Text

Proposed License Amendment Request Consolidated Line Item Improvement Process Technical Specification Improvement Regarding Steam Generator Tube Integrity Response to Request for Additional Information
	ML070190655
Person / Time
Site:	Surry
Issue date:	01/19/2007
From:	Gerald Bichof; Virginia Electric & Power Co (VEPCO)
To:	; Document Control Desk, Office of Nuclear Reactor Regulation
References
	06-1021
	Download: ML070190655 (93)
	v • d • e

January 19, 2007 U. S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, D. C. 20555 VIRGINIA ELECTRIC AND POWER COMPANY SURRY POWER STATION UNITS I AND 2 Serial No.

06-1 02 1 NLOSIGDM RO Docket Nos.

50-280, 281 License Nos. DPR-32, 37 REGARDING STEAM GENERATOR TUBE INTEGRITY RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION In a letter dated May 26, 2006 (Serial No.06-024), Virginia Electric and Power Company (Dominion) requested amendments in the form of changes to the Technical Specifications (TS) to Facility Operating License Numbers DPR-32 and DPR-37 for Surry Power Station Units 1 and 2, respectively. The proposed amendment would revise the TS requirements related to Reactor Coolant System leakage definitions and requirements and steam generator tube integrity consistent with NRC-approved Revision 4 to Technical Specification Task Force (TSTF) Standard Technical Specification Change Traveler, TSTF-449, "Steam Generator Tube Integrity" (TSTF-449, Rev. 4). 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). In a letter dated November 6, 2006, the NRC staff requested additional information to facilitate their review of the proposed license amendment. Dominion's response to the staff's request is included in Attachment 1. As noted in Attachment 1, revisions to the previously submitted license amendment request were required to address the NRC's comments.

Consequently, the previously submitted license amendment request has been revised to resolve the NRC comments.

These changes are indicated by a single revision bar in the right hand margin in, Description and Assessment, and by double revision bars in the right hand margin in Attachment 3, Proposed Technical Specifications Pages (Mark-Up)., Proposed Technical Specifications Pages (Typed), incorporates the indicated revisions.

We have evaluated the changes to the proposed amendment and have determined that the previously provided no significant hazards consideration as defined in 10 CFR 50.92 and the environmental assessment are not affected. Although unchanged, the original evaluations are included in Attachment 2 for completeness. The revised license amendment request has been reviewed and approved by the Station Nuclear Safety and Operating Committee.

Serial No. 06-1021 Docket Nos. 50-2801281 Page 2 of 4 Dominion's previous request for approval of the license amendments by March 31, 2007 with a 180-day implementation period is unchanged.

If you have any questions or require additional information, please contact Mr. Gary D.

Miller at (804) 273-2771.

Sincerely, G..T. Bischof Vice President - Nuclear Engineering Attachments

1. Resolution of NRC Comments on License Amendment Request Dated May 26, 2006 (Serial No.06-024)

2. Description and Assessment

3. Proposed Technical Specifications Pages (Mark-Up)

4. Proposed Technical Specifications Pages (Typed)

Commitments made in this letter: None

Serial No. 06-1021 Docket Nos. 50-2801281 Page 3 of 4 cc:

U.S. Nuclear Regulatory Commission Region II Sam Nunn Atlanta Federal Center 61 Forsyth Street, SW Suite 23T85 Atlanta, Georgia 30303 Mr. N. P. Garrett NRC Senior Resident Inspector Surry Power Station Mr. S. P. Lingam NRC Project Manager U. S. Nuclear Regulatory Commission One White Flint North 1 1555 Rockville Pike Mail Stop 8-HI2 Rockville, MD 20852 Mr. L. N. Olshan NRC Project Manager U. S. Nuclear Regulatory Commission One White Flint North 11 555 Rockville Pike Mail Stop 8-G9A Rockville, Maryland 20852 Commissioner Bureau of Radiological Health 1500 East Main Street Suite 240 Richmond, VA 23218

Serial No. 06-1021 Docket Nos. 50-2801281 Page 4 of 4 COMMONWEALTH OF VIRGINIA

)

1 COUNTY OF HENRICO 1

The foregoing document was acknowledged before me, in and for the County and Commonwealth aforesaid, today by Gerald T. Bischof, who is Vice President - Nuclear Engineering, of Virginia Electric and Power Company. He has affirmed before me that he is duly authorized to execute and file the foregoing document in behalf of that Company, and that the statements in the document are true to the best of his knowledge and belief.

