Text

Application for Technical Specification Improvement Regarding Steam Generator Tube Integrity and Other Administrative Changes
	ML061080500
Person / Time
Site:	Oconee, Mcguire, McGuire
Issue date:	04/11/2006
From:	Gordon Peterson; Duke Energy Carolinas, Duke Power Co
To:	; Document Control Desk, Office of Nuclear Reactor Regulation
References
	Download: ML061080500 (99)
	v • d • e

a5 Duke GARY R. PETERSON r Vice President Eneirgyo McGuire Nuclear Statimn Duke Energy Corporation MGO1VP/ 12700 Hagers Ferry Rd.

Huntersvilfe, NC 28078 704 875 5333 April 11, 2006 704 875 4809 fax grpetersgduke-energy. corn U.S. Nuclear Regulatory Commission Document Control Desk Washington, D.C. 20555-0001

SUBJECT:

Duke Power Company LLC d/b/a Duke Energy Carolinas, LLC Oconee Nuclear Station, Units 1, 2, and 3 Docket Nos. 50-269, 50-270, and 50-287 McGuire Nuclear Station, Units 1 and 2 Docket Nos. 50-369 and 50-370 Application for Technical Specification Improvement Regarding Steam Generator Tube Integrity and Other Administrative Changes In acccrdance with the provisions of Section 50.90 of Title 10 of the Code of Federal Regulations (10 CFR), Duke Power Company LLC d/b/a Duke Energy Carolinas, LLC (Duke) is submitting a license amendment request (LAR) for the Facility Operating Licenses (FOL) and Technical Specifications (TS) for Oconee Nuclear Station Units 1, 2, and 3, and McGuire Nuclear Station, Units 1 and 2.

This LUR would revise the TS requirements related to steam generator tube integrity. The changes are consistent with NRC-approved Revision 4 to Technical Specification Task Force (TSTF) Standard Technical Specification Change Traveler, TSTF-449, "Steam Generator Tube Integrity." The availability of this TS improvement was announced in the Federal Register on May 6,'2005, (70 FR 24126), as part of the Consolidated Line Item Improvement Process (CLIIP).

Also, this LAR contains proposed changes to the Oconee FOLs that remove conditions that lire now outdated and superseded by the CLIIP. Additionally, the proposed changes revise an organizational description in Oconee and McGuire TS 5.2.1 that is solely administrative in nature and unrelated to the CLIIP.

Attachment 1 provides a description and assessment of the proposed amendment.

Attachment 2a provides the existing FOL and TS pages for Oconee Units 1, 2, and 3, marked-up to show the proposed changes.

Attachment 2b provides the existing TS pages for McGuire Units 1 and 2, marked-up to show the proposed changes.

Attachments 3a and 3b (FUTURE), providing revised, clean FOL, TS, and Bases pages for Oconee and McGuire, respectively, will be provided to the NRC at the time of issuance of the approved amendments.

fir (;))I www. duke-energy. corn

U. S. Nuclear Regulatory Commission April 11, 2006 Page 2 Attachment 4a provides the existing TS Bases pages for Oconee Units 1, 2, and 3, marked-up to show the proposed changes. b provides the existing TS Bases pages for McGuire Units 1 and 2, marked-up to show the proposed changes.

In accordance with 10 CFR 50.91, a copy of this application, with enclosures, is being provided to the designated official of the State of North Carolina and to the designated official of the State of South Carolina.

Implementation of this proposed change to the Oconee and McGuire Facility Operating Licenses and TS will require revision to the Oconee and McGuire Updated Final Safety Analysis Reports (UFSAR). Necessary UFSAR changes will be submitted in accordance with 10 CFR 50.71 (0).

Duke requests NRC approval of this CLIIP item by October 15, 2006, with each station's implementation to take place within 120 days after the completion of the Fall 2006 refueling outages on Oconee Unit 1 and McGuire Unit 2.

In a letter to the NRC dated February 15, 2006, Duke responded to NRC Generic Letter 2006-01 concerning steam generator tube integrity. In the February 15, 2006 letter, Duke committed to submit an LAR for Oconee Units 1, 2, and 3, and McGuire Units 1 and 2 (Option 1 of the GiL) related to steam generator tube integrity and consistent with NRC-approved Revision 4 to TSTF-449 as described above. The LAR submitted herein fulfills this regulatory commitment.

In accordance with Duke administrative procedures and the Quality Assurance Program Topical Report, the plant-specific changes contained in this LAR have been reviewed and approved by the respective Oconee or McGuire Plant Operations Review Committee. This LAR has also been reviewed and approved by the Duke Nuclear Safety Review Board.

If you should have any questions regarding this submittal, please contact J. S. Warren at 704-875-5171.

Very truly yours, eterson Attachments 2

U. S. Nuclear Regulatory Commission April 11, 2006 Page 3 Attachments:

1. Description and Assessment 2a. Proposed Facility Operating Licenses and Technical Specifications Changes (Mark-up) fDr Oconee Units 1, 2, and 3 2b. Proposed Technical Specifications Changes (Mark-up) for McGuire Units 1 and 2 3a. Proposed Facility Operating Licenses Pages, Technical Specifications Pages, and Bases Pages for Oconee Units 1, 2, and 3 (FUTURE) 3b. Proposed Technical Specifications Pages and Bases Pages for McGuire Units 1 and 2 (FUTURE) 4a. Proposed Technical Specifications Bases Changes (Mark-up) for Oconee Units 1, 2, and 3 4b. Proposed Technical Specifications Bases Changes (Mark-up) for McGuire Units 1 and 2 3

U. S. Nuclear Regulatory Commission April 11, 2006 Page 4 xc (with attachments):

W. D. Travers U. S. Nuclear Regulatory Commission Regional Administrator, Region II Atlanta Federal Center 61 Forsyth St., SW, Suite 23T85 Atlanta, GA 30303 L. N. Olshan (Addressee Only)

NRC Project Manager (Oconee)

U. S. Nuclear Regulatory commission Mail Stop 8 G9A Washington, DC 20555-0001 J. F. Stang, Jr. (Addressee Only)

NRC Project Manager (McGuire)

U. S. Nuclear Regulatory commission Mail Stop 8 H4A Washington, DC 20555-0001 M. C. Shannon Senior Resident Inspector U. S. Nuclear Regulatory Commission Oconee Nuclear Site J. B. Brady Senior Resident Inspector U. S. Nuclear Regulatory Commission McGuire Nuclear Site Beverly 0. Hall, Section Chief Radiation Protection Section 1645 Mail Service Center Raleigh, NC 27699-1645 H. J. Porter, Director Division of Radioactive Waste Management South Carolina Bureau of Land and Waste Management 2600 Bull Street Columbia, SC 29201 4

U. S. Nuclear Regulatory Commission April 11, 2006 Page 5 G. R. Paterson, affirms that he is the person who subscribed his name to the foregoing statement, and that all the matters and facts set forth herein are true and correct to the best of his knowledge.

R. Peterson, Site Vice President Subscribed and sworn to me: 4 /L67U51 //, c) ° Date C A7K 646 4~Notary Public My commission expires: 4&qas / I/, So0 .

Date 5

ATTACHMENT 1 Description and Assessment

1.0 INTRODUCTION

The proposed license amendment revises the requirements in the Technical Specification (TS) related to steam generator tube integrity. The changes are consistent with 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 Reqister on May 6, 2005 as part of the Consolidated Line Item Improvement Process (CLIIP).

2.0 DESCRIPTION

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

Revised Oconee and McGuire TS 1.1 definition of LEAKAGE

Revised Oconee and McGuire TS 3.4.13, "Reactor Coolant System (RCS) Operational LEAKAGE"

New Oconee TS 3.4.16, "Steam Generator (SG) Tube Integrity"

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

Revised Oconee TS 5.5.10, "Steam Generator (SG) Tube Surveillance Program," (after steam generator replacement)

Deleted Oconee TS 5.5.21, "Steam Generator (SG) Tube Surveillance Program," (until steam generator replacement)

Revised McGuire TS 5.5.9, "Steam Generator (SG) Tube Surveillance Program"

Revised Oconee and McGuire TS 5.6.8, "Steam Generator Tube Inspection Report"

Revised Oconee and McGuire TS 5.2.1, "Onsite and Offsite Organizations"

Revised Oconee Facility Operating Licenses Conditions 5 and 6 Proposed revisions to the TS Bases are also included in this application. As discussed in the NRC's model safety evaluation (SE), 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 Programs. The final two items listed above are additions to the CLIIP. These additional changes are discussed in Section 9.0.

3.0 BACKGROUND

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

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

1

5.0 TECHNICAL ANALYSIS

Duke Power Company LLC d/b/a Duke Energy Carolinas, LLC (Duke) has reviewed the SE published on March 2, 2005 (70 FR 10298) as part of the CLIIP Notice for Comment. This included the NRC Staff's SE, the supporting information provided to support TSTF-449, and the changes associated with Revision 4 to TSTF-449. Duke has concluded that the justifications presented in the TSTF proposal and the SE prepared by the NRC Staff are applicable to Oconee Nuclear Station, Units 1, 2, and 3; and McGuire Nuclear Station, Units 1 and 2, and justify this amendment for the incorporation of the changes to the Oconee and McGuire TS.

6.0 REGULATORY ANALYSIS

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

449, Revision 4.

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

Plant Name, Unit Nos. Oconee Nuclear Station, Units 1, 2, and 3 Steam Generator (SG) Model BWC ROTSG Effective Full Power Years (EFPY Unit 1: 1.2 yrs.

of service for currently installed Unit 2: 1.3 yrs.

SGs. Unit 3: <1.3 yr.

Tubing Material Alloy 690 Number of tubes per SG. 15,631 Number and percentage of tubes plugged in each SG. SG Tubes Plugged % Plugged 1A 31 0.20 1B 19 0.12 2A 6 0.04 2B 4 0.03 3A 0 0.0 3B 0 0.0 Number of tubes repaired in each None SG.

Degradation mechanism(s) Tube Support Plate Wear identified.

Current primary-to-secondary Per SG: 150 gpd leakage limits. Total: 300 gpd Leakage is evaluated at 77 OF.

2

Plant Name, Unit Nos. Oconee Nuclear Station, Units 1, 2, and 3 Approved Alternate Tube Repair None Criteria (ARC)

Approved SG Tube Repair None Methods Performance criteria for accident Accident leakage is calculated at the TS limit.

Plant Name, Unit Nos. McGuire Nuclear Station, Units 1 and 2 Steam Generator (SG) Model CFR80 Effective Full Power Years (EFPY Unit 1: 7.6 yrs.

of service for currently installed Unit 2: 6.7yrs.

SGs Tubing Material Alloy 690 Number of tubes per SG 6,633 Number and percentage of tubes SG Tubes Plugged % Plugged plugged in each SG.

1A 2 0.03 1B 2 0.03 iC 5 0.08 1D 4 0.06 2A 20 0.30 2B 3 0.05 2C 1 0.02 2D 4 0.06 Number of tubes repaired in each None SG.

Degradation mechanism(s) None identified.

Current primary-to-secondary Per SG: 135 gpd leakage limits. Total: 389 gpd Leakage is evaluated at 585 OF.

Approved Alternate Tube Repair None Criteria (ARC)

Approved SG Tube Repair None Methods Performance criteria for accident Accident leakage is calculated at the TS limits.

leakage. ________________________

3

7.0 NO SIGNIFICANT HAZARDS CONSIDERATION Duke has reviewed the proposed no significant hazards consideration determination published on March 2, 2005 (70 FR 10298) as part of the CLIIP. Duke has concluded that the proposed determ nation presented in the notice is applicable to Oconee and McGuire and the determ nation is hereby incorporated by reference to satisfy the requirements of 10 CFR 50.91 (et).

8.0 ENVIRONMENTAL EVALUATION Duke has reviewed the environmental evaluation included in the model SE published on March 2, 2005 (70 FR 10298) as part of the CLIIP. Duke has concluded that the Staff's findings presented in that evaluation are applicable to Oconee and McGuire and the evaluation is hereby incorporated by reference for this application.

9.0 PRECEDENT This application is being made in accordance with the CLIIP. In TS 3.4.13, "RCS Operational Leakage," the CLIIP reduces the allowable primary to secondary leakage from any one SG to 150 gallons per day and eliminates the TS requirement for total primary to secondary leakage through all SGs. The current Oconee TS already limits primary to secondary leakage to 150 gallons per day for one SG, thus it is not necessary to implement this portion of the CLIIP at Oconee. The current McGuire TS limits the one SG value to 135 gallons per day and the limit through all SGs to 389 gallons per day. This portion of the CLIIP is not being implemented at McGuire because these lower leakage rate limits are assumed in the applicable safety analyses. Thus, McGuire will maintain the current more restrictive TS limits for primary to secondary leakage. Also for McGuire, Insert B3.4.13A, as shown in the traveler, is not used because it is not needed in order for this Bases to accurately describe the TS.

For Oconee only, this LAR deletes current Conditions 5 and 6 on Page 8a from FOLs DPR-38, DPR-47, and DPR-55 for Oconee Units 1, 2, and 3, respectively. These conditions were imposed upon the Oconee FOLs in Amendments 318, 318, and 318, also for Oconee Units 1, 2, and 3, respectively. These amendments were issued by NRC letter and SE dated December 15, 2000. As stated in the SER, the purpose of these license conditions was to ensure that Duke would perform an adequate evaluation to demonstrate that gross structural failure and leakage of the reroll repair joints, used at Oconee at that time, would not occur in the event of a LBLOCA. Further, this evaluation was to demonstrate that adequate safety margins and defense-in-depth would be maintained in the design and installation of the reroll repairs at Oconee Units 1, 2, and 3. These FOL conditions are now obsolete since all the Oconee steam generators have now been replaced and there are no repaired tubes in service, all defective tubes are now plugged. The SER stated that these FOL conditions applied only until the SGs were replaced. Also, the inspections, evaluations, and reporting requirements required by these conditions are superseded by the changes to TS 5.5.10 and 5.6.8 contained in the NRC CLIIP and within this LAR. Thus Duke has determined that this additional change is consistent with the implementation of the NRC CLIIP at Oconee Units 1, 2, and 3.

Additionally, for both Oconee and McGuire, this license amendment request contains a proposed change unrelated to the CLIIP. This proposed change revises an organizational 4

description in TS 5.2.1 to conform to a Duke application for consent to the indirect transfer of control of the facility operating licenses submitted by a Duke letter to the NRC dated August 5, 2005 and approved by NRC letter and SE dated February 7, 2006. This change is solely administrative in nature.

