I ACTIONS -

A. 1 Unidentified LEAKAGEx; identified LEAKAGE--

in excess of the LC0 limits must be reduced to within limits within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months . This Completion Time allows time to verify leakage rates and either identify unidentified LEAKAGE or reduce LEAKAGE to within limits before the reactor must be shut down. This action is necessary to prevent further deterioration of the RCPB.

B.l and B.2 If any pressure boundary LEAKAGE exists, or ~ r i m a wto secondaw LEAKAGE is not within limit. or if unidentified -a identified L E A K A G E M 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 brought to lower pressure conditions to reduce the severity of the LEAKAGE and its potential consequences. It should be noted that LEAKAGE past seals and gaskets is not pressure boundary LEAKAGE. The reactor must be brought to MODE 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and MODE 5 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months .

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

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

SURVEILLANCE REQUIREMENTS Verifying RCS LEAKAGE to be within the LC0 limits ensures the integrity of the RCPB is maintained. Pressure boundary LEAKAGE would at first appear as unidentified LEAKAGE and can only be positively identified by inspection. It should be noted that LEAKAGE past seals and gaskets is not pressure boundary LEAKAGE.

Unidentified LEAKAGE and identified LEAKAGE are determined by performance of an RCS water inventory balance. k m e t y b The RCS water inventory balance must be performed with the reactor at steady state operating conditions. The Surveillance is modified by two Notes. Note Istates-that ?- this SR is not required to be Vogtle Units Iand 2 Revision No. 0

RCS Operational LEAKAGE B 3.4.13 performed in MODES 3 and 4 until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months of steady state operation have been established. In all cases, this SR is required to be performed prior to entering MODE 2 to ensure the assessment of RCS leakage prior to critical operation.

Steady state operation is required to perform a proper inventory balance; calculations during maneuvering are not useful and a Note requires the Surveillance to be performed when steady state is established. For RCS operational LEAKAGE determination by water inventory balance, steady state is defined as stable RCS pressure, temperature, power level, pressurizer and makeup tank levels, makeup and letdown, and RCP seal injection and return flows.

An early warning of pressure boundary LEAKAGE or unidentified LEAKAGE is provided by the automatic systems that monitor the containment atmosphere radioactivity and the containment sump level. It should be noted that LEAKAGE past seals and gaskets is not pressure boundary LEAKAGE. These leakage detection systems are specified in LC0 3.4.15, "RCS Leakage Detection Instrumentation."

Note 2 s that this SR is not a ~ ~ ~ i c to a bsrimarv b to twondary GE LEAKAGF of 15Q srallons ~ edav r earnnot b~

ursd acwratehc by an R r S water i n m t w v balance.

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. The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Frequency after steady state operation has been achieved provides for those situations where a transient occurs, and the duration of the transient is such that the 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Frequency plus the 25% extension allowed by SR 3.0.2 would be exceeded. In this event, the SR would be due within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after steady state operation has been reestablished.

This SR verifies that ~rimarvto secondarv LEAKAGE is less than or eaual to 150 aallons Der dav throuah anv one SG. Satisfvina the primarv to secondarv LEAKAGE limit ensures that the o~erational LEAKAGE ~erforrnancecriterion in the Steam Generator Proaram is met. If this SR is not met, com~liancewith LC0 3.4.1 7, 'Steam Generator Tube Intmritv," should be evaluated. The 150 aallons dav limit is measured at room temwrature as described in Reference

5. The o~erationalLEAKAGE rate limit amlies to LEAKAGE throwh anv one SG. If it is not ~racticalto assian the LEAKAGE to an individual SG, all the wirnarv to secondary LEAKAGE should bq wnservativelv assumed to be from one SG.

The Surveillance is modified bv a Note which states that thg Surveillance is not reauired to be ~erformeduntil 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after establishment of steadv state omration. For RCS ~rimarvt~

secondarv LEAKAGE determination. steadv state is defined as stable RCS Dressure. tem~erature,wwer level. ~ressurirerand makeup Vogtle Units 1 and 2 Revision No. 0

RCS Operational LEAKAGE B 3.4.13 tank levels, makeup and letdown, and RCP seal iniection and return flows.