Acknowledged before me this /9'*

day of Q a u u ~ n ~,, 2007.

My Commission Expires:

&.UL.LQE 31. a 0 8.

(SEAL)

Serial No. 06-1021 Docket Nos. 50-280 and 281 ATTACHMENT I Resolution of NRC Comments on License Amendment Request Dated May 26, 2006 (Serial No.06-024)

Virginia Electric and Power Company (Dominion)

Surry Power Station Units I and 2

Serial No. 06-1021 Docket Nos. 50-280 and 281 Resolution of NRC Comments on License Amendment Request Dated May 26,2006 (Serial No.06-024)

Surw Power Station Units I And 2 Virginia Electric and Power Company (Dominion) submitted a License Amendment Request (LAR) to the NRC in a letter dated May 26, 2006 (Serial No.06-024). The proposed amendment would revise the Technical Specifications (TS) requirements related to Reactor Coolant System leakage definitions and requirements and steam generator tube integrity. The change is consistent with NRC-approved Revision 4 to Technical Specification Task Force (TSTF) Standard Technical Specification Change Traveler, TSTF-449, "Steam Generator Tube Integrity" (TSTF-449, Rev. 4). In a letter dated November 6, 2006, the NRC requested additional information to support their review of the LAR. Dominion's response to the NRC request for additional information is provided below.

Please discuss your plans to make the language in proposed Technical Specification (TS) Sections 3.1.C.2.b and 3. I.H.3 consistent with the language used in the associated bases sections.

Response - The TS Bases sections associated with proposed TS 3.1.C.2.b and 3.1.H.3 have been revised to be consistent with the language used in their associated TS. Specifically, the term "...COLD SHUTDOWN within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months ." has been changed to "...COLD SHUTDOWN within the following 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months ."

In proposed Bases Sections 3.1. C. 2. b and 3.1. C. 3, and Sun/eillance Requirement (SR) 4.13.A, the term "unit" is used, however, in proposed Bases Section 3.1. H.3 the term 'plant" is used. Please discuss your plans to modify the bases and SRs to be consistent by using either "unit" or 'plant. "

Response - The phrase "plant conditions" has been changed to "unit conditions" in TS Bases Section 3.1.H.3, and the term "plant operation" was changed to "unit operation" in TS Bases Section 3.1.H.2.a and b for TS consistency. In addition, the term "plant life" was changed to "unit life" in the BACKGROUND section of the TS 3.1.C Bases.

You made several changes to Bases Sections 3.1.C and 4.13 that go beyond TSTF-449. Please confirm that all of the proposed changes are consistent with your current Nuclear Regulatory Commission (NRC) approved design and licensing basis. If they are not consistent, please provide the technical justification or discuss your plans to remove them. In addition, discuss why the statement concerning General Design Criterion 30 and Regulatory Guide 1.45 was not included in the proposed bases for TS Section 3.1. C.

Response - The portions of the TS Bases Sections 3.1.C and 4.13 wording that are different than TSTF-449 reflect the current Surry design and licensing bases, which are based on the full implementation of the alternative source term (AST) for Surry Page 1 of 6

Serial No. 06-1021 Docket Nos. 50-280 and 281 Power Station Units 1 and 2. Dominion implemented the AST as the design basis for Surry by License Amendments 2301230, respectively, issued by the NRC on March 8, 2002. The approval was based on reanalysis of the Loss of Coolant Accident and the Fuel Handling Accident. Subsequently, the Locked Rotor, Main Steam Line Break, and Steam Generator Tube Rupture accidents were also reanalyzed with the AST methodology as a follow on to the previously approved AST analyses in accordance with 10 CFR 50.59. The safety analysis for design basis accidents is also discussed in Chapter 14 of the Surry Updated Final Safety Analysis Report (UFSAR). The Surry TS Bases revisions are consistent with the UFSAR discussion. The wording used in the Surry TS Bases sections is also similar to that used in Dominion's North Anna license amendment request, which implemented TSTF-449, Rev. 4, as North Anna has also implemented the AST. The North Anna license amendment request was approved by the NRC in Amendments 2481228 for Units 1 and 2 dated October 16, 2006.