These are the variations or deviations from, or additions to, the TS changes described in TSrF-449, Revision 4, or the NRC Staff's model SE published on March 2, 2005 (70 FR 10298), that Duke is proposing. Since the variations, deviations, and additional changes contained in this LAR are either solely administrative in nature, remove obsolete requirements, or are conservative variations or deviations from the CLIIP, Duke has determined that these changes, as discussed here within Section 9, are bounded by the NRC's model SE, no significant hazards consideration, and environmental evaluation.

10.0 REFERENCES

Federal Register Notices:

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

Notice of Availability published on May 6, 2005 (70 FR 24126) 5

Attachment 2a Oconee Nuclear Station Units 1, 2, and 3 Proposed Facility Operating Licenses Changes and Technical Specifications Changes (Mark-up)

OCONEE INSERTS OCONEE INSERT 3.4.13 A

NOTE-

NOT --------- ------------------------------------------------------

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.

OCONEE INSERT B 3.4.13 A The LCO requirement to limit primary to secondary LEAKAGE through any one SG to less than or equa Ito 150 gallons per day is less than the conditions assumed in the safety analyses.

OCONEE INSERT B 3.4.13 B

d. Primary to Secondary LEAKAGE Through Any One SG

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

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

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OCONEE INSERTS INSERT B 3.4.13 D (BWOG)

This SR verifies that primary to secondary LEAKAGE is less than or equal to 150 gallons per day through any one SG. Satisfying the primary to secondary LEAKAGE limit ensures that the operational LEAKAGE performance criterion in the Steam Generator Program is met. If this SR is not met, compliance with this LCO, as well as LCO 3.4.16, "Steam Generator Tube Integrity,"

should be evaluated. The 150 gallons per day limit is measured at room temperature as described in Ref. 5. The operational LEAKAGE rate limit applies to LEAKAGE through any cne SG. If it is not practical to assign the LEAKAGE to an individual SG, all the primary to secondary LEAKAGE should be conservatively assumed to be from one SG.

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

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

5).

OCONEE INSERT B 3.4.13 E

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

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

Page 2

OCONEE INSERTS INSERT 5.5.10 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 and 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-secondary pressure differential and a safety factor of 1.4 against burst applied to the design basis accident primary-to-secondary pressure differentials. Apart from the above requirements, additional loading conditions associated with the design basis accidents, or combination of accidents in accordance with the design and licensing basis, shall also be evaluated to determine if the associated loads contribute significantly to burst or collapse. In the assessment of tube integrity, those loads that do significantly affect burst or collapse shall be determined and assessed in combination with the loads due to pressure with a safety factor of 1.2 on the combined primary loads and 1.0 on axial secondary loads.

2. Accident induced leakage performance criterion: The primary to secondary accident induced leakage rate for any design basis accident, other than a SG tube rupture, shall not exceed the leakage rate assumed in the accident analysis in terms of total leakage rate for all SGs and leakage rate for an individual SG. Leakage is not to exceed 150 gpd 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 LCO 3.4.13, "RCS Operational LEAKAGE."

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OCONEE INSERTS INSERT 5.5.10 (cont.)

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

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

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

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

3. If crack indications are found in any SG tube, then the next inspection for each SG for the degradation mechanism that caused the crack indication shall not exceed 2 4 effective full power months or one refueling outage (whichever is less). If definitive information, such as from examination of a pulled tube, diagnostic non-destructive testing, or engineering evaluation indicates that a crack-like indication is not associated with a crack(s), then the indication need not be treated as a crack.

e. Provisions for monitoring operational primary to secondary LEAKAGE.

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OCONEE INSERTS INSERT 5.6.8 A report shall be submitted within 180 days after the initial entry into MODE 4 following completion of an inspection performed in accordance with Specification 5.5.10, 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 m schanism,

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, arid

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

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-8a - I 5.e -team Generator Circumferential Crack Report:

owing each inservice inspection of steam generator tubes, the NRC al be notified of the f wing prior to returning the steam generators to service:

a. Indicati f circumferential cracking in the secondary sid (lower roll in the upper tubesheet or per roll in the lower tubesheet) if rerol

b. Indication of circum ntial cracking in the oriaroll or heat affected zone adjacent to the tube-to-tubesheet s weld-if no rero resent.

c. Determination of the best-estie tleakage that would result from an analysis of the limiting Large Break Loss of ant Accident (LBLOCA) based on circumferential cracking in the original tube-t ubesh rolls, tube-to-tubesheet rerolls, and heat affected zones of seal we as found dun each inspection.

6. Demonstrate that the p ary-to-secondary leakage owing a LBLOCA, as described n Appendix A to BAW 74, is acceptable, based on the a ound condition of the SGs. This is required to de nstrate that adequate margin and defenin-depth are maintained. Ior the purpose his evaluation, acceptable means a best estima of the leakage expected in the eveof a LBLOCA that would not result in a significant increae of radionuclide release .g., in excess of 10 CFR 100 limits). A summary of this eval ion shall be provjeld to the NRC within 3 months following completion of steam gener r tube insel-v inspection with the report required by Technical Specification 5.6.8, Item FOR THE NUCLEAR REGULATORY COMMISSION Roy Zimmerman, Acting Director Office of Nuclear Reactor Regulation

Attachment:

1) Appendix A - Technical Specifications Renewed License No. DPR-38 Date of Issuance May 23, 2000 Renewed License No. DPR-38

- 8a - I Steam Generator Circumferential Crack Report: le ollowing each inservice inspection of steam generator tubes, the NRC shall otifieci of th following prior to returning the steam generators to service:

a. nd tion of circumferential cracking in the secondary side rolwer roll in the upper tubes et or upper roll in the lower tubesheet) if rerolled.

b. Indication orcumferential cracking in the origina or heat affected zone adjacent to the tube-to-t esheet seal weld-if no reroll resent.

c. Determination of the besttimate ai leakage that would result from an analysis of the limiting Large Break Los olant Accident (LBLOCA) based on circumferential cracking in the original tube- u sheet rolls, tube-to-tubesheet rerolls, and heat affected zones of seal we as fou during each inspection.

6. Demonstrate that the ary-to-secondary le ge following a LBLOCA, as described in Appendix A to BA 374, is acceptable, based o e as-found condition of the SGs. This is required to d onstrate that adequate margin andense-in-depth are maintained. For thq purpose Ithis evaluation, acceptable means a best e ate of the leakage expected in the evil of a LBLOCA that would not result in a significantrease of radionuclide relea (e.g., in excess of 10 CFR 100 limits). A summary of this equation shall be eded to the NRC within 3 months following completion of steam gen tor tube inset-

./-viceinspection with the report required by Technical Specification 5.6.8, Ite FOR THE NUCLEAR REGULATORY COMMISSION Roy P. Zimmerman, Acting Director Office of Nuclear Reactor Regulation

Attachment:

1) Appendix A - Technical Specifications Renewed License No. DPR-47 Date of issuance: May 23, 2000 Renewed License No. DPR-47

- Ba - I

5. Steam Generator Circumferential Crack Report:

F0ii Wi igeach inservice inspection of steam generator tubes, the NRC shall be notifio the followl nor to returning the steam generators to service:

a. Indication of ci ferential cracking in the secondary side roll (low iin the upper tubesheet or upper in the lower tubesheet) if rerolled.

b. Indication of circumferentia cking in the original roll eat affected zone adjacent to the tube-to-tubesheet seal weld-o reroll is prese

c. Determination of the best-estimate tota e that would result from an analysis of the limiting Large Break Loss of Coolan c nt (LBLOCA) based on circumferential cracking in the original tube-to-tube eet rolls, t -to-tubesheet rerolls, and heat affected zones of seal welds as nd during each inection.

6. Demonstrate that the prima o-secondary leakage following aLOCA, as described in Appendix A to BAW-237,s acceptable, based on the as-found co ition of the SGs. alhis is required to demon ate that adequate margin and defense-in-depth maintained. For the purpose of th valuation, acceptable means a best estimate of the leage expected in the event o LBLOCA that would not result in a significant increase of radio lide release (e.,in excess of 10 CFR 100 limits). A summary of this evaluation shall b provid o the NRC within 3 months following completion of steam generator tube ins vi( spection with the report required by Technical Specification 5.6.8, Item b.

FOR THE NUCLEAR REGULATORY COMMISSION Roy P. Zimmerman, Acting Director Office of Nuclear Reactor Regulation

Attachment:

1) Appendix A - Technical Specifications Renewed License No. DPR-55 Date of issuance: May 23, 2000 Renewed License No. DPR-55

TABLE OF CONTENTS 3.4.6 RCS Loops - MODE 4 ............................. 3.4.6-1 3.4.7 RCS Loops - MODE 5, Loops Filled ............................. 3.4.7-1 3.4.8 RCS Loops - MODE 5, Loops Not Filled ............................. 3.4.8-1 3.4.9 Pressurizer ............................. 3.4.9-1 3.4.10 Pressurizer Safety Valves ............................. 3.4.10 -1 3.4.11 RCS Specific Activity ............................. 3.4.11--1 3.4.12 Low Temperature Overpressure Protection (LTOP)

System ................... 3.4.1 2-1 3.4.13 RCS Operational LEAKAGE ................... 3.4.13-1 3.4.14 R Pres e Isolation Va J :e - 1 CS Leakagnstrumentation ...... 3.4.151

/ 35;1; So s verer&t C56) Th~e..ltt,3*6 3.5.1 Core Flood Tanks (CFTs) . ................................... 5.1-1 3.5.2 High Pressure Injection .................................... 3.5.2-1 3.5.3 Low Pressure Injection .................................... 3.5.3-1 3.5.4 Borated Water Storage Tank (BWST) .................................... 3.5.4-1 3.6 CONTAINMENT SYSTEMS .................................... 3.6.1-1 3.6.1 Containment .................................... 3.6.1-1 3.6.2 Containment Air Locks .................................... 3.6.2-1 3.6.3 Containment Isolation Valves .................................... 3.6.3-1 3.6.4 Containment Pressure .................................... 3.6.4-1 3.6.5 Reactor Building Spray and Cooling System .................................... 3.6.5-1 3.7 PLANT SYSTEMS .................................... 3.7.1-1 3.7.1 Main Steam Relief Valves (MSRVs) .................................... 3.7.1-1 3.7.2 Turbine Stop Valves (TSVs) .................................... 3.7.2-1 3.7.3 Main Feedwater Control Valves (MFCVs), and Startup Feedwater Control Valves (SFCVs) .................................... 3.7.3-1 3.7.4 Not used ................................. 3.7.4-1 3.7.5 Emergency Feedwater (EFW) System ................................. 3.7.5-1 3.7.6 Upper Surge Tank (UST), and Hotwell (HW) ................................. 3.7.6-1 3.7.7 Low Pressure Service Water (LPSW) System ................................. 3.7.7-1 3.7.8 Emergency Condenser Circulating Water (ECCW) ........................... 3.7.8-1 3.7.9 Control Room Ventilation System (CRVS) Booster Fans ................................. 3.7.9-1 3.7.10 Penetration Room Ventilation System (PRVS) ................................. 3.7.10-1 3.7.11 Spent Fuel Pool Water Level ................................. 3.7.11-1 3.7.12 Spent Fuel Pool Boron Concentration ................................. 3.7.12-1 3.7.13 Fuel Assembly Storage ................................. 3.7.13-1 OCONEE UNITS 1, 2, & 3 iii Amendment Nos. 3 ,3 , &i JI

TABLE OF CONTENTS B 3.4 REACTOR COOLANT SYSTEM (RCS) .B 3.4.1-1 B 3.4.1 RCS Pressure, Temperature, and Flow Departure from Nucleate Boiling (DNB) Limits .B 3.4.1-1 B 3.4.2 RCS Minimum Temperature for Criticality .B 3.4.2-1 B 3.4.3 RCS Pressure and Temperature (P/T) Limits .B 3.4.3-1 B 3.4.4 RCS Loops - MODES 1 and 2 .B 3.4.4-1 B 3.4.5 RCS Loops - MODE 3 ......................... B 3.4.5-1 B 3.4.6 RCS Loops - MODE 4 ......................... B 3.4.6-1 B 3.4.7 RCS Loops - MODE 5, Loops Filled ......................... B 3.4.7-1 B 3.4.8 RCS Loops - MODE 5, Loops Not Filled .B 3.4.8-1 B 3.4.9 Pressurizer .B 3.4.9-1 B 3.4.10 Pressurizer Safety Valves .B 3.4.10-1 B 3.4.11 RCS Specific Activity .B 3.4.11-1 B 3.4.12 Low Temperature Overpressure Protection (LTOP)

System ................... B 3.4.12-1 B 3.4.13 RCS Operational LEAKAGE ................... B 3.4.13-1 B 3.4.14 RCS Pressure Isolation Valve (PIV) Leakage .............................. B 3 1

........... ........... B 3.4.15-1\

B 3.5.1 Core Flood Tanks (CFTs) ....................................... B 3.5.1-1 B 3.5.2 High Pressure Injection (HPI) ....................................... B 3.5.2-1 B 3.5.3 Low Pressure Injection (LPI) ........................................ B 3.5.3-1 B 3.5.4 Borated Water Storage Tank (BWST) ....................................... B 3.5.4-1 B 3.6 CONTAINMENT SYSTEMS ....................................... B 3.6.1-1 B 3.6.1 Containment ....................................... B 3.6.1-1 B 3.6.2 Containment Air Locks ....................................... B 3.6.2-1 B 3.6.3 Containment Isolation Valves ....................................... B 3:6.3-1 B 3.6.4 Containment Pressure .............................................. B 3.6.4-1 B 3.6.5 Reactor Building Spray and Cooling System ................................ B 3.6.5-1 B 3.7 PLANT SYSTEMS ....................................... B 3.7.1-1 B 3.7.1 Main Steam Relief Valves (MSRVs) ....................................... B 3.7.1-1 B 3.7.2 Turbine Stop Valves (TSVs) ....................................... B 3.7.2-1 B 3.7.3 Main Feedwater Control Valves (MFCVs), and Startup Feedwater Control Valves (SFCVs) .................................... B 3.7.3-1 B 3.7.4 Atmospheric Dump Valve (ADV) Flow Paths ............................... B 3.7.4-1 B 3.7.5 Emergency Feedwater (EFW) System................................... B 3.7.5-1 B 3.7.6 Upper Surge Tank (UST) and Hotwell (HW) ................................ B 3.7.6-1 B 3.7.7 Low Pressure Service Water (LPSW) System ............................. B 3.7.7-1 B 3.7.8 Emergency Condenser Circulating Water (ECCW) ..................... B 3.7.8-1

~2, & 3 ~ ~ UNT ,,&3iiAedetNsI~, 3, &._9 OCONEE UNITS 1,OCONEE~~~~ iii Amendment Nos.L30,30 &96 1

Definitions

'I.1 1.1 Definitions (continued)

E - AVERAGE E shall be the average (weighted in proportion DISINTEGRATION ENERGY to 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 > 30 minutes, making up at least 95% of the total noniodine activity in th e coolant.