The Surveillance Freauencv of 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months is a reasonable interval to trend primaw to secondaw LEAKAGE and recwnizes the importance of eariv leakaae detection in the prevention of accidents. The ~rimary to secondaw LEAKAGE is determined usina continuous process radiation monitors or radiuchemical arab sam~linain accordance with the EPRI auidelines (Ref.-.3 REFERENCES 1. 10 CFR 50, Appendix A, GDC 30.

2. Regulatory Guide 1.45, May 1973.

3. FSAR, Section 15.

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

5. EPRI. "Pressurized Water Reactor Primary-toSecondaw Leak Vogtle Units 1 and 2 Revision No. 0

SG Tube lntegrity B 3.4.1 7 B 3.4 REACTOR COOLANT SYSTEM (RCS)

B 3.4.17 Steam Generator (SG) Tube lntegrity BASES BACKGROUND Steam generator (SG) tubes are small diameter, thin walled tubes that carry primary coolant through the primary to secondary heat exchangers.

The SG tubes have a nurrrber of important safety functions. Steam generator tubes are an integral part of the reactor coolant pressure boundary (RCPB) and, as such, are relied on to maintain the primary system's pressure and inventory. The SG tubes isolate the radioactive fission products in the primary coolant from the secondary system. In addition, as part of the RCPB, the SG tubes are unique in that they act as the heat transfer surface between the primary and secondary systems to remove heat from the primary system. This Specification addresses only the RCPB integrity function of the SG. The SG heat removal function is addressed by LC0 3.4.4, "RCS Loops - MODES 1 and 2," LC0 3.4.5, "RCS Loops - MODE 3," LC0 3.4.6, "RCS Loops - MODE 4," and LC0 3.4.7, "RCS Loops - MODE 5, Loops Filled."

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

Steam generator tubirrg 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, "Steam Generator (SG) Program," 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.

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

Vogtle Units 1 and 2 B 3.4.17-1 Rev. X.X

SG Tube Integrity B 3.4.17 BASES APPI-ICABLE The steam generator tube rupture (SGTR) accident is the limiting design SAFETY basis event for SG tubes and avoiding an SGTR is the basis for this ANALYSES Specification. The analysis of a SGTR event assumes a boundirrg primary to secondary LEAKAGE rate equal to the operational LEAKAGE rate limits in LC0 3.4.1 3, "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 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 1 gallon per minute or is assumed to increase to 1 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 LC0 3.4.16, "RCS Specific Activity," limits. For accidents that assume fuel damage, the primary coolant activity is a function of the amount of activity released from the damaged fuel. The dose consequences of these events are within the limits of GDC 19 (Ref. 2), 10 CFR 100 (Ref. 3) or the NRC approved licensing basis (e.g., a small fraction of these limits).

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

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

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

For Unit 2 during Refueling Outage 11 and the subsequent operating cycle, degradation found in the portion of the tube below 17 inches from the top of the hot leg tubesheet does not require plugging. For Unit 2 during Refueling Outage 11 and the subsequent operating cycle, the portion of the tube below 17 inches from the top of the hot leg tubesheet is excluded from tube inspections (Ref. 7). The tube-to-tubesheet weld is not considered part of the tube.

Vogtle Units 1 and 2 B 3.4.17-2 Rev. X.X

SG Tube Integrity B 3.4.17 BASES LC0 (continued) A SG tube has tube integrity when it satisfies the SG performance criteria.

The SG performance criteria are defined in Specification 5.5.9, "Steam Generator Program," and describe acceptable SG tube performance.