In addition, the statement in TSTF-449 concerning General Design Criterion (GDC) 30 and Regulatory Guide (RG) 1.45 was not included in the proposed Bases for TS Section 3.1.C because Surry Units I and 2 were licensed prior to the issue of these documents and is therefore not committed to them. During the initial plant licensing of Surry Units 1 and 2, it was demonstrated that the design of the reactor coolant pressure boundary met the regulatory requirements in place at that time.

The GDC included in Appendix A to 10 CFR Part 50 did not become effective until May 21, 1971. However, the Construction Permits for Surry Units 1 and 2 were issued prior to May 21, 1971; consequently, these units were not subject to GDC requirements. (Reference SECY-92-223 dated September 18, 1992.) Nevertheless, Surry meets the GDC 30 requirements. In addition, Surry received its operating license in 1972, prior to the issue of RG 1.45 in May 1973, and consequently did not commit to the RG requirements. As a result, it was determined that it would be inappropriate to include the statement concerning GDC 30 and RG 1.45 in the proposed TS 3.1.C Bases.

4. In several TSs (e.g., TS Section 3. I.C, Applicability Section of TS Bases Sections

3. I. C, 3.1. H, 3.1. H.2. b, Bases Sections 3.1. H. 2.a and b, 4.19. B), terminology such as "whenever REACTOR OPERA TlON exceeds COLD SHUTDOWN conditions" is used. This terminology is not clear since both refueling shutdown and intermediate shutdown conditions "exceed" cold shutdown conditions (depending on your perspective). Please discuss your plans to more clearly specify the requirement.

For example, in proposed TS Section 3.1. C: "The following specifications are applicable to RCS [reactor coolant system] operational LEAKAGE during the following REACTOR OPERA TlON conditions: INTERMEDIATE SHUTDOWN, HOT SHUTDOWN, REACTOR CRITICAL, and POWER OPERA TION. " Another example would be: "The following specifications are applicable to RCS operational LEAKAGE whenever Tavg (average temperature) exceeds 200°F (200 degrees Fahrenheit)."

In proposed TS Section 3.1. H.2.b, it may be acceptable to replace "exceeding" with "exiting" consistent with the wording in proposed TS Section 6.6.A.3.

Page 2 of 6

Serial No. 06-1021 Docket Nos. 50-280 and 281 Response - The following changes have been made to the proposed TS sections to include less confusing REACTOR OPERATION condition terminology to resolve the NRC1s noted concern:

TS 3.1.C Applicabilitv The phrase

"... RCS operational LEAKAGE whenever REACTOR OPERATION exceeds COLD SHUTDOWN conditions."

has been changed to

"... RCS operational LEAKAGE whenever Tavg (average RCS temperature) exceeds 200°F (200 degrees Fahrenheit)."

TS Bases Section 3.1.C - APPLICABILITY The phrase "In operating modes above COLD SHUTDOWN,..."

has been changed to "In REACTOR OPERATION conditions where Tavg exceeds 20O0Fl... l1 TS 3.1.H Applicabilitv The phrase "...whenever REACTOR OPERATION exceeds COLD SHUTDOWN conditions."

has been changed to

"...whenever Tavg (average RCS temperature) exceeds 200°F (200 degrees Fahrenheit)."

TS 3.1.H.2.b The phrase "...exceeding COLD SHUTDOWN conditions..."

has been changed to

"...Tavg exceeding 200°F..."

TS Bases Section 3.1.H - APPLICABILITY The phrase "...when operating above COLD SHUTDOWN conditions."

has been changed to

"...when Tavg exceeds 200°F."

Page 3 of 6

Serial No. 06-1021 Docket Nos. 50-280 and 281 TS Bases Section 3.1.H.2.a and b The phrase "...exceeding COLD SHUTDOWN conditions..."

has been changed to

"...Tavg exceeding 200°F..."

TS4.19.B The phrase "...exceeding COLD SHUTDOWN conditions..."

has been changed to

"...Tavg exceeding 200°F..."

TS Bases Section SR 4.19.B The phrase "...exceeding COLD SHUTDOWN conditions..."

has been changed to

"...Tavg exceeding 200°F..."