LEAKAGE LEAKAGE shall be:

a. Identified LEAKAGE

1. LEAKAGE, such as that from pump seals or valve packing (except 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 (RC LEAKAGE through a steam generator to the Secondary System;

b. Unidentified LEAKAGE L 19 All LEAKAGE (except RCP seal water injection or leakoff) that is not identified LEAKAGE.

c. Pressure Boundary LEAKAGE p ='p7 se LEAKAGE (excep LEAKAGE) through a nonisolable fault in an RCS component body, pipe wall, or vessel wall.

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

OCONEE: UNITS 1, 2, & 3 1.1-3 Amendment Nos. 0 , ,&3

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

a. No pressure boundary LEAKAGE;

b. 1 gpm unidentified LEAKAGE;

c. 10 gpm identified LEAKAGE; c",J say 150 gallon-per dE J, through any onel APPLICABILITY: MODES 1,2, 3, and 4.

IACTIONS K A.

CONDITION RCS LEAKAGE not within limits for reasons A.1 REQUIRED ACTION Reduce LEAKAGE to within limits.

COMPLETION TIME 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months other than pressure Of bcundary LEAKAGE. L[Z4 6E B. Required Action and B.1 Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-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 _ pro ral *D secrbia#y LEAKAGE exists.

OCONEE UNITS 1,2, &3 3.4.13-1 Amendment Nos. bp6, 3p6, & )@

RCS Operational LEAKAGE 3.4.13 2, ~4/ICO-ble A-~4 i-0 ,O~ tav -kV secewfqr-y LE SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.1.13.1 NOT h----------------I-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.

Evaluate RCS Operational LEAKAGE. 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months l Verify team generat (tube integri is in N In ac rdance w the accor ance with the team GenertorT Ste Generat Tube Su eillance Progr Tube eillance P/ogram 3, /3 A OCONEE UNITS 1, 2, & 3 3.4.1 3-2 Amendment Nos.9 91 ]&,!i)

SG Tube Integrity 3.4.16 3.4 REACTOR COOLANT SYSTEM (RCS) 3.4.16 Steam Generator (SG) Tube Integrity e, (A)

-- 5 3. , I LCO 3.4.16 SG tube integrity shall be maintained.

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

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

ACTIONS

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

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

Program.

AND A.2 Plug the affected tube(s) 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.1 Be in MODE 3. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months associated Completion Time of Condition A not AND met.

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

OCONEE Units 1, 2, & 3 3.4.1 6-1 Amendments Nos.

SG Tube Integrity 3.4.16 AeW T5 3/

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.16.1 Verify SG tube integrity in accordance with the In accordance Steam Generator Program. with the Steam Generator Program SR 3.4.16.2 Verify that each inspected SG tube that satisfies the Prior to entering tube repair criteria is plugged in accordance with the MODE 4 following Steam Generator Program. an SG tube inspection OCONEE Units 1, 2, & 3 3.4.16-2 Amendments Nos.

Organization 5.2 5.0 ADMINISTRATIVE CONTROLS 5.2 Orcianization 5.2.1 Onsite and Offsite Organizations Onsite and offsite organizations shall be established for unit operation and corporate management, respectively. The onsite and offsite organizations shall include the positions for activities affecting safety of the nuclear power plant.

a. Lines of authority, responsibility, and communication shall be defined and established throughout highest management levels, intermediate levels, and all operating organization positions. These relationships shall be documented and updated, as appropriate, in organization charts, functional descriptions of departmental responsibilities and relationships, and job descriptions for key personnel positions, or in equivalent forms of documentation. These requirements shall be documented in the UFSAR;

b. The Station Manager shall be responsible for overall safe operation of the plant and shall have control over those onsite activities necessary for safe operation and maintenance of the plant;

c. The Vice-President, Oconee Nuclear Site, shall have corporate responsibility for overall plant nuclear safety and shall take any measures needed to ensure acceptable performance of the staff in operating, maintaining, and providing technical support to the plant to ensure nuclear safety;

d. The Vice President, Nuclear Generation Department, will be the Senior Nuclear Executive and have corporate responsibility for overall nuclear safety; and

e. The individuals who train the operating staff, carry out health physics, or perform quality assurance functions may report to the appropriate onsitE manager; however, these individuals shall have sufficient organizational freedom to ensure their independence from operating pressures.

5.2.2 Station Staff

a. A non-licensed operator shall be onsite for each reactor containing fuel and an additional non-licensed operator shall be onsite for each control room from which a reactor is operating in MODES 1, 2, 3, or 4.

OCONEE UNITS 1, 2, & 3 5.0-2 Amendment Nos.[ K&

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.9 Inservice Testing Program (continued)

ASME Boiler and Pressure Vessel Code and applicable Addenda terminology for Required Frequencies inservice testing for performing inservice activities testing activities Weekly At least once per 7 days

Monthly At least once per 31 days Quarterly or every 3 months At least once per 92 days Semiannually or every 6 months At least once per 184 days Every 9 months At least once per 276 days Yearly or annually At least once per 366 days Biennially or every 2 years At least once per 731 days

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

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

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

5.5.10 Steam Generator (SG)[TZbe,6urvillaa cProqram Amendment Nos. 3j)

OCONEE UNITS 1, 2, &

UNITS 1,2, &33 5.0-133 5.0-1 Amendment Nos.P3(Y 34/, 3E)J

Programs and Manuals 5.5 5.5 P'rograms and Manuals 5.5.10 Steam Generator (SG) ube Surveillance Program (continued)

b. Acceptance Crit ia The steam g nerator shall be considered operable after com tion of the specified a ions. All tubes examined exceeding the pluggi limit shall be removed rom service (e.g., plugged, stabilized).

c. Sele ion and Testing Tie steam generator tube minimum sample sizej spection result classifica-ion, and the corresponding action required sh be as specified in Table 5.5.10-1. The inservice inspection of s am generator tubes shall be performed at the frequencies specified in 5 .1O.d and the inspected tubes shall be verified acceptable per 5.5.1 0.e. he tubes selected for each inservice inspection shall include at le 3% of the total number of tubes in both steam generators, with one or th steam generators being inspected.

The tubes selected for these insp tions shall be selected on a random basis except:

1. The first sample inspecp n during each inservice inspection of each steam generator sha nclude:

a. All tubes that reviously had detectable wall penetrations (>20%) arid have not be nplugged.

b. At leas 0% of the tubes inspected shall be in those areas whe exper 'nce has indicated potential problems.

c. ube adjacent to any selected tube which does not permit passage f the eddy-current probe for tube inspection.

2. he tubes selected as the second and third samples required by Table 5.5.10-1) during each inservice inspection m be subjected to less than a full tube inspection provided:

a. The tubes selected for these samples inc de the tubes from those areas of the tubesheet array where tub with imperfections were previously found.

b. The inspections include those po ions of the tubes where imperfections were previously f und.

I- _____

OCONEE UNITS 1, 2, & 3 5.0-1 4 Amendment Nos.g 3- jI

Programs and Manuals 5.5 IPrograms and Manuals 5.5.10Steam Generator (SG) Tuk/e Surveillanci ro-gram (continued)\

The results of ea sample inspecti shall be classified into one of the following three tegories:

Cat o Inspection Results

-1 Less than 5% of the total tubes inspected are degrad tubes and none of the inspected tubes are defective.

C-2 One or more tubes, but no more than 1% of th tal tubes inspected are defective, or between 5% and 0% of the total tubes inspected are degraded tubes.

C-3 More than 10% of the total tubes insp ted are degraded tubes or more than 1% of the inspe ed tubes are defective.

NOTE: In all inspections, previous degraded tubes must exhibit significant (>10%) furth wall penetrations to be included in the above percentge calculations.

d. Inspection Intervals The above required inse ce inspections of steam generator tubes shal be performed at the folwing frequencies.

1. Inservice inspect s shall be performed at intervals of not less than 12 nor more than calendar months after the previous inspection. If the results of tw consecutive inspections fall into the C-1 category or if two consecu e inspections demonstrate that previously observed degra tion has not continued and no additional degradation has oc rred, the inspection interval may be extended to a maximum of I ~ onths .

2. If the results of the inservice inspection of a steam generat performed in accordance with Table 5.5.10-1 at 40 month intervals in Category C-3, subsequent inservice inspections shall be perfored at intervals of not less than 10 months nor more than one fuel cyp e after the previous inspection. The increase in inspection frequenc hall apply until a subsequent inspection meets the conditions secified in 5.5.10.d.1 and the interval can be extended to a maximu f 40 months.

3. Additional, unscheduled inservice ins ctions shall be performed on eac~h steam generator in accordance withe first sample inspection specified in Table 5.5.10-1 during the sh own subsequent to any of the following conditions:

OCONEE: UNITS 1, 2, & 3 5.0-15 Amendment Nos134,3'p

Programs and Manuals

~5.5 5.5 Pro rams and Manuals ( 5£\

5.5.10 Steam Generat SG Tube Surveillance Program (contin ed)

a. eismic occurrence greater than the Oper ting Basis Earthquake,

b. A loss-of-coolant accident requiring actu on of the engineered safeguards, or

c. A main steam line or feedwater line reak.

4. After primary to secondary leakage excess of the limits of Specification 3.4.13, an inspection of the affect steam generator will be performed in accordance with Table 5.5.10-1 ith an initial inspection sample size of 6% of the tubes in the affected team generator.

e. Definitions As used in this specificatio

1. Imperfection means n exception to the dimensions, finish or contour o/f tube from that req red by fabrication drawings or specifications. Edd current testing in ications below 20% of the nominal tube wall thickn ss, if detectable, y be considered as imperfections.

2. De radatio means a service-induced cracking, wastage, wear r general c rosion occurring on either the inside or outside of tube.

3. Der ed Tube means a tube containing imperfections Ž 0% of the no al wall thickness caused by degradation.

4. 0/ De radation means the percentage of the tube wa thickness affected or removed by degradation.

Defect means an imperfection of such severity t it exceeds the plugging limit. A tube containing a defect is dective.

6. Plugging Limit means the imperfection dep beyond which the tube shall be either removed from service by pluggi because it may become unserviceable prior to the next inspecti ; it is equal to 40% of the nominal tube or sleeve wall thickness

7. Unserviceable describes the con on of a tube if it leaks or contains a defect large enough to affect it tructural integrity in the event of an Operating Basis Earthquake,/loss-of-coolant accident, or a steam line or feedwater line break as specified in 5.5.1 0.d.

OCONEE UNITS 1, 2, & 3 5.0-16 Amendment Nos.333,& 3

Programs and Manuals 5.5 5.5 Programs and Manuals nominal tube o sleeve wall thickness.

5.5.10 S team Generator SG) Tub Surveillance Program (cont ued)

8. Tube Inspection eans an inspection of the st am generator tub from point ofTn5thecompletely to the point of e 0/g5E9T g, OCONEE_ UNITS 1, 2, & 3 5.0-1 7 Amendment Nos. ED

Programs and Manuals 5.5 TABLE $.5.10-1 (Page Idi-2~

STEAM GENRATOR TUBE INSPECTION (continued) .

.OCONEE UNITS 1, 2, & 3 5.0-1 8 Amendment Nos 3l

Programs and Manuals 5.5 10-1 6 (Page 2 of 2)

JTOR TUBE INSPECTION Notes: (1) S=3(N/n)% Where N is the number of steam generators in th uit, and n is the number of steam generators inspected during an inspection.

(2) Following an 18% random inspection (C-3 category in tion) an unaffected area is identified. The unaffected area will be logically and consistently defed based on generator design, defect location and characteristics. The criteria for accepting an are s unaffected depends on the number of defects found in the sample inspected in that area and are estaished such that there is a 0.05 or smaller probability of accepting the area as unaffected if it contai30 or more defective tubes. -I OCONEE UNITS 1, 2, & 3 5.0-1 9 Amendment Noso324 33, &3gz-D

Programs and Manuals

.5.5 5.5 Programs and Manuals 5.5.20 Battery Discharge Testing Program (continued)

b. If battery capacity is determined to be < 80% of the manufacturer's rating an OPERABILITY evaluation shall be initiated immediately and completed within the guidelines of the Oconee OPERABILITY program. If the OPERABILITY evaluation determines the battery OPERABLE, battery capacity shall be restored to 2 80% of the manufacturer's rating within a time frame commensurate with the safety significance of the issue.

Otherwise, the battery shall be declared inoperable and the applicable Condition of Specification 3.8.3 shall be entered.

The provisions of SR 3.0.2 and SR 3.0.3 are applicable to the Battery Discharge Testing Program surveillance frequencies.

.21 Steam Generator (SG) Tube Surveillance Program

\----------------------------------------------NOTE -------------------------------- ---/----------

Applicable on each unit until steam generator replacement.

This p ram provides the controls for SG tube surveillan . The program shall include th Ilowing:

a. Examination thods Inservice inspection team generat bing shall include non-destructive examination by eddy-cur t testin r other equivalent techniques. The inspection equipment shall p i a sensitivity that will detect defects with -a penetration of 20 percent or of the minimum allowable as-manufactured tube wall thickness.

b. Acceptance Criteria The steam gen ator shall be considered ope le after completion of the specified actj ns. All tubes examined exceedinge repair limit shall be repaired b/sleeving or rerolling or removed from se ce (e.g., plugged, l ~stabilz I

Fo nits 1 and 3, there are a number of steam generator tu s which xceed the tube repair limit as a result of tube end anomalies. ese tubes are temporarily exempted from the requirements for sleeving, rero or removal from service, until repaired during or before the next Unit 1 a Unit 3 refueling outages (Unit 1 EOC 18, Unit 3 EOC 17 refueling outages, respectively). An analysis has been performed which confirms the operabi OCONEE: UNITS 1, 2, & 3 5.0-26 Amendment Nos.8 3, 4

Programs and Manuals 5.5 5.5 Programs and Manuals v5.21 Steam Generator (SG) Tube Surveillance Program (continued) of Units 1 and 3 will not be impacted with these tubes in service until the ne,/

refueling outage on each of these units.

c. Selection and Testing The steam generator tube minimum sample size, inspection result lassifica-tian, and the corresponding action required shall be as soecifiedi Ta2e 5.5.21-1. The inservice inspection of steam generator t es shall be perfo ed at the frequencies specified in 5.5.21.d and the i pected tubes shall b verified acceptable per 5.5.21 .e. The tubes selec d for each inservice spection shall include at least 3% of the total umber of tubes in both steam enerators, with one or both steam gener rs being inspected.