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

There are three SG performance criteria: structural integrity, accident induced 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 "significantnis defined as "An accident loading condition other than differential pressure is considered significant when the addition of such loads in the assessment of the structural integrity performance criterion could cause a lower structural limit or limiting burst/collapse condition to be established." For tube integrity evaluations, except for circumferential degradation, axial thermal loads are classified as secondary loads. For circumferential degradation, the classification of axial thermal loads as primary or secondary loads will be evaluated on a case-by-case basis.

'The division between primary and secondary classifications will be based on detailed analysis andlor testing.

Structural integrity requires that the primary membrane stress intensity in a tube not exceed the yield strength for all ASME Code, Section Ill, 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 Ill, Subsection NB (Ref. 4) and Draft Regulatory Guide 1.I21 (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 Vogtle Units 1 and 2 B 3.4.1 7-3 Rev. X.X

SG Tube Integrity B 3.4.17 BASES LC0 (continued) analysis assumes that accident induced leakage does not exceed 1 gpm per SG, 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 SG tube conditions during plant operation. The limit on operational LEAKAGE is contained in LC0 3.4.1 3, "RCS Operational LEAKAGE," and limits primary to secondary LEAKAGE through any one SG to 150 gallons per day. This limit is based on the assumption that a single crack leaking this amount would not propagate to a SGTR under the stress conditions of a LOCA or a main steam line break. If this amount of LEAKAGE is due to more than one crack, the cracks are very small, and the above assumption is conservative.

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

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

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

A.l 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 3.4.17.2. 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 Vogtle Units 1 and 2 B 3.4.17-4 Rev. X.X

SG Tube Integrity B 3.4.17 BASES Actions (continued) 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 operation until the next inspection is supported by the operational assessment.

B.l and 8.2 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 3.4.17.1 REQUIREMENTS During shutdown periods the SGs are inspected as required by this SR and the Steam Generator Program. NEI 97-06, Steam Generator Program Guidelines (Ref. I),and its referenced EPRl 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.

Vogtle Units 1 and 2 Rev. X.X

SG Tube Integrity B 3.4.17 BASES SURVEILLANCE REQUIREMENTS (continued)

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

lnspection methods are a function of degradation morphology, nondestructive examination (NDE) technique capabilities, and inspection locations.

The Steam Generator Program defines the Frequency of SR 3.4.17.1.

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

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 5.5.9are 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 until the next inspection of the subject tube(s). Reference 1 provides guidance for performing operational assessments to verify that the tubes remaining in service will continue to meet the SG performance criteria.

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

Vogtle Units 1 and 2 6 3.4.17-6 Rev. X.X

SG Tube Integrity B 3.4.17 BASES REFERENCES 1. NEI 97-06, "Steam Generator Program Guidelines."

2. 10 CFR 50 Appendix A, GDC 19.

3. 10 CFR 100.

4. ASME Boiler and Pressure Vessel Code, Section Ill, Subsection NB.

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

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

7. License Amendment Nos. 138 and 117, "Vogtle Electric Generating Plant Units 1 and 2, Re: Issuance of Amendments Regarding the Steam Generator Tube Surveillance Program (TAC Nos. MC8078 and MC8079)," September 21, 2005.

Vogtle Units 1 and 2 Rev. X.X

v t e Letter Sequence Request
TAC:MD0118, Steam Generator Tube Integrity (Open)
Initiation Request, Request Acceptance... Administration Questions Answers Results Approval... Other: ML063390071
MONTHYEAR2006-03-29 [Table View]

NL-06-0124, Application for Technical Specification Improvement Regarding Steam Generator Tube Integrity

Text

Enclosures:

1.0 INTRODUCTION

2.0 DESCRIPTION

3.0 BACKGROUND

6.0 REGULATORY ANALYSIS

10.0 REFERENCES

Navigation menu

NL-06-0124, Application for Technical Specification Improvement Regarding Steam Generator Tube Integrity

Text

Enclosures:

1.0 INTRODUCTION

2.0 DESCRIPTION

3.0 BACKGROUND

6.0 REGULATORY ANALYSIS

10.0 REFERENCES

Navigation menu

Search