TS 6.6.A.3 The phrase "...after exiting COLD SHUTDOWN conditions..."

has been changed to

"...after Tavg exceeds 200°F..."

5. Please provide justification for removing "...to be met until the next refueling outage... " from proposed Bases Sections 3.1. H. 2. a and b or alternatively discuss your plans to modify these bases sections to state "...to be met until the next refueling outage or SG tube inspection. "

Response - The phrase "to be met until the next refueling outage..." has been incorporated into the proposed TS Bases Section 3.1.H.2.a and b.

6. In the second paragraph of proposed SR 4.13.A1 there appears to be a typographical error, "met" should be "performed." Please discuss your plans to correct this typographical error.

Response - The word "met" has been changed to "performed" in the second paragraph of the proposed TS Bases Section SR 4.1 3.A.

Page 4 of 6

Serial No. 06-1021 Docket Nos. 50-280 and 281 You deleted the existing Bases for proposed TS Section 3.1.C which describes various leak detection instruments.

Please discuss whether this information is captured elsewhere in your TSs. The NRC staff notes that in the Bases for TS Section 4.13 you did not propose to incorporate the following sentence from the standard TSs: "These leakage detections systems are specified in LC0 (Limiting Condition for Operation) 3.4.75, "RCS Leakage Detection Instrumentation." If the information concerning the leakage detection instruments is not captured elsewhere, please discuss your plans to leave it in TS Section 3.1.C and to incorporate a sentence into the Bases for TS Section 4.73 indicating that the leakage detection instruments are specified in the Bases of TS Section 3. I.

Response - The previously deleted information concerning RCS leakage detection instruments will be retained in the TS Section 3.1.C Basis, and a sentence has been incorporated into the TS Bases Section SR 4.13.A indicating that the leakage detection instruments are specified in the Bases Section of TS Section 3.1.

In proposed TS Section 3. I. H, it would appear that TS Section 3.1. H. 2 would permit you to elect not to plug a tube provided the conditions in TS Section 3.1. H.2.a and TS Section 3.7. H.2.b were met.

This is not consistent with the Technical Specification Task Force (TSTF)-449.

In TSTF-449, the required actions are intended to apply only in the event that a tube that should have been plugged was inadvertently not plugged rather than electing not to plug a tube. Please discuss your plans to clarify your TSs in this regard. For example, terminology such as, "If the requirements of 3. I.H. I are not met for one or more SG tubes, then perform the following: "

Response - Proposed TS 3.1.H.2 has been revised to include the following introductory phrase, "If the requirements of 3.1.H.1 are not met for one or more SG tubes, then perform the following:" to ensure that it is clear that TS Section 3.1.H.2 would not permit you to elect not to plug a tube provided the conditions in TS Sections 3.1.H.2.a and 3.1.H.2.b were met.

In proposed TS Section 4.13.A, you proposed relaxing the sun/eillance frequency for verifying RCS operational leakage from daily to once every 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months .

Please discuss your plans to modify this requirement to be consistent with your existing TSs since this change is not consistent with TSTF-449.

Response - The TS SR 4.13.A frequency for verifying that the operational LEAKAGE is within limits has been changed from "once every 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months " to "once every 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months ." The associated change has also been made in the TS 4.13.A Bases section.

10. In several sections of your proposed TSs, there are 'Applicability" and ttObjective" sections. Please discuss why these sections are not included in every proposed TS section.

Page 5 of 6

Serial No. 06-1021 Docket Nos. 50-280 and 281 Response - "Applicability" and "Objective" sections have been added to TS 4.13.

Objective sections were not added to TS 3.1.C and 3.1.H since they are subsections of TS 3.1, Reactor Coolant System, which currently includes an Objective section that is applicable to its subsections. However, even though TS 3.1 also includes an Applicability section, separate Applicability sections were added to TS 3.1.C and 3.1.H to provide greater specificity regarding the conditions for which these two TS apply.

Page 6 of 6

Serial No. 06-1021 Docket Nos. 50-280 and 281 ATTACHMENT 2 DESCRIPTION AND ASSESSMENT Virginia Electric and Power Company (Dominion)

Surry Power Station Units 1 and 2

Serial No. 06-1021 Docket Nos. 50-280 and 281 DESCRIPTION AND ASSESSMENT

1.0 INTRODUCTION

The proposed license amendment revises the requirements in the Surry Power Station Units land 2 Technical Specifications (TS) related to steam generator tube integrity.