The tubes se cted for these inspections shall be se cted on a random basis except:

1. The first sampl nspection during each in vice inspection of each steam generator all include:

a. All tubes that pre usly had dettable wall penetrations (>20%) arid have not been plug d or sle repaired in the affected area.

b. At least 50% of the tube spected shall be in those areas where experience has indicat p tential problems.

c. A tube adjacent to ny selecte ube which does not permit passage of the eddy-curr it probe for tube sspection.

2. Tubes in the foil ng Group(s) may be uded from the first sample if all tubes in a oup in both OTSGs are insp ted. No credit will be taken for these tugs in meeting minimum sample si requirements.

Group As: Tubes within one, two, or three rows oce open inspection lane.

3. All ubes which have been repaired using the reroll proces will have the w roll area inspected during the inservice inspection.

4/. The tubes selected as the second and third samples (if require y Table 5.5.21-1) during each inservice inspection may be subjecte to less than a full tube inspection provided:

OCONEE UNITS 1, 2, & 3 5.0-27 Amendment Nos.\334,Z3]!)

Programs and Manuals 5.5 5.5 Programs and Manuals

/.5.21 Steam Generator (SG) Tube Surveillance Program (continued)

a. The tubes selected for these samples include the tubes from tho areas of the tubesheet array where tubes with imperfections we previously found.

b. The inspections include those portions of the tubes where imperfections were previously found.

e results of each sample inspection shall be classified into ne of the fol ing three categories:

te 0 Inspection Results C-1 Less than 5% of the total tubes inspe ted are degraded tubes nd none of the inspected tubes ar defective.

C-2 On or more tubes, but no mor han 1% of the total tubes inspeced are defective, or be een 5% and 10% of the total tubes in ected are degrad tubes.

C-3 More than 1e% of the to I tubes inspected are degraded tubes or more an 1 of the inspected tubes are defective.

NOTES:

(1) In all insp ions, eviously degraded tubes must exhibit signific t (>10%) f her wall penetrations to be included in the bove percenta calculations.

(2) ere special inspections re performed pursuant to

.5.21 .c.2, defective or degr ed tubes found as a result of the inspection shall be inclu d in determining the Inspection Results Category for t t special inspection but need not be included in determinin the Inspection Results Category for the general steam gene tor inspection, unless the mechanism of degradation i random in nature.

(3) Where special inspections are performed p rsuant to 5.5.21.c.2, defective or degraded tube indica~ ns found in the new roll area as a result of the inspection a d any indications found in the originally rolled region of e rerolled tube, need not be included in determining e Inspection Results Category for the general steam generator inspection.

OCONEE UNITS 1, 2, & 3 5.0-28 Amendment Nost334,3:-:

Programs and Manuals 5.5 5.5 Programs and Manuals

.5.21 Steam Generator (SG) Tube Surveillance Proqram (continued)

d. Inspection Intervals The above required inservice inspections of steam generator tube hall be performed at the following frequencies.

1. Inservice inspections shall be performed at intervals of n less than 12 nor more than 24 calendar months after the previous insection. If the results of two consecutive inspections following servic under all volatile treatment (AVT) conditions fall into the C-1 catego r if two consecutive inspections demonstrate that previously observed egradation has not continued and no additional degradation has oc rred, the inspection terval may be extended to a maximum of 40,onths.

2. If th esults of the inservice inspection of steam generator performed in acc ance with Table 5.5.21-1 at 40 onth intervals fall in Category C-3, sub quent inservice inspection shall be performed at intervals of not less th 10 months nor more t n one fuel cycle after the previous inspection. e increase in insp tion frequency shall apply until a subsequent ins ection meets t conditions specified in 5.5.21.d.1 and the interval can b extended a maximum of 40 months.

3. Additional, unschedu iervice inspections shall be performed on each steam generator in ac dance with the first sample inspection specified in Table 5.5.21-1 duri g shutdown subsequent to any of the following conditions:

a. A seismicurrence greater an the Operating Basis Earthquake..

b. A los of-coolant accident requirin actuation of the engineered sa guards, or C.A main steam line or feedwater line brea 4 After primary to secondary leakage in excess of th limits of Specification 3.4.13, an inspection of the affected steam generato ill be performed in accordance with the following criteria:

a. If the leaking tube is in a Group as defined in Section 5.5 .c.2, all of the tubes in this Group in this steam generator will be inspe d. If the results of this inspection fall into the C-3 category, addition inspections will be performed in the same Group in the other ste U2dgenerator.

OCONEI_ UNITS 1, 2, & 3 5.0-29 Amendment Nos4t3<34,38: 3;

Programs and Manuals 5.5 5.5 Programs and Manuals

&5.5.21 Steam Generator (SG) Tube Surveillance Program (continued)

b. If the leaking tube has been repaired by the reroll process d is leaking in the new roll area, all tubes in the steam gener r that have been repaired by.the reroll process will have the new r area inspected. If the results of this inspection fall into th -3 category, additional inspections will be performed in the new IIarea in the other steam generator.

c. If the leaking tube is not in a Group as define in 5.5.21.d.4.a, then an inspection will be performed on the affe ed steam generator in ccordance with Table 5.5.21-1 with an in' ial inspection sample size o 6% of the tubes in the affected steam enerator.

e. Definitions As used in this s cification:

1. Imperfection meais an exceptio o the dimensions, finish or contour of a tube from that requ ed by fabri tion drawings or specifications. Eddy-current testing indica ns bel 20% of the nominal tube or sleeve wall thickness, if detectable abe considered as imperfections.

2. Degradation means a s -induced cracking, wastage, wear or general corrosion occ ring oeither the inside or outside of a tube or a sleeve.

3. Degraded Tube eans a tube or a leeve containing imperfections

> 20% of the n minal wall thickness used by degradation.

4. % Dearada 'on means the percentage of e tube or sleeve wall thickness ffected or removed by degradati n.

5. Defect eans an imperfection of such severity at it exceeds the repair limit. tube or sleeve containing a defect is defe ive.

6. R air Limit means the imperfection depth beyond wh'h the tube shall either removed from service by plugging or repaired sleeving or rerolling because it may become unserviceable prior to the xt inspection; it is equal to 40% of the nominal tube or sleeve wa thickness.

Axial tube imperfections of any depth observed between the prii ry side surface of the tube sheet clad and the end of the tube are exclude from this repair limit.

OCONEE UNITS 1, 2, & 3 5.0-30 Amendment Nos.P334

Programs and Manuals 5.5 5.5 IPrograms and Manuals

.21 Steam Generator (SG) Tube Surveillance Program (continued)

The Babcock and Wilcox process (or method) equivalent to t method described in report, BAW-1 823P, Revision 1 will be used sleeving is./

The new r a must be free of degradation oder for the repair to be considered accep . The rerolling proc used by Oconee is described in the Topic port, B 3P, Revision 4.

7. Unserviceable describes the of a tube if it leaks or contains a defect large enough to af its structu integrity in the event of an Operating Basis Eartake, a loss-of-cool accident, or a steam line or feedwater line ak as specified in 5.5.21.d.

8. Tube Ins tion means an inspection of the steam ge tor tube from the p t of entry completely to the point of exit. The degra tube

y~e the new roll area can be excluded from future periodic ins ction requirements because it is no longer part of the pressure boundary e the repair roll is installed.

OCONEE UNITS 1, 2, & 3 5.0-31 Amendment Nos. 334, 334, & 3:35 l

Programs and Manuals 5.5

&3 5.0-32 Amendment Nos.

UNITS 1,2, OCONEE UNITS 1,2, &3 5.0-32 Amendment Nos. t2,3~483~3 1)

Programs and Manuals 5.5 II TABLE 5.5.21-1 (Page 1 of 2)

STEAM GENERATOR TUBE INSPECTION 1st Sample Inspection 2nd Sample Inspection I 3rd Sample Ins 7 Kan II Sample Size Result Action Result Action Result Action

\ Required Required Required (continued) 0-3 Inspect 6Sc-i N/A N/A tubes in the S.G, plug or repair Defective tubes and nspect 2S es in the /

oth S.G. C-2N/A N/A Perform H0ow-oninspecbn/

l ~in the otheK l ~S.G. in /

accordance with results of the above \_

inspection as - (a)If defects C-1 N/A applied to can be Table 5.5.21-1 localized to an affected area, Prompt inspect all C-2 N/A Notification to tubes in NRC pursuant f ected area to 10 CFR asplug or 50.72 repai fective C-3 N/A

/ ~(b) If defe~

cannot be localized to an affected area,

/ ~inspect all \

tubes in this S.G. and plug or repair defective tubes.

Notes: (1) S-3(N )% Where N is the number of steam generators inthe unit, and n is the numberf steam gene tors inspected during an inspection.

(2) F owing an 18% random inspection (C-3 category inspection) an unaffected area is identifi The affected area will be logically and consistently defined based on generator design, defect locaI n and characteristics. The criteria for accepting an area as unaffected depends on the number of defect found in the sample inspected in that area and are established such that there isa 0.05 or smaller probability accepting the area as unaffected if it contains 30 or more defective tubes.

.1 OCONEE UNITS 1, 2, & 3 5.0-33 Amendment Nos.13,34, 3'3g,& 3z

Reporting Requirements

.5.6 5.6 Reporting Requirements (continued) 5.6.8 Steam Generator Tube Inspection Report The steam generator tube in ection report shall comply with the flowing:

a. The number of tub s plugged or repaired in each steam enerator shall be reported to the C within 30 days following the com etion of the plugging or rair procedure.

b. The res s of the steam generator tube inservi inspection shall be report to the NRC within 3 months followin completion of the ins ction. This report shall include:

Number and extent of tubes ins cted.

2. Location and percent of wa ckness penetration for each indication of a degraded be.

3. Identification of tub ugged or repaired.

4. Number of tube epaired by rerolling and number of indic ifons detected in tInew roll area of the repaired tubes.

c. Results of stea generator tube inspections which fall into ategory C-3 and require tification to the NRC shall be reported pri to resumption of plant operion. The written report shall provide the re Its of investiga-tions conucted to determine cause of the tube degr ation and corrective measles taken to prevent recurrence.

d. Th designation of affected and unaffected are will be reported to the N 4C when they are determined.

OCONEE: UNITS 1, 2, & 3 5.0-38 Amendment Nos.

Attachment 2b McGuire Nuclear Station Units 1 and 2 Proposed Technical Specifications Changes (Mark-up)

MCGUIRE INSERTS MCGUIRE INSERT 3.4.13 A

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

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

MCGUIIRE INSERT B 3.4.13 B P'rimarv to Secondary LEAKAGE Through Any One SG

-rhe limit of 135 gallons per day per SG is based on the LEAKAGE rate assumptions in the accident analyses (Ref. 9). This limit is more conservative than the performance criterion in NEI 97-06, Steam Generator Program Guidelines (Ref. 7) which is based on operating experience with SG tube degradation mechanisms that result in tube leakage.

The 135 gallons per day limit in conjunction with the implementation of the Steam Generator Program is an effective measure for minimizing the frequency of steam Generator tube ruptures.

MCGUIRE INSERT B 3.4.13 C Note 2 states that this SR is not applicable to primary to secondaryLEAKAGE because LEAKAGE of 135 gallons per day cannot be measured accurately by an RCS water inventory balance.

Page 1

MCGUIRE INSERTS MCGUIRE INSERT B 3.4.13 D (WOG)

This SR verifies that primary to secondary LEAKAGE is less than or equal to 135 gallons per day through any one SG or 389 gallons per day total for all SGs. Satisfying the primary to secondary LEAKAGE limit ensures that the assumptions of the safety analyses are met (Ref. 3).

If this SR is not met, compliance with this LCO, as well as LCO 3.4.18, "Steam Generator Tube Integrity," should be evaluated. The 135 and 389 gallons per day limits are measured at a temperature of 585 OF as described in Ref. 3. The operational LEAKAGE rate limit applies to LEAKAGE through any one SG. If it is not practical to assign the LEAKAGE to an individual SG, all the primary to secondary LEAKAGE should be conservatively assumed to be from one SG.

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

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

8).

MCGUIRE INSERT B 3.4.13 E

7. 14EI 97-06, "Steam Generator Program Guidelines."

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

9. UFSAR, Table 15-24.

Page 2

MCGUIRE INSERTS MCGLIIRE 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 provisiDns:

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, aid operational LEAKAGE.

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

2. Accident induced leakage performance criterion: The primary to secondary accident induced leakage rate for any design basis accident, other than a SG tube rupture, shall not exceed the leakage rate assumed in the accident analysis in terms of tot:al leakage rate for all SGs and leakage rate for an individual SG . Leakage is not to exceed 0.27 gpm total, except for specific types of degradation at specific locations as described in paragraph c of the Steam Generator Program.

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

MCGUIRE INSERTS MCGUIRE INSERT 5.5.9 (cont.)

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

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

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

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

e. Provisions for monitoring operational primary to secondary LEAKAGE.