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

2.0 DESCRIPTION

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

Revise TS Table of Contents Add new TS 1.X - Definition of LEAKAGE Revise TS 3.1.C, "Leakage" Add new TS 3.1.H, "Steam Generator (SG) Tube Integrity" Revise TS Table 4.1 -2A - Delete ltem 10 and revise a reference in ltem 19 Add new TS 4.13 Surveillance, "RCS Operational Leakage" Replace existing TS 4.19, "Steam Generator Inservice Inspection" with new TS 4.19, "Steam Generator (SG) Tube Integrity" Add new TS 6.4.Q, "Steam Generator (SG) Program" Add new TS 6.6.A.3, "Steam Generator Tube Inspection Report" Proposed revisions to the TS Bases are also included in this application. As discussed in the NRC1s model safety evaluation, adoption of the revised TS Bases associated with TSTF-449, Revision 4, is an integral part of implementing this TS improvement. The changes to the affected TS Bases pages will be incorporated in accordance with the TS Bases Control Program.

3.0 BACKGROUND

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

4.0 REGULATORY REQUIREMENTS AND GUIDANCE The applicable regulatory requirements and guidance associated with this application are adequately addressed by the NRC Notice of Availability published on May 6, 2005 Page 1 of 5

Serial No. 06-1 021 Docket Nos. 50-280 and 281 (70 FR 24126), the NRC Notice for Comment published on March 2, 2005 (70 FR 10298), and TSTF-449, Revision 4.

5.0 TECHNICAL ANALYSIS

Dominion has reviewed the safety evaluation (SE) published on March 2, 2005 (70 FR 10298) as part of the CLllP 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. Dominion has concluded that the justifications presented in the TSTF proposal and the SE prepared by the NRC staff'are applicable to Surry Power Station Units 1 and 2 and justify this amendment for the incorporation of the changes to the Surry Units 1 and 2 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 No.

Steam Generator Model(s)

Effective Full Power Years (EFPY) of service for currently installed SGs Tubing Material Number of tubes r>er SG Number and percentage of tubes plugged in each SG Number of tubes repaired in each SG Surry Power Station (SPS) Units 1 and 2 Westinghouse Model 51 -F; %Loop SPS 1 19.5 EFPY at last inspection in April 2006 Allov 600TT I

SPS 2 20.6 EFPY at last inspection in October 2006 None I

Page 2 of 5

Serial No. 06-1021 Docket Nos. 50-280 and 281 Degradation mechanism(s) identified Current primary to secondary leakage limits Approved Alternate Tube Repair Criteria (ARC)

Approved SG Tube Repair Methods Performance criteria for accident leakage SPS 1 Outer diameter (OD) wear at anti-vibration bar intersections OD wear due to transient foreign objects OD wear caused by sludge lance equipment used during outage SPS 2 Same as SPS 1 above Inactive RCS Cold Leg pit indications TS -

Admin. Control Limit Per SG:

500 gpd

>75 gpd for 21 hr Total:

1 gPm 1 gpm total SG leakage at room temperature (~70°F) and normal atmospheric pressure (14.7 psi)

None None 1 gpm total SG leakage at room temperature (~70°F) and normal atmospheric pressure (14.7 psi) 7.0 NO SIGNIFICANT HAZARDS CONSIDERATION 7.1 Incorporation of TSTF-449, Revision 4 Dominion has reviewed the proposed no significant hazards consideration determination published on March 2, 2005 (70 FR 10298) as part of the CLIIP.

Dominion has concluded that the proposed determination presented in the notice is applicable to Surry Power Station Units 1 and 2 and the determination is hereby incorporated by reference to satisfy the requirements of 10 CFR 50.91 (a).

7.2 Changes to Address Improved Technical Specifications Format Dominion is proposing minor variations andlor deviations from the TS changes described in TSTF-449, Revision 4, to provide consistent terminology and format within Surry's custom TS, as well as consistency with Surry's design and licensing bases. For I example, Surry TS do not use the NUREG-1431 lmproved Standard TS (ITS) defined Page 3 of 5

Serial No. 06-1021 Docket Nos. 50-280 and 281 terms, such as, Condition, Action and Frequency or their associated Table format, as the Surry TS typically use a more narrative format. However, the intent of the CLllP wording has been maintained in the proposed TS change and has been used verbatim to the extent possible.

Also, Surry TS do not currently include a definition for LEAKAGE; consequently, the ITS definition for LEAKAGE, as modified by the CLIIP, is being incorporated into Surry's TS in this license amendment request. In addition, the Surry TS format separates Limiting Conditions for Operation (LCOs) and Action Statements (ASS) from Surveillance Requirements (SRs) by placing them in different TS sections (Sections 3 and 4, respectively). Also, Surry TS do not use the ITS MODE terminology convention for reactor operating conditions.

Surry TS use specific definitions for each operating condition instead, e.g., POWER OPERATION, HOT

SHUTDOWN, INTERMEDIATE

SHUTDOWN, REACTOR

CRITICAL, COLD SHUTDOWN and REFUELING SHUTDOWN. While not identical, the reactor operating MODES specified in the CLllP are generally consistent with the defined REACTOR OPERATION conditions used in the Surry license amendment request.

The corresponding REACTOR OPERATION conditions were used instead of the specified ITS MODES where appropriate. Also, the Applicability of several TS sections was described using words similar to "... whenever Tavg exceeds 200°F..." in lieu of MODES or listing out numerous REACTOR OPERATION conditions, and the SR frequency for certain TS SR was written using words similar to "prior to exceeding 200°F".

The minor variations andlor deviations from the specific wordinglformat provided in the CLllP do not change the meaning, intent or applicability of the CLIIP.

A table summarizing the minor variations andlor deviations from the TS changes described in TSTF-449, Revision 4, is provided in Attachment A.

A significant hazards consideration determination has been performed for the TS changes associated with terminology and format differences between the Surry TS and the ITS to facilitate incorporation of the changes described in TSTF-449, Revision 4.

Dominion has concluded that the proposed changes do not involve a significant hazards consideration because the changes do not:

1. Involve a siqnificant increase in the probability or consequences of an accident previouslv evaluated.

The proposed changes involve adding a new definition of RCS leakage and rewording certain Technical Specifications (TS) for consistency with NUREG-1431, Revision 3.

These changes do not involve any physical plant modifications or changes in plant operation; consequently, no technical changes are being made to the existing TS. As such, these changes are administrative in nature and do not affect initiators of analyzed events or assumed mitigation of accident or transient events. Therefore, these changes do not involve a significant increase in the probability or consequences of an accident previously evaluated.

Page 4 of 5

Serial No. 06-1021 Docket Nos. 50-280 and 281

2. Create the possibility of a new or different kind of accident from anv accident previouslv evaluated.

The proposed changes involve adding a new definition of RCS leakage and rewording certain Technical Specifications (TS) for consistency with NUREG-1431, Revision 3.

These administrative changes do not involve physical alteration of the plant (no new or different type of equipment will be installed) or changes in methods governing normal plant operation. The changes will not impose any new or different requirements or eliminate any existing requirements. Therefore, these changes do not create the possibility of a new or different kind of accident from any accident previously evaluated.

3. Involve a significant reduction in a margin of safetv.

The proposed changes involve adding a new definition of RCS leakage and rewording certain Technical Specifications (TS) for consistency with NUREG-1431, Revision 3.

The changes are administrative in nature and will not involve any technical changes.

The changes will not reduce a margin of safety because they have no impact on any safety analysis assumptions. Also, since these changes are administrative in nature, no question of safety is involved. Therefore, the changes do not involve a significant reduction in a margin of safety.

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

9.0 PRECEDENT This application is being made in accordance with the CLIIP. Dominion is not proposing significant variations and/or deviations from the TS changes described in TSTF-449, Revision 4, or the NRC staffs model SE published on March 2, 2005 (70 FR 10298). However, since Surry's TS are custom TS, as opposed to ITS, the changes proposed by the CLllP have been implemented such that they are consistent with the existing Surry TS format requirements. Consequently, these minor variations and/or deviations do not conflict with the applicability of the NRC1s model safety evaluation to the proposed changes.