Page 4

MCGUIRE INSERTS INSERT 5.6.8 A report shall be submitted within 180 days after the initial entry into MODE 4 following completion of an inspection performed in accordance with Specification 5.5.9, Steam Generator (SG) Program. The report shall include:

a. Ths scope of inspections performed on each SG,

b. Acive degradation mechanisms found,

c. Nondestructive examination techniques utilized for each degradation mechanism,

d. Lo<ation, 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, and

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

Page 5

TABLE CF CONTENTS (continued) 3.4 REACTOR COOLANT SYSTEM (RCS) (continued) 3.4.6 RCS Loops-MODE 4 . . ............................3.4.6-1 3.4.7 RCS Loops-MODE 5, Loops Filled. .......................................... 3.4.7-1 3.4.8 RCS Loops-MODE 5, Loops Not Filled . ........................................ 3.4.8-1 3.4.9 Pressurizer .......................................... 3.4.9-1 3.4.10 Pressurizer Safety Valves . . ........................... 3.4.10-1 3.4.11 Pressurizer Power Operated Relief Valves (PORVs) ............... 3.4.11-1 3.4.12 Low Temperature Overpressure Protection (LTOP) System .......... 3.4.12-1 3.4.13 RCS Operational LEAKAGE . . .........................3.4.13-1 3.4.14 RCS Pressure Isolation Valve (PIV) Leakage . . .................3.4.14-1 3.4.15 RCS Leakage Detection Instrumentation . . ...................3.4.15-1 3.4.16 RCS Specific Activity ............. .. 3.4.16-1 K .t1g5 Xenon~ Lao fy lS)rae/* 3e#g 3.5.1 . Accumulators ............................... 3.5.1-1 3.5.2 ECCS-Operating ............................... 3.5.2-1 3.5.3 ECCS-Shutdown ............................... 3.5.3-1 3.5.4 Refueling Water Storage Tank (RWST) ............................... 3.5.4-1 3.5.5 Seal Injection Flow ............................... 3.5.5-1 3.6 CONTAINMENT SYSTEMS ............................... 3.6.1-1 3.6.1 Containment ..................... 3.6.1-1 3.6.2 Containment Air Locks ..................... 3.6.2-1 3.6.3 Containment Isolation Valves ..................... 3.6.3-1 3.6.4 Containment Pressure ..................... 3.6.4-1 3.6.5 Containment Air Temperature ....................... 3.6.5-1 3.6.6 Containment Spray System ..................... 3.6.6-1 3.6.7 Not Used ..................................................... l 3.6.8 Hydrogen Skimmer System (HSS) ................................................. 3.6.8-1 3.6.9 Hydrogen Mitigation System (HMS) ............................................... 3.6.9-1 3.6.10 Annulus Ventilation System (AVS) ................................................. 3.6.10-1 3.6.11 Air Return System (ARS) ................................................... 3.6.11-1 3.6.12 Ice Bed ................................................... 3.6.12-1 3.6.13 Ice Condenser Doors ................................................... 3.6.13-1 3.6.14 Divider Barrier Integrity .................................................... 3.6.14-1 3.6.15 Containment Recirculation Drains .................................................. 3.6.15-1 3.6.16 Reactor Building .................................................... 3.6.16-1 3.7 PLANT SYSTEMS ................................................... 3.7.1-1 3.7.1 Main Steam Safety Valves (MSSVs) .............................................. 3.7.1-1 3.7.2 Main Steam Isolation Valves (MSIVs) ............................................ 3.7.2-1 3.7.3 Main Feedwater Isolation Valves (MFIVs),

Main Feedwater Control Valves (MFCVs), MFCV's Bypass Valves and Main Feedwater (MFW) to Auxiliary Feedwater (AFW) Nozzle Bypass Valves (MFW/AFW NBVs) ... 3.7.3-1 3.7.4 Steam Generator Power Operated Relief Valves (SG PORVs) ... 3.7.4-1 McGuire Units 1 and 2 ii Amendment Nos .

TABLE OF CONTENTS B 3.4 REACTOR COOLANT SYSTEM (RCS) (continued)

B 3.4.14 RCS Pressure Isolation Valve (PIV) Leakage ................................ B 3.4.14-1 B 3.4.15 RCS Leakage Detection Instrumentation ................................ B 3.4.15-1 B 3.4.16 RCS Specific Activity ................................ B 3.4.16-1 i El RLi

Eei~i B 3.5 B 3.5.1 Accumulators .B 3.5.1-1 B 3.5.2 ECCS-Operating .B 3.5.2-1 B 3.5.3 ECCS-Shutdown .B 3.5.3-1 B 3.5.4 Refueling Water Storage Tank (RWST) .B 3.5.4-1 B 3.5.5 Seal Injection Flow .B 3.5.5-1 B 3.6 CONTAINMENT SYSTEMS B 3.6.1 Containment .......................... B 3.6.1-1 B 3.6.2 Containment Air Locks .......................... B 3.6.2-1 B 3.6.3 Containment Isolation Valves .......................... B 3.6.3-1 B 3.6.4 Containment Pressure ......................... . B 3.6.4-1 B 3.6.5 Containment Air Temperature ......................... B 3.6.5-1 B 3.6.6 Containment Spray System ......................... B 3.6.6-1 B 3.6.7 Hydrogen Recombiners ......................... B 3.6.7-1 B 3.6.8 Hydrogen Skimmer System (HSS) ......................... B 3.6.8-1 B 3.6.9 Hydrogen Mitigation System (HMS) ......................... B 3.6.9-1 B 3.6.10 Annulus Ventilation System (AVS) ........ ................. B 3.6.10-1 B 3.6.11 Air Return System (ARS) ......................... B 3.6.11-1 B 3.6.12 Ice Bed ......................... B 3.6.12-1 B 3.6.13 Ice Condenser Doors ......................... B 3.6.13-1 B 3.6.14 Divider Barrier Integrity ......................... B 3.6.14-1 B 3.6.15 Containment Recirculation Drains ......................... B 3.6.15-1 B 3.6.16 Reactor Building ......................... B 3.6.16-1 B 3.7 PLANT SYSTEMS B 3.7.1 Main Steam Safety Valves (MSSVs) .......................... B 3.7.1-1 B 3.7.2 Main Steam Isolation Valves (MSIVs) .......... ................ B 3.7.2-1 B 3.7.3 Main Feedwater Isolation Valves (MFIVs), Main Feedwater Control Valves (MFCVs), MFCV's Bypass Valves and Main Feedwater (MFW) to Auxiliary Feedwater (AFW)

Nozzle Bypass Valves (MFW/AFW NBVs) .............................. B 3.7.3-1 B 3.7.4 Steam Generator Power Operated Relief Valves (SG PORVs) ....... B 3.7.4-1 B 3.7.5 Auxiliary Feedwater (AFW) System ............................................... B 3.7.5-1 B 3.7.6 Component Cooling Water (CCW) System ..................................... B 3.7.6-1 B 3.7.7 Nuclear Service Water System (NSWS) ......................................... B 3.7.7-1 B 3.7.8 Standby Nuclear Service Water Pond (SNSWP) ............................ B 3.7.8-1 B 3.7.9 Control Room Area Ventilation System (CRAVS) ........................... B 3.7.9-1 B 3.7.10 Control Room Area Chilled Water System (CRACWS) .................... B 3.7.10-1 B 3.7.11 Auxiliary Building Filtered Ventilation Exhaust System (ABFVES)... B 3.7.11-1 McGuire Units 1 and 2 ii Revision No./

Definitions 1.1 1.1 Delinitions (continued)

ENGINEERED SAFETY The ESF RESPONSE TIME shall be that time interval from FEATURE (ESF) RESPONSE when the monitored parameter exceeds its ESF actuation TIME 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

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

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

(continued)

McGuire Units 1 and 2 1.1 -3 Amendment Nos.[2p61 )

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

a. No pressure boundary LEAKAGE;

b. 1 gpm unidentified LEAKAGE;

c. 10 gpm identified LEAKAGE;

d. 389 gallons per day total primary to secondary LEAKAGE through all steam generators (SGs); and

e. 135 allons per day primary to secondary LEAKAGE through any one APPLIC:ABILIT Y: _ MODES 1, 2, 3, and 4.

ACTIONS 'e&

CONDITION REQUIRED ACTION COMPLETION TIME

'1%

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

other than pressure boundary LEAKAGE. or preach +

5eC<JcXrsy LEAKAlt E 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 rriet.

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

Pry +0 ecemllry

G#4E Aot wi,+4t1;S't McGuir( eUnits 1 and 2 3.4.13-1 Amendment Nos. EiD

RCS Operational LEAKAGE 3.4.13 SURVEILLANCE REQUIREMENTS SURVEILLANCE oFREQUENCY SR 3.4.13.1 -NO------------- ---- NOTE -------

Not required to be performed7MjDEo until Only required to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months of steady state operation. be performed

-------------- ---- -- -- ----- during steady state operation t ec~ozear'- LA2dJt1G - _- -- - - - - - - -

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

SR 3.4.13.2 VIr{ ,' v , _f cc.iA _

ILE54,C)6e 15 /_ I3qlo5- p t~r( Et de- 1tAo-0t;Il et t iy D?4c 56 or 5 4lr1°S per t-tfd.bkal .tI McGuire Units 1 and 2 3.4.13-2 Amendment Nos. F14/6)

SG Tube Integity 3.4.18 3.4 REACTOR COOLANT SYSTEM (RCS) 3.4.18 Steam Generator (SG) Tube Integrity Nej T5 3,~I

~-/

LCO 3.4.18 SG tube integrity shall be maintained.

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

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

ACTIONS

- ------NOT t--_---- --- ---- --- ---- ---- --- ---- ---

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

Program.

AND A.2 Plug the affected tube(s) 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.1 Be in MODE 3. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months associated Completion Timo of Condition A not AND met.

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

McGuire Units 1 and 2 3.4.1 8-1 Amendment Nos.

SG Tube Integrity 3.4.18 SURVEILLANCE REQUIREMENTS (Ner VS 3Lf.(8, SURVEILLANCE FREQUENCY SR 3.4.18.1 Verify SG tube integrity in accordance with the In accordance Steam Generator Program. with the Steam Generator Program SR 3.4.18.2 Verify that each inspected SG tube that satisfies the Prior to entering tube repair criteria is plugged in accordance with the MODE 4 following Steam Generator Program. a SG tube inspection McGuire Units 1 and 2 3.4.18-2 Amendment Nos.

Organization 5.2 5.0 ADMINISTRATIVE CONTROLS 5.2 Crgnzation 5.2.1 Onsite and Offsite Organizations Onsite and offsite organizations shall be established for unit operation and corporate management, respectively. The onsite and offsite organizations shall include the positions for activities affecting safety of the nuclear power plant.

a. Lines of authority, responsibility, and communication shall be defined and established throughout highest management levels, intermediate levels, and all operating organization positions. These relationships shall be documented and updated, as appropriate, in organization charts, functional descriptions of departmental responsibilities and relationships, and job descriptions for key personnel positions, or in equivalent forms of documentation. These requirements shall be documented in the UFSAR; b.. The Station Manager shall be responsible for overall safe operation of the plant and shall have control over those onsite activities necessary for safe operation and maintenance of the plant;

c. The Vice President of McGuire Nuclear Site shall have corporate responsibility for overall plant nuclear safety and shall take any measures needed to ensure acceptable performance of the staff in operating, maintaining, and providing technical support to the plant to ensure nuclear safety; M&L

d. The Vice President Nuclear Generation Department will be the Senior Nuclear Executive and have corporate responsibility for overall nuclear safety; and

e. The individuals who train the operating staff, carry out radiation protection, or perform quality assurance functions may report to the appropriate onsile manager; however, these individuals shall have sufficient organizational freedom to ensure their independence from operating pressures.

(continued)

McGuire Units 1 and 2 5.2-1 Amendment Nos.

Programs and Manuals 5.5 5.5 Programs and Manuals (continued) 5.5.8 Inservice Testing Proqram This program provides controls for inservice testing of ASME Code Class 1, 2, and 3 components including applicable supports. The program shall include the following:

a. Testing frequencies specified in Section Xl 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 testing inservice testing activities activities Weekly At least once per 7 days Monthly At least once per 31 days Quarterly or every 3 months At least once per 92 days Semiannually or every 6 months At least once per 184 days Every 9 months At least once per 276 days Yearly or annually At least once per 366 days Biennially or every 2 years At least once per 731 days

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

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

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

5.5.9 Steam Generator (SG)FTie 96rvqlaiPro-qram This progr m provides conos for the inservic ins tubes to Insure that the stuctural integrity of t is p4 maintai d. The prograry¶ for inservice inspe ion c basedtn a modificatio of Regulatory Guid 1.83, shall jclude: +

5w - I.S7 (continued)

McGuire Units 1 and 2 5.5-6 Amendment Nos. Rgiiu K

Programs and Manuals.

_ - 5.5 5.5 Programs and Manuals continued) l5.5.9.1 Steam Generato ~ample Selection and Inspeto /vo Each steam grnerator shall be determined OPERABL during shutdown by selecting an inspecting at least the minimum of stea generators specified in Table 5.5 5.5.9.2 Stea Generator Tube Sample Selection and, nsection T steam generator tube minimum samp size, inspection result classification, d the corresponding action required s 1Ibe as specified in Table 5.5-2. The Unservice inspection of steam generato tubes shall be performed at the frequencies specified in Specificatio .5.9.3 and the inspected tubes shall be verified acceptable per the accept ce criteria of Specification 5.5.9.4. The tubes selected for each inservice inspe ion shall include at least 3% of the total number of tubes in all steam ge erators; the tubes selected for these inspections shall be selected on a rando asis except:

a. Where experienc similar plants with similar water chemistry indicates critical areas to e inspected, then at least 50% of the tubes inspected shall be from ese critical areas;

b. The first mple of tubes selected for each inservice inspection (subse ent to the preservice inspection) of each steam generat shall incle:

All nonplugged tubes that previously had detectabl wall penetrations (greater than 20%),

2. Tubes in those areas where experience has i icated potential problems, and

3. A tube inspection (pursuant to Specifica n 5.5.9.4.a.8) shall be performed on each selected tube. If y selected tube does not permit the passage of the eddy curr nt probe for a tube inspection, this shall be recorded nd an adjacent tube shall be selected and subjected to a tu inspection.

c. The tubes selected as the secon nd third samples (if required by Table 5.5-2) during each inserv e inspection may be subjected to a partial tube inspection provid:

1. The tubes select for these samples include the tubes from those areas of e tube sheet array where tubes with imperfections ere previously found, and (continued)

McGuire Units 1 and 2 5.5-7 AmendmentNos.

Programs and Manuals 5.5 Programs and Manuals 5.5.9. Steam Generato/Tube Sam le Selection and Inwi&ction continued

2. he inspections include those po ons of t tubes where imperfections were previously fo nd.

The result of each sample inspection shall classified into one of the following three catories:

Catelnspection Results C-1 Less tha 5% of the total tubes inspected are degrade tubes and none of the inspected tubes are del ctive.

One r more tubes, but not more than 1% of t

/tot tubes inspected are defective, or betwe 5O/.

an 10% of the total tubes inspected are de raded

/~ tes./

C-3 ore than 10% of the total tubes inspect d are degraded tubes or more than 1% of the spected tubes are defective.

Note: In all inspections previously degraded tubes must exhibit si nificant (greater than 1 /o) further wall penetrations to be included/n the above percentage ca ulations.

5.5.9.3 Inspection Freaue cies The above requi d inservice inspections of steam generato tubes shall be performed at th following frequencies:

a. The fist inservice inspection after the steam gen ator replacement shall be p rformed after at least 6 Effective Full Powe Months but within 24 cal ndar months of initial criticality after steam enerator replacement.

S sequent inservice inspections shall be pe rmed at intervals of not I ss than 12 nor more than 24 calendar mon s after the previous nspection. If two consecutive inspections f lowing service under AVT conditions, not including the preservice ins ection, result in all inspection results falling into the C-1 category or if o consecutive inspections demonstrate that previously observed d gradation has not continued and no additional degradation has occurred the inspection interval may be extended to a maximum of once per 4 months;-

(continued)

McGuire Units 1 and 2 5.5-8 Amendment Nos.4

Programs and Manuals 5.5 5.5 Projrams and Manuals 5.5.9.3 Inspection Fre uenci s (continued)

b. If the resul of the inservice inspection of a steam g erator conducted in accorda e with Table 5.5-2 at 40-month intervals fI in Category C-3, the ins ction frequency shall be increased to at I st once per 20 month The increase in inspection frequency s iI apply until the subs quent inspections satisfy the criteria of Spcification 5.5.9.3.a; the int al may then be extended to a maximum once per 40 months; and

c. dditional, unscheduled inservice inspectio s shall be performed on each steam generator in accordance with the fi t sample inspection specified in Table 5.5-2 during the shutdown subs quent to any of the following conditions:

1. Reactor-to-secondary tube eaks (not including leaks originating from tube-to-tube sheet w ds) in excess of the limits of Specification 3.4.13,

2. A seismic occurrenc reater than the Operating Basis Earthquake,

3. A loss-of-coolan ccident requiring actuation of the Engineere Safety Feature, or

4. A main stea line or feedwater line break.

The provisions of SR 3.0 are applicable to the SG Tube Surveillance rogram test frequencies.

5.5.9.4 Acceptance Criteri

a. As used i/this specification:

1. erfection means an exception to the dim sions, finish or contour of a tube from that required by fab ation drawings or specifications. Eddy-current testing indic ions below 20% of the nominal tube wall thickness, if detectabl, may be considered as imperfections; Degradation means a service-induc d cracking, wastage, wear oi

/general corrosion occurring on eit er inside or outside of a tube; (continued)

McGuire Units 1 and 2 5.5-9 Amendment Nosjl176)

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.9.4 Accept nceiei (continued) / ~

3. / Degraded Tube means a tube contain ng imperfectionsgrae than or equal to 20% of the nominal be wall thickness caused by

/ degradation;/

4. % degradation means the perce tage of the tube wall thickness affected or removed by degra tion;

5. Defect means an imperfecti n of such severity that it exceeds the l plugging limit. A tube con ining a defect is defective;

6. Plugging Limit means t e imperfection depth at or beyond which the tube shall be remved from service by plugging. The plugg g limit is equal to 40of the nominal tube wall thickness.

7. Unserviceable scribes the condition of a tube if it leaks o contains a def ct large enough to affect its structural inte ity in the event of n Operating Basis Earthquake, a loss-of-c lant accident, a steam line or feedwater line break as sp died in 5.5.9.3.7 bve;/

8. Tube ns ection means an inspection of the steam enerator tube fro the point of entry completely around the U-b nd to the point

\ ~of/exit; and/

9. reservice Inspection means an inspection the full length of each tube in each steam generator perfor ed by eddy current techniques prior to service to establish a aseline condition of the!

tubing. This inspection shall be perfor d prior to initial POWER OPERATION using the equipment an ttechniques expected to be used during subsequent inservice i pections.

b. The steam generator shall be determine OPERABLE after completing orresponding th actions required by ble 5.5-2.

(continued)

McGuire Units 1 and 2 5.5-10 Amendment Nos. h i6)

Programs and Manuals 5.5 MINIMUM NU BR OF STEAM GENERATOSTBE\

INSPEC1 D URING INSERVICE INSPECIN Preservice Inspection No Yes No. of Steam Gener per Unit Four Four First Inservice In ection after the All Two Steam Genera r Replacement Second & ubsequent Inservice One2 Inspecstio /

Tabl N ition

1. The inservice inspection may be limitedo one steam generator on a rotating sWedule encompassing 3 N % of the tubes (wh e N is the number of steam generato in the unit) if the results of the first or previous inspecti ns indicate that all steam generators re performing in a like mariner. Note that under some circ stances, the operating conditions in ne or more steam generators may be found to be mo severe than those in other steam g erators. Under such circumstances the sample seque e shall be modified to inspect the mst severe conditions.

2. Each of the other two steam g erators not inspected during the firs nservice inspections after the steam generator replace nt shall be inspected during the sec nd and third inspections. The fourth and subsequent inspe ions shall follow the instwuctions de ribed in 1 above.

/AV)5 Uk T 12 P .1 McGuire Units 1 and 2 5.5-1 1 Amendment Nos.q/Z16 )

Programs and Manual; 5.5 TABLE 5.5E2ON JSTEAM GE ERATOR TUBE INSPECTION IF-1ST SAMPLE INSPECTION I/2ND SAMPLE INSPECTION 3RD SA LE INSPECTION Sample Size Result Action / Result Action Required Resu I Action Required

. _ ~Required 7

A minimum C-1 None N/A N/A N/A of S tubes per SG C-2 Pug C-1 None IN/A N/A A efective tubes and inspect additional 2S tubes in this SG C-2 Plug Ofective C-1 None tub and inspec t

/

a ditional 4S Jbes in this SG /

C-2 Plug defective thibe C-3 Perform action r result of first inple 0-3 Perform action for N/A N/A C-3 result of first sample 4 44 - 4- 4 -1 C-3 Inspect all tAII other None N/A N/A tubes in this SGs are C-1 5G. plug

/

defective/

tubes an~y inspectorS tubes*j eac other S

Some SGs Perform action for N/A /A C-2 but no C-2 result of additional second sample SGs are 0-3 Additional Inspect all tubes in/ N/A N/A SG is C-3 each SG and plug defective tubes S /I s l ~S =: 3N/n / Where N is the number of steam generators in t eunit, an(d n is the number of steam generators inspected d i g an inspection./

s:6-j7 McGuire Units 1 and 2 5.5-12 Amendment Nos.6 )

5.6 Reporting Requirements 5.6.8 Steam Generator Tube Inspection Report

a. The numrer of tubes plugged in each s eam generator shall be r ported to the N C within 15 days following c pletion of the program;

b. The c mplete results of the Steam enerator Tube Surveilla e Program shal e reported to the NRC within 12 months following the ompletion of the rogram and shall include:

Number and extent of tu es inspected,

2. Location and percent wall-thickness penetr ion for each indication of an impe ection, and (continued)

McGuire Units 1 and 2 5.6-5 Amendment Nos. E (~

Attachment 3a (FUTURE)

Oconee Nuclear Station Units 1, 2, and 3 Proposed Facility Operating Licenses Pages, Technical Specifications Pages, and Bases Pages

Attachment 3b (FUTURE)

McGuire Nuclear Station Units 1 and 2 Proposed Technical Specifications Pages and Bases Pages

Attachment 4a Oconee Nuclear Station Units 1, 2, and 3 Proposed Technical Specifications Bases Changes (Mark-up)

RCS Loops - MODE 3 B 3.4.5 BASES (continued)

LCO The purpose of this LCO is to require two loops to be available for heat removal thus providing redundancy. The LCO requires the two loops to be OPERABLE with the intent of requiring both SGs to be capable of transferring heat from the reactor coolant at a controlled rate. Forced reactor coolant flow is the required way to transport heat, although natural circulation flow provides adequate removal. A minimum of one running RCP meets the LCO requirement for one loop in operation.

The Note permits a limited period of operation without RCPs. All RCPs may not be in operation for < 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months per 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months period for the transition 1o or from the Decay Heat Removal (DHR) System, and otherwise may be de-energized for *1 hour per 8 hour9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months period. This means that natural circulation has been established. When in natural circulation, boron reduction is prohibited because an even concentration distribution throughout the RCS cannot be ensured. Core outlet temperature is to be maintained at least 10F below the saturation temperature so that no vapor bubble may form and possibly cause a natural circulation flow obstruction.

In MODES 3, 4, and 5, it is sometimes necessary to stop all RCP or LPI pump forced circulation (e.g., change operation from one DHR loop to the other, to perform surveillance or startup testing, to perform the transition to and from DHR mode cooling, or to avoid operation below the RCP minimum net positive suction head limit). This is acceptable because natural circulation is adequate for heat removal, or the reactor coolant temperature can be maintained subcooled and boron stratification affecting reactivity control is not expected.

An OPERABLE RCS loo consists of a least one OPERABLE RCP and an SG that is a I o tra fern dec ea t sec9 darlui. An RCP is OPERABLE i tis capable of being powered and is able to provide forced flow if required.

APPLICA131LITY In MODE 3, the heat load is lower than at power; therefore, one RCS loop in operation is adequate for transport and heat removal. A second RCS loop is required to be OPERABLE but not in operation for redundant heat removal capability.

OCONEE UNITS 1, 2, & 3 B 3.4.5-2 BAS REVISI DAT 03,Z/ l

RCS Loops - MODE: 4 B 3.4.6 BASES LCO so that no vapor bubble may form and possibly cause a natural circulation (continued) flow obstruction.

Note 1 also permits the DHR pumps to be stopped for S 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months per 8 hour9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months period. When the DHR pumps are stopped, no alternate heat removal path exists, unless the RCS and SGs have been placed in service in forced or natural circulation. The response of the RCS without the DHR loop.

depends on the core decay heat load and the length of time that the DHR pumps are stopped. As decay heat diminishes, the effects on RCS temperature and pressure diminish. Without cooling by DHR, higher heal loads will cause the reactor coolant temperature and pressure to increase at a rate proportional to the decay heat load. Because pressure can increase, the applicable system pressure limits (pressure and temperature (P/T) or low temperature overpressure protection (LTOP) limits) must be observed and forced DHR flow or heat removal via the SGs must be re-established prior to reaching the pressure limit. The circumstances for stopping both DHR trains are to be limited to situations where: .

a. Pressure and temperature increases can be maintained well within the allowable pressure (PIT and LTOP) and 10F subcooling limits; or

b. An alternate heat removal path through the SG is in operation.

Note 2 allows a DHR loop to be considered OPERABLE if it is capable of being manually (locally or remotely) realigned to the DHR mode of operation and is not otherwise inoperable. This provision is necessary because of the dual function of the components that comprise the decay heat removal mode of the Low Pressure Injection System.

An OPERABLE RCS loop consists of at least one OPERABLE RCP and an SG that is tpablf o tray(sterrigo de ea hth secondar fluid.

(0:pE::PA re5_:~f Similarly for the DHR loops, an OPERABLE DHR loop is comprised of the OPERABLE LPI pump(s) capable of providing forced flow to the LPI heat exchanger(s). LPI pumps are OPERABLE if they are capable of being powered and are able to provide flow if required.

APPLICASILITY In MODE 4, this LCO ensures forced circulation of the reactor coolant to remove decay heat from the core and to provide proper boron mixing.

OCONEE UNITS 1, 2, & 3 B 3.4.6-2 Amendment Nos.lO,303

RCS Loops - MODE 5, Loops Filled B 3.4.7 BASES LCO Note 2 allows one required DHR loop to be inoperable for a period of (continued) < 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months provided that the other 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 provides for an orderly transition from MODE 5 to MODE 4 during a planned heatup by permitting DHR loops to not be in operation when at least one RCP is in operation. This Note provides for the transition to MODE 4 where an RCP is permitted to be in operation and replaces the RCS circulation function provided by the DHR loops.

Note 4 allows a DHR loop to be considered OPERABLE during alignment and when aligned for low pressure injection if it is capable of being manually (locally or remotely) realigned to the DHR mode of operation and is not otherwise inoperable. This provision is necessary because of the dual requirements of the components that comprise the low pressure injection/decay heat removal system.

To be considered OPERABLE, a DHR loop must consist of a pump, a heat exchanger, valves, piping, instruments, and controls to ensure an OPERABLE flow path and to determine the temperature. The flow path starts in one of the RCS hot legs and is returned to reactor vessel via one or both Core Flood tank injection nozzles. The BWST recirculation crossover line through valves LP-40 and LP-41 may be part of a flow path if it provides adequate decay heat removal capability. The operability of the operating DHR loop and the supporting heat sink is dependent on the ability to maintain the desired RCS temperature. LPSW and ECCW are required to support the OPERABLE DHR train(s). One LPSW pump and one ECCW header can simultaneously support one or two DHR trains.

Single failure protection is not required for LPSW or support systems in these modes.

To be considered OPERABLE, DHR loops must be capable of being powered and are able to provide flow if required. An G can perform as a heat sink when it has an adequate water level and is OPERABLE~ic n wit e St 'Win(nerat Tub urveil nce APPLICABILITY In MODE 5 with loops filled, forced circulation is provided by this LCO to remove decay heat from the core and to provide proper boron mixing. One loop of DHR in operation provides sufficient circulation for these purposes.

Operation in other MODES is covered by:

LCO 3.4.4, ARCS Loops - MODES 1 and 2w; LCO 3.4.5, 'RCS Loops - MODE 3T; OCONEE: UNITS 1, 2, & 3 B 3.4.7-3 (BIS SON 4 TED 1,9/C 7

RCS Operational LEAKA;GE B3.4.13 B 3.4 REACTOR COOLANT SYSTEM (RCS)

B 3.4.13 RCS Operational LEAKAGE BASES BACKGROUND Components that contain or transport the coolant to or from the reactor core make up the RCS. Component joints are made by welding, bolting, rolling, or pressure loading, and valves isolate connecting systems from thE!

RCS.

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

The safety significance of RCS LEAKAGE varies widely depending on its source, rate, and duration. Therefore, detecting and monitorinq reactor coolant LEAKAGE into the containment areagenecessary. Separating the identified LEAKAGE from the unidentified LEAKAGE is necessary to provide quantitative information to the operators, allowing them to take corrective action should a leak occur detrimental to the safety of the facility and the public.

This LCO deals with protection of the reactor coolant pressure boundary (RCPB) from degradation and the core from inadequate cooling, in addition to preventing the accident analysis radiation release assumptions from being exceeded. The consequences of violating this LCO include the possibility of a loss of coolant accident (LOCA). However, the ability to monitor leakage provides advance warning to permit unit shutdown before a LOCA occurs. This advantage has been shown by "leak before break' studies.