10.0 REFERENCES

Federal Register Notices:

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

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

Page 5 of 5

Serial No. 06-1021 Docket Nos. 50-280 and 281 Section TOC 1.1 Definitions 83.4.4 B3.4.5 83.4.6 B3.4.7 CLIIP/TSTF 449 TS Revision None Revises the LEAKAGE definition in TS to include the parenthetical phrase "(primary to secondary LEAKAGE)" in item a.3 and item c and deletes the term "(SG)" in both items.

Deletes the term "in accordance with the Steam Generator Tube Surveillance Program."

in the RCS Loops - MODES 1 and 2 LC0 Bases section.

Deletes the term "in accordance with the Steam Generator Tube Surveillance Program."

in the RCS Loops - MODE 3 LC0 Bases section.

Deletes the term "in accordance with the Steam Generator Tube Surveillance Program."

in the RCS Loops - MODE 4 LC0 Bases section.

Deletes the term "in accordance with the Steam Generator Tube Surveillance Program."

in the RCS Loops - MODE 5, Loops Filled LC0 Bases section.

Attachm Surry TS Section TOC 1.X NIA NIA NIA lnclusion of Proposed Change into Surry Custom TS The Surry TS Table of Contents has been revised to reflect the newlrevised TS sections as appropriate.

Surry TS do not currently include a definition for LEAKAGE. The proposed change incorporates a definition for LEAKAGE into the Surry TS that is identical to the ITS Definition including the proposed TSTF change.

SPS TS do not include this TSlwording; therefore, no change is required.

SPS TS do not include this TSI wording; therefore, no change is required.

Page 1 of 5

Serial No. 06-1021 Docket Nos. 50-280 and 281 Section LC0 3.4.13 SR 3.4.13 CLllP/TSTF 449 TS Revision Revises RCS Operational LEAKAGE for primary to secondary LEAKAGE to 5 1 50 gallons per day primary to secondary LEAKAGE through any one SG.

Includes primary to secondary LEAKAGE in the CONDITIONS column of the LC0 ACTIONS.

Added new Note to Surveillance Requirement (SR) 3.4.13.1 indicating SR not applicable to primary to secondary LEAKAGE.

Revised SR 3.4.13.2 to verify primary to secondary LEAKAGE every 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . Added a new Note stating "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."

Surry TS Section 3.1.C.1 through 3.1.C.3 Inclusion of Proposed Change into Surry Custom TS Surry TS do not use the ITS MODE terminology; therefore, the applicability of the TS has been stated as follows: The following specifications are applicable to RCS operational LEAKAGE whenever Tavg (average RCS temperature) exceeds 200°F (200 degrees Fahrenheit), to address operating conditions above COLD SHUTDOWN.

Surry TS 3.1.C.2 through.6 LCOs and ACTIONS associated with RCS Operational LEAKAGE have been replaced with TS 3.1.C.1 through 3.1.C.3 specifications that are consistent with the revised ITS Section 3.4.1 3. Surry's TS format and reactor operating condition terminology is retained vs. the format and MODE terminology used in ITS. Specifically, MODE 3 is changed to HOT SHUTDOWN and MODE 5 is changed to COLD SHUTDOWN.

The existing RCS LEAKAGE detection specification has been renumbered from 3.1.C. 1 to 3.1.C.4 and the existing RCS pressure isolation valves' TS has been renumbered from 3.1.C.7 to 3.1.C.5 to accommodate the TSTF changes.

Surry TS do not use the ITS MODE terminology; therefore the applicability of the TS has been stated as follows: The following specifications are applicable to RCS operational LEAKAGE whenever Tavg (average RCS temperature) exceeds 200°F (200 degrees Fahrenheit), to address operating conditions above COLD SHUTDOWN.

New SPS TS 4.13.A includes the revised ITS SR 3.4.13.1 for verification that RCS operational LEAKAGE is within limits by performance of an RCS water inventory balance with the exception that the frequency has been specified as once every 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months instead of once every 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months frequency is consistent with the Page 2 of 5

Serial No. 06-1021 Docket Nos. 50-280 and 281 CLllPliSTF 449 TS Revision Attachml Surry TS Section B3.4.13 3.1.C.1 and 4.1 3 Bases Revise the Bases for the RCS Operational LEAKAGE TS to address TSTF-449, Rev. 4 changes.