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 sucAhan event The steam line break (SLB)a LE50 Osanalysesum al primary to secondary LEAKAGE greater than gallon per day as the initial condition. /50 OCONEE UNITS 1, 2, & 3 B 3.4.13-1 Amendment Nos. L, /30 & 395 /7

RCS Operational LEAKAGE B 3.4.13 BASES APPLICABLE Primary to secondary LEAKAGE is a factor in the dose releases outside SAFETY ANALYSES containment resulting from a SLB accident. To a lesser extent, other (continued) accidents or transients involve secondary steam release to the atmosphere, such as a steam generator tube rupture (SGTR). The leakage contaminates the secondary fluid and can be released to the environment.

within the limits defined in 10 CFR 100.

RCS operational LEAKAGE satisfies Criterion 2 of 10 CFR 50.36 (Ref.3).

LCO

RCS LEAKAGE includes leakage from connected systems up to and including the second normally closed valve for systems which do not penetrate containment and the outermost isolation valve for systems which penetrate containment. Loss of reactor coolant through reactor coolant pump seals and system valves to connecting systems which vent to the gas vent header and from which coolant can be returned to the RCS shall not be considered as RCS LEAKAGE.

RCS operational LEAKAGE shall be limited to:

a. Pressure Boundary LEAKAGE No pressure boundary LEAKAGE is allowed, being indicative of material deterioration. LEAKAGE of this type is unacceptable as the leak itself could cause further deterioration, resulting in higher LEAKAGE. Violation of this LCO could result in continued degradation of the RCPB. LEAKAGE past seals, gaskets, and steam generator tubes 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 LCO could result in continued degradation of the RCPB, if the LEAKAGE is from the pressure boundary.

OCONEE U1NITS 1, 2, & 3 B 3.4.13-2 BASES REVISION DATED

RCS Operational LEAKAGE B 3.4.13 BASES LCO c. Identified LEAKAGE (continued)

Up to 10 gpm of identified LEAKAGE is considered allowable because LEAKAGE is from known sources that do not interfere with detection of unidentified LEAKAGE and is well within the capability' of the RCS makeup system. Identified LEAKAGE includes LEAKAGE to the containment from specifically known and located sources, but does not include pressure boundary LEAKAGE or controlled reactor coolant pump (RCP) seal leakoff (a normal function not considered LEAKAGE). Violation of this LCO could result in continued degradation of a component or system.

d.PiravtoScndarv LIAKAGE throuh AIteam 7 Geerators (SGs) ///

/o al primary to se on ary LEAKAGE >aonting to,30 ga n per

/ day through all Sas produces acceptable offsite doses in ~ L accident analy s. Violation of this 0 could exceed the fisite dose limits fo this accident. Prim to secondary LEA GE must be included n the total allowable mit for identified L GE.

/Nc T e. Primar tSecondary LEAKA throuuh An One S B3.t S 1/The 1 (allon per day limit/ one SG is eaut lto a total of

/ 300 Mlon per day primart secondary LEAKAGE allocated

_Z equ lly between the two Jnerators.f APPLICA131LITY In MODES 1, 2, 3, and 4, the potential for RCPB LEAKAGE is greatest when the RCS is pressurized.

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

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

OCONEE UJNITS 1, 2, & 3 B 3.4.13-3 Amendment N os.

RCS Operational LEAKAGE B 3.4.13 BASES (continued)

ACTION'S A.1 If unidentified LEAKAGE identified LEAKAG E1qf ria) are in excess of the LCO limits, the LEAKAGE must be reduced to within limits within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months . This Completion Time allows time to verify leakage rates and either identify unidentified LEAKAGE or reduce LEAKAGE to within limits before the reactor must be shut down. This action is necessary to prevent further deterioration of the RCPB.

(, or pf2wnxry +o seco#Inry I-E4tAG&)

B.1 and B.2 V1 If any pressure boundary LEAKAGE exists or unidentifiedif identified (jdmcato ec ag)LEAKAGE cannot be reduced to within limits within reactor must be brought to lower pressure conditions to reduce the severity of the LEAKAGE and its potential consequences. The reactor .

must be brought to MODE 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-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 Completion Times allowed are reasonable, based on operating experience, to reach the required conditions from full power conditions in an orderly manner and without challenging unit systems. In MODE 5, the pressure stresses acting on the RCPB are much lower and further deterioration is much less likely.

SURVEILLANCE SR 3.4.13.1 REQUIREMENTS Evaluation of RCS LEAKAGE ensures identified and unidentified leakage is maintained within the associated LCO limits and ensures that the integrity of the RCPB is maintained. Identified and unidentified LEAKAGE is determined by performance of an RCS water inventory balane I~iry tp Ma y XAKAE is ryesurdb effluentt monitgring wih he/ /

l /sc#naylsyse-o risl prirrdry and socondar radio ~OPV/

ofan, lccnrins. etW_e e laaedeeto senst t ensureeaag is within int. iZ7 D The RCS water inventory balance must be performed with the reactor at steady state operatin conditions and near operating pressure. T r -ere BNote M d a w that this SR is not required to be performed until hours after establish osteady state operation. This 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months allowance p s suicient ti collect and process all necessary data after stable plant conditions are established.

OCONEE UNITS 1, 2, & 3 B 3.4.13-4 Amendment Nos*, 3.0,& z0(?

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

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

An early warning of LEAKAGE is provided by the automatic systems that monitor the containment atmosphere radioactivity and the containment sump level.

These leakage detection systems are specified in LCO 3.4.15, 'RCS Leakage Detection Instrumentation.*

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

SR 3.4.13.2

/INS1 This provides e means ne ssary to d ermine S OPERABI in B 3.4.1 an o erational M DE. The re uirement to emonstra SG tube i egrity NBS in corda n Generator rbe Surv c .ihteStear ilance Progrm lphasizes t e importanc of SG tube* tegrity, ev n though thi urveillancecannot be p ormed at rmal oper ng conditio

f REFERENCES 1. UFSAR, Section 3.1.

2. UFSAR, Chapter 15.

3. 10 CFR 50.36.

a OCONEE UNITS 1, 2, & 3 B 3.4.13-5 Amendment NosiWj0oVI

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

B 3.4.16 Steam Generator (SG) Tube Integrity BASES' BACKGROUND Steam generator (SG) tubes are small diameter, thin walled tubes that carry primary coolant through the primary to secondary heat exchangers.

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

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

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

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

Specification 5.5.10, "Steam Generator (SG) Program," requires that El program be established and implemented to ensure that SG tube integrity is maintained. Pursuant to Specification 5.5.10, 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 5.5.10. 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).

Rev.

B 3.4.16-1 OCONEEE UNITS 1,2, OCONE E UNITS &3 1, 2, & 3 B 3.4.1 6-1 Rev.

SG Tube Integrity B 3.4.16 BASES APPLICABLE 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 bounding primary to secondary LEAKAGE rate equal to the operational LEAKAGE rate limits in LCO 3.4.13, "RCS Operational LEAKAGE," plus the leakage rate associated with a double-ended rupture of a single tube. The accident analysis for a SGTR assumes cooldown via the main steam atmospheric dump valves.

The analysis for design basis accidents and transients other than a SG(TR 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 bounds the primary to secondary LEAKAGE of 150 gallons per day per SG. For accidents that do not involve fuel damage, the primary coolant activity level of DOSE EQUIVALENT 1-131 is assumed to be equal to the LCO 3.4.16, "RCS Specific Activity," limits. For accidents that assume fuel damage, the primary coolant activity is a function of the amount of activity released from the damaged fuel. The dose consequences of these events are within the limits of GDC 19 (Ref. 2), 10 CFR 100 (Ref. 3) or the NRC approved licensing basis (e.g., a small fraction of these limits).

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

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

The tube-to-tubesheet weld is not considered part of the tube.

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

The SG performance criteria are defined in Specification 5.5.10, "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.

3..16- e._

3 UITS,2,&

OCONE OCONEE UNITS 1, 2, & 3 B 3.4.1 6-2 Rev.

SG Tube Integrity B 3.4.16 BASES LCO (continued) There are three SG performance criteria: structural integrity, accident induced leakage, and operational LEAKAGE. Failure to meet any one of these criteria is considered failure to meet the LCO.

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

loads in the assessment of the structural integrity performance criterion could cause a lower structural limit or limiting burst/collapse condition to be established." For tube integrity evaluations, except for circumferential degradation, axial thermal loads are classified as secondary loads. For circumferential degradation, the classification of axial thermal loads as primary or secondary loads will be evaluated on a case-by-case basis.

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

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

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

The accident induced leakage performance criterion ensures that the primary to secondary LEAKAGE caused by a design basis accident, other than a SGTR, is within the accident analysis assumptions. The accident analysis assumes that accident induced leakage does not exceed 150 gpd 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.

Rev.

& 3 B 3.4.16-3 UNITS 1,2, OCONEE UNITS OCONEEE 1,2, &3 B 3.4.1 6-3 Rev.

SG Tube Integrity B 3.4.16 BASES LCO (continued) The operational LEAKAGE performance criterion provides an observable indication of SG tube conditions during plant operation. The limit on operational LEAKAGE is contained in LCO 3.4.13, "RCS Operational LEAKAGE," and limits primary to secondary LEAKAGE through any one SG to 150 gallons per day. This limit is based on the assumption that a single crack leaking this amount would not propagate to a SGTR under the stress conditions of a LOCA or a main steam line break. If this amount of LEAKAGE is due to more than one crack, the cracks are very small, and the above assumption is conservative.

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

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

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

A.1 and A.2 Condition A applies if it is discovered that one or more SG tubes examined in an inservice inspection satisfy the tube repair criteria but were not plugged in accordance with the Steam Generator Program as required by SR 3.4.16.2. An evaluation of SG tube integrity of the affected tube(s) must be made. Steam generator tube integrity is based on meeting the SG performance criteria described in the Steam Generator Program. The SG repair criteria define limits on SG tube degradation that allow for flaw growth between inspections while still providing assurance that the SG performance criteria will continue to be met. In order to determine if a SG tube that should have been plugged has tube integrity, an evaluation must be completed that demonstrates that the SG performance criteria will continue to be met until the next refueling outage or SG tube inspection, which ever is shorter. 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.

OCONEE UNITS 1, 2, & 3 B 3.4.16-4 Rev.

SG Tube Integrity B 3.4.16 BASE';

Actions (continued)

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

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

This Completion Time is acceptable since operation until the next inspection is supported by the operational assessment.

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

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

SURVEILLANCE SR 3.4.16.1 REQUI REMENTS During shutdown periods the SGs are inspected as required by this SR and the Steam Generator Program. NEI 97-06, Steam Generator Program Guidelines (Ref. 1), and its referenced EPRI Guidelines, establish the content of the Steam Generator Program. Use of the Steam Generator Program ensures that the inspection is appropriate and consistent with accepted industry practices.

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

OCONEE UNITS 1, 2, & 3 B 3.4.16-5 Rev.

SG Tube Integrity B 3.4.16 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. Inspection scope (i.e., which tubes or areas of tubing within the SG are to be inspected) is a function of existing and potential degradation locations. The Steam Generator Program also specifies the inspection methods to be used to find potential degradation.

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

The Steam Generator Program defines the Frequency of SR 3.4.16.1.

The Frequency is determined by the operational assessment and other limits in the 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 5.5.10 contains prescriptive requirements concerning inspection intervals to provide added assurance that the SG performance criteria will be met between scheduled inspections.

SR 3.4.1 6.2 During a 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 5.5.10 are intended to ensure that tubes accepted for continued service satisfy the SG performance criteria with allowance for error in the flaw size measurement and for future flaw growth. In addition, the tube repair criteria, in conjunction with other elements of the Steam Generator Program, ensure that the SG performance criteria will continue to be met 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.

Rev.

B 3.4.16-6 OCONEEE UNITS OCONEE 1, 2, &

UNITS 1,2, & 33 B 3.4.1 6-6 Rev.

SG Tube Integrity B 3.4.16 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 III, Subsection NB.

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

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

Rev.

UNITS 1,2, &3 B 3.4.16-7 OCONEE UNITS 1,2, &3 B 3.4.1 6-7 Rev.

Attachment 4b McGuire Nuclear Station Units 1 and 2 Proposed Technical Specifications Bases Changes (Mark-up)

RCS Loops - MODES 1 and 2 B 3.4.4 BASES -

APPLICABLE SAFETY ANALYSES (continued) assuming the number of RCS loops in operation is consistent with the Technical Specifications. The majority of the plant safety analyses are based on initial conditions at high core power or zero power. The primary coolant flowrate, and thus the number of RCPs in operation is an important assumption in all accident analyses (Ref. 1).

Steady state DNB analysis has been performed for the four RCS loop operation. For four RCS loop operation, the steady state DNB analysis, which generates the pressure and temperature Safety Limit (SL) (i.e., the departure from nucleate boiling ratio (DNBR) limit) assumes a maximum power level of 118% RTP. This is the design overpower condition for four RCS loop operation. The DNBR limit defines a locus of pressure and temperature points that result in a minimum DNBR greater than or equal to the critical heat flux correlation limit.

The plant is designed to operate with all RCS loops in operation to maintain DNBR above the SL, during all normal operations and anticipated transients. By ensuring heat transfer in the nucleate boiling region, adequate heat transfer is provided between the fuel cladding and the reactor coolant.

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

2).

LCO The purpose of this LCO is to require an adequate forced flow rate for core heat removal. Flow is represented by the number of RCPs in operation for removal of heat by the SGs. To meet safety analysis acceptance criteria for DNB, four pumps are required in MODES 1 and 2..

An OPERABLE RCS loop consists of an OPERABLE RCP in operation providing forced flow for heat transport and an OPERABLE SG a tcor t ce Steam enera ' ube rvirce Ftogr APPLICABILITY In MODES 1 and 2, the reactor is critical and thus has the potential to produce maximum THERMAL POWER. Thus, to ensure that the assumptions of the accident analyses remain valid, all RCS loops are required to be OPERABLE and in operation in these MODES to prevent DNB and core damage.

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

McGuire Units 1 and 2 B 3.4.4-2 Revision No

RCS Loops - MODE 3 B 3.4.5 BASES LCO (continued) characteristics of the RCS are changed. The 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months time period specified is adequate to perform the desired tests, and operating experience has shown that boron stratification is not a problem during this short period with no forced flow.

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

a. No operations are permitted that would dilute the RCS boron concentration with coolant at boron concentration less than required to assure the SDM of LCO 3.1.1 and maintain Keff < 0.99, thereby maintaining an adequate margin to criticality. Boron reduction with coolant at boron concentration less than required to assure SDM and Keff < 0.99 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 10F 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 iillbince Pro ra , which has the minimum water level specified in SR 3.4.5.2. An RCP is OPERABLE if it is capable of being powered and is able to provide forced flow if required.

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

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

Operation in other MODES is covered by:

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

LCO 3.4.6,'RCS Loops-MODE 4";

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

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

LCO 3.4.17, ARCS Loops-Test Exceptions";

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

McGuire Units 1 and 2 B 3.4.5-3 Revision No/

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

Note 1 permits all RCPs or RHR pumps to be de-energized for < 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months per 8 hour9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months period. The purpose of the Note is to permit tests that are designed to validate various accident analyses values. One of the tests performed during the startup testing program is the validation of rod drop times during cold conditions, both with and without flow. The no flow test may be performed in MODE 3, 4, or 5 and requires that the pumps be stopped for a short period of time. The Note permits the de-energizing of the pumps in order to perform this test and validate the assumed analysis values. If changes are made to the RCS that would cause a change to the flow characteristics of the RCS, the input values must be revalidated by conducting the test again. The 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months time period is adequate to perform the test, and operating experience has shown that boron stratification is not a problem during this short period with no forced flow.

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

a. No operations are permitted that would dilute the RCS boron concentration with coolant with boron concentrations less than required to meet SDM of LCO 3.1.1 and maintain Keff < 0.99, therefore maintaining an adequate margin to criticality. Boron reduction with coolant of boron concentrations less than required to assure SDM and maintain Keff < 0.99 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 10F below saturation temperature, so that no vapor bubble may form and possibly cause a natural circulation flow obstruction.

Note 2 requires that the secondary side water temperature of each SG be

< 50 0F above each of the RCS cold leg temperatures or that pressurizer water volume be < 92% (1600 ft3) before the start of an RCP with any RCS cold leg temperature < 300 0F. This restraint is to prevent a low temperature overpressure event due to a thermal transient when an RCP is started.

An OPERABLE RCS loop comprises an OPERABLE RCP and an OPERABLE _SG Vacorancekith 11w6 Stearfh Gerao Vie rva e ro a , which as the minimum water level specified in RR 3.4.6.2. The water level is maintained by an OPERABLE AFW train in accordance with LCO 3.7.5, 'Auxiliary Feedwater System."

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 McGuire Units 1 and 2 B 3.4.6-2 Revision No.

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

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

< 500 F above each of the RCS cold leg temperatures or that pressurizer water volume be < 92% (1600 ft3) before the start of a reactor coolant pump (RCP) with an RCS cold leg temperature

3001F. 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. An OPERABLE SG can perform as a heat sink when it has an adequate water level~find -isO OERABKE n l~ ycrpance pith thy!SteamyGenerolor T96 Su~yeillar)& Prgrf APPLICABILITY In MODE 5 with RCS loops filled, this LCO requires forced circulation of the reactor coolant to remove decay heat from the core and to provide proper boron mixing. One loop of RHR provides sufficient circulation for these purposes. However, one additional RHR loop is required to be OPERABLE, or the secondary side narrow range water level of at least two SGs is required to be 2 12%.

Operation in other MODES is covered by:

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

L00 3.4.5, 'RCS Loops-MODE 3";

LC0 3.4.6, "RCS Loops-MODE 4";

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

LCO 3.4.17 'RCS Loops-Test Exceptions";

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

McGuire Units 1 and 2 B 3.4.7-3 Revision No

RCS Operational LEAKAGE B 3.4.13 BASES LCO (continued)

LEAKAGE. Violation of this LCO could result in continued degradation of the RCPB. Pressure boundary LEAKAGE is nonisolable LEAKAGE from the RCPB through an RCS component body, pipe wall or vessel wall. LEAKAGE past seals and gaskets and SG LEAKAGE are 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 LCO could result in continued degradation of the RCPB, if the LEAKAGE is from the pressure boundary.

c. Identified LEAKAGE Up to 10 gpm of identified LEAKAGE is considered allowable because LEAKAGE is from known sources that do not interfere with detection of unidentified or total LEAKAGE and is well within the capability of the RCS Makeup System. Identified LEAKAGE includes LEAKAGE captured by the pressurizer relief tank and reactor coolant drain tank, as well as quantified LEAKAGE to the containment from specifically known and located sources, but does not include pressure boundary LEAKAGE or controlled reactor coolant pump (RCP) seal leakoff (a normal function not considered LEAKAGE). Violation of this LCO could result in continued degradation of a component or system.

d. Primary to Secondary LEAKAGE through All Steam Generators (SGs)

Total primary to secondary LEAKAGE amounting to 389 gpd through all SGs produces acceptable offsite doses in the accident

'analysis. Violation of this LCO could exceed the offsite dose limits 1A 1S ' for the previously described accidents. Primary to secondary

-LEAKAGE must be included in the total allowable limit for identified 13 ~5LEAKAGE.

< ~~~e.L Prma /oSecondary JCEAKAGEthopn~sS Te 35gallons per flylimit on one UGis based on th assy npion that a shle crack leakir3 this amount woul not propagate to a SGY under the stres conditions of LOAoa m~in steam line rWMture If leaked rough many cr s, the cacks ale very small, a d the above as mption is conse live.

McGuire Units 1 and 2 B 3.4.13-3 Revision No.l

RCS Operational LEAKAGE B 3.4.1 3 BASES APPLICABILITY In MODES 1, 2,3, and 4, the potential for RCPB LEAKAGE is greatest when the RCS is pressurized.

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

LCO 3.4.14, 'RCS Pressure Isolation Valve (PIV) Leakage," measures leakage through each individual PIV and can impact this LCO. Of the two 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 from the RCS, the loss must be included in the allowable unidentified LEAKAGE.

ACTIONS A.1 A nintified LEAKAGEidentified LEAKAGEtqpripary/o gcor) 6 ar) in excess of the LCO limits must be reduced to within limits within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months . This Completion Time allows time to verify leakage rates and either identify unidentified LEAKAGE or reduce LEAKAGE to within limits before the reactor must be shut down. This action is necessary to prevent further deterioration of the RCPB.

I o'r pt,9iav/ to ecc~t iiP4 1a Zfk4GE B.1 and B.2 15 Sd Its Li>

If any pressure boundary LEAKAGE existsor if unidentified LEAKAGEZ identified LEAKAG ma to s con ary GA 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 SR 3.4.13.1 REQUIREMENTS Verifying RCS LEAKAGE to be within the LCO limits ensures the integrity of the RCPB is maintained. Pressure boundary LEAKAGE would at first McGuire Units 1 and 2 B 3.4.13-4 Revision No.

RCS Operational LEAKAGE B 3.4.13 BASES SURVEILLANCE REQUIREMENTS (continued) 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 invento balance. Prim ry to secodr LEAJGE is ,srdby/

2,lsom pebmnceo an RC water invetor baac incrntion wjf ef ent mo ioing w~in the se ~nar se ndfdwter stems.)

TA-e shrVel The RCS water inventory balance must be performed with the reactor a

,y , , stead state operating conditions and near operating pressure.J twth~e. X t is SR is not required to bea nose :it t; k until our of steady state ooeratioUar 6erng pr ssure a eeate =e Steady state operation is required to perform a proper inventory balance; calculations during maneuvering are not useful and a Note requires the Surveillance to be met when steady state is established. For RCS operational LEAKAGE determination by water inventory balance, steady state is defined as stable RCS pressure, temperature, power level, pressurizer and makeup tank levels, makeup and letdown, and RCP seal injection and return flows.

An early warning of pressure boundary LEAKAGE or unidentified LEAKAGE is provided by the 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.

Tese leakage detection systems are specified in LCO 3.4.15, RC 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 IN Ž naccidents. A Note under the Frequency column states that this SR is

~~required to be performed during steady state operation.

SR 3.4.1 3.2 Ts S Ides the eans necess to determi e SG OPERA LITY in an erational M E. The requi ment to de onstrate SG t e 1 3f.15 D integ ty in accorda ce with the St m Generat Tube Surveillnce Pro ram emphasj es the import ce of SG tu e integrity, ev though .

)o(A2c1 /th Surveillanc cannot be pe rmed at nor al operating cDnditions.

McGuire Units 1 and 2 B 3.4.13-5 Revision No. /

RCS Operational LEAKAGE B 3.4.13 BASES REFERENCES 1. 10 CFR 50, Appendix A, GDC 30.

2. Regulatory Guide 1.45, May 1973.

3. UFSAR, Section 15.

4. 10 CFR 50.36, Technical Specifications, (c)(2)(ii).

5. UFSAR, Table 18-1.

6. McGuire License Renewal Commitments MCS-1274.00-00-0016, Section 4.29, RCS Operational Leakage Monitoring Program.

McGuire Units 1 and 2 B 3.4.13-6 Revision No/

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

B 3.4.18 Steam Generator (SG) Tube Integrity BASES BACKGROUND Steam generator (SG) tubes are small diameter, thin walled tubes that carry primary coolant through the primary to secondary heat exchangers.

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

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

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

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

Specification 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).

Revision No.

B 3.4.18-1 and 2 Units 11 and McGuire Units 2 B 3.4.18-1 Revision No.

SG Tube Integrity B 3.4.18 BASE'S APPLICABLE 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 bounding primary to secondary LEAKAGE rate equal to the operational LEAKAGE rate limits in LCO 3.4.13, "RCS Operational LEAKAGE," plus the leakage rate associated with a double-ended rupture of a single tube. The accident analysis for a SGTR assumes main steam isolation valve closure and cooldown via the SG safety valves or blowdown through the SG PORVs.

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 389 gallons per day. For accidents that do not involve fuel damage, the primary coolant activity level of DOSE EQUIVALENT 1-1'31 is assumed to be equal to the LCO 3.4.16, "RCS Specific Activity," limits.

For accidents that assume fuel damage, the primary coolant activity is a function of the amount of activity released from the damaged fuel. The dose consequences of these events are within the limits of GDC 19 (Ref.

2), 10 CFR 100 (Ref. 3) or the NRC approved licensing basis (e.g., a small fraction of these limits).

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

LCO The LCO requires that SG tube integrity be maintained. The LCO also requires that all SG tubes that satisfy the repair criteria be plugged 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 and any repairs made to it, between the tube-to-tubesheet weld at the tube inlet and the tube-to-tubesheet weld at the tube outlet. The tube-to-tubesheet weld is not considered part of the tube.

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.

Revision No.

B 3.4.18-2 and 2 Units 11 and McGuire Units 2 B 3.4.1 8-2 Revision No.

SG Tube Integrity B 3.4.18 BASES LCO (continued) There are three SG performance criteria: structural integrity, accident induced leakage, and operational LEAKAGE. Failure to meet any one! of these criteria is considered failure to meet the LCO.

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

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

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

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

The accident induced leakage performance criterion ensures that the primary to secondary LEAKAGE caused by a design basis accident, other than a SGTR, is within the accident analysis assumptions. The accident analysis assumes that accident induced leakage does not exceed 0.27 gpm total, 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.

Revision No.

B 3.4.18-3 McGuire Units and 2 1 and Units 1 2 B 3.4.1 8-3 Revision No.

SG Tube Integrity B 3.4.18 BASE'S LCO (continued) The operational LEAKAGE performance criterion provides an observable indication of SG tube conditions during plant operation. The limit on operational LEAKAGE is contained in LCO 3.4.13, "RCS Operational LEAKAGE," and limits primary to secondary LEAKAGE through any one SG to 135 gallons per day or 389 gallons per day total. This limit is based on the assumption that a single crack leaking this amount would not propagate to a SGTR under the stress conditions of a LOCA or a main steam line break. If this amount of LEAKAGE is due to more than one crack, the cracks are very small, and the above assumption is conservative.

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

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

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

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

B 3.4.18-4 Revision No.

McGuir Units McGuire and 22 1 and Units 1 B 3.4.18-4 Revision No.

SG Tube Integrity B 3.4.18 BASES Actions (continued)

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

If the evaluation determines that the affected tube(s) have tube integrity, Required Action A.2 allows plant operation to continue until the next refueling outage or SG inspection provided the inspection interval continues to be supported by an operational assessment that reflects *he 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.1 and B.2 If the Required Actions and associated Completion Times of Condition A are not met or if SG tube integrity is not being maintained, the reactor must be brought to MODE 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and MODE 5 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months .

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

SURVEILLANCE SR 3.4.18.1 REQUI REMENTS During shutdown periods the SGs are inspected as required by this SR and the Steam Generator Program. NEI 97-06, Steam Generator Program Guidelines (Ref. 1), and its referenced EPRI Guidelines, establish the content of the Steam Generator Program. Use of the Steam Generator Program ensures that the inspection is appropriate and consistent with accepted industry practices.

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

Revision No.

B 3.4.18-5 McGuire and 2 Units 11 and McGuir Units 2 B 3.4.1 8-5 Revision No.

SG Tube Integrity B 3.4.18 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. Inspection scope (i.e., which tubes or areas of tubing within the SG are to be inspected) is a function of existing and potential degradation locations. The Steam Generator Program also specifies the inspection methods to be used to find potential degradation.

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

The Steam Generator Program defines the Frequency of SR 3.4.18.1.

The Frequency is determined by the operational assessment and other limits in the SG examination guidelines (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.

SR 3.4.1 8.2 During an SG inspection, any inspected tube that satisfies the Steam Generator Program repair criteria is removed from service by plugging.

The tube repair criteria delineated in Specification 5.5.9 are intended to ensure that tubes accepted for continued service satisfy the SG performance criteria with allowance for error in the flaw size measurement and for future flaw growth. In addition, the tube repair criteria, in conjunction with other elements of the Steam Generator Program, ensure that the SG performance criteria will continue to be met 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.

Revision No.

B 3.4.18-6 McGuire Units McGuire and 22 1 and Units 1 B 3.4.1 8-6 Revision No.

SG Tube Integrity B 3.4.18 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 IlIl, Subsection NB.

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

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

B 3.4.18-7 Revision No.

McGuira Units 1 McGuire Units and 2 1 and 2 B 3.4.18-7 Revision No.

v t e Letter Sequence Request
TAC:MD0086, Steam Generator Tube Integrity (Open)
Initiation Request Acceptance... Administration Questions Answers 29 November 2006 Results Approval... Other: ML070930279
MONTHYEAR2006-04-11 [Table View]

ML061080500

Text

SUBJECT:

1.0 INTRODUCTION

2.0 DESCRIPTION

3.0 BACKGROUND

5.0 TECHNICAL ANALYSIS

6.0 REGULATORY ANALYSIS

10.0 REFERENCES

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