Inclusion of Proposed Change into Surry Custom TS current Surry licensing basis. TS 4.13.A also includes the associated ITS Notes as revised by the TSTF with the exception that the word "performed" in Note 1 has been changed to "completed" to preclude confusion regarding when the verification is to be performedlcompleted.

New SPS TS 4.13.B includes the revised ITS SR 3.4.13.2 for verification of SG tube integrity every 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months by verifying primary to secondary LEAKAGE is 1150 gallons per day through any one SG.

TS 4.13.B also includes the new Note with the exception that the word "performed" has been changed to "completed" to preclude confusion regarding when the verification is to be performed1 completed.

The existing TS Basis for SPS TS 3.1.C is being replaced with Bases wording consistent with the ITS B3.4.13 Bases wording, as revised by TSTF-449, and Surry's alternate source term licensing basis, with the exception of the SRs Bases portion. The SRs Bases discussion section is included in the TS 4.13 Bases, which includes the RCS Operational LEAKAGE SRs. Consequently, the Background, Applicable Safety Analyses, Limiting Conditions for Operation, Applicability, Actions and References sections are included in the TS 3.1.C Basis, and the Surveillance Requirements and References (repeated) sections are included in the TS 4.1 3 Bases for consistency with SPS custom TS format (i.e., separate TS sections for LCOslAS and their associated SRs). An additional UFSAR reference has also been added to both Bases sections.

New SPS TS 3.1.H, SG Tube Integrity, has been added and is consistent with ITS 3.4.20. (Note: SPS TS LCOslASs and SRs are contained in different TS sections.)

Page 3 of 5

Serial No. 06-1021 Docket Nos. 50-280 and 281 CLIIP/TSTF 449 TS Revision SG Tube lntegrity Surveillance Requirements.

New Bases for the new SG Tube Integrity TS in accordance with TSTF-449, Rev. 4.

Attachm Surry TS Section 3.1.H and 4.19 Bases Inclusion of Proposed Change into Surry Custom TS Surry TS do not use the MODE terminology; therefore, the applicability of the TS has been stated as follows: The following specifications are applicable to RCS operational LEAKAGE whenever Tavg (average RCS temperature) exceeds 200°F (200 degrees Fahrenheit), to address operating conditions above COLD SHUTDOWN.

The ITS Note, "Separate Condition entry is allowed for each SG tube," has been revised to read, "A separate TS action entry is allowed for each SG tube," for consistency with SPS custom TS terminology.

The ITS COMPLETION TIME "prior to entering MODE 4" has been changed to "prior to Tavg exceeding 220°F" for consistency with SPS TS terminology.

Existing SPS TS 4.19, Steam Generator Inservice Inspection, has been replaced in its entirety by new TS 4.19, SG Tube Integrity. The new TS 4.19 SRs are consistent with ITS TS 3.4.20 SRs. The ITS phrase "prior to entering MODE 4" has been changed to "prior to Tavg exceeding 200°F" for consistency with SPS TS terminology.

As discussed above, TS 3.4.20 is divided into two parts to address the SPS TS format. Specifically, the LCOIAS portion is included in TS 3.1.H, and the SRs are included in TS 4.19. Consequently, the associated Bases 63.4.20 has been divided between the two SPS TS sections accordingly. TS references to other ITS sections have been changed to match the applicable SPS TS sections. The Background, Applicable Safety Analyses, Limiting Conditions for Operation, Applicability, Actions and References sections are included with the TS 3.1.H Bases, and the Surveillance Requirements and References (repeated) are included in the TS 4.1 9 Bases.

Page 4 of 5

Serial No. 06-1021 Docket Nos. 50-280 and 281 ITS Section CLllP/TSTF 449 TS Revision New Steam Generator (SG) Program descriptionlcriteria.

New Steam Generator Tube Inspection Report descriptionlcriteria.

Attachmc Surry TS Section Inclusion of Proposed Change into Surry Custom TS Also, the sentence in the TS 3.1.H Bases that states: "The accident analysis assumes that accident induced leakage does not exceed 1 gpm per SG." has been changed to read, "The accident analysis assumes that accident induced leakage does not exceed 1 gpm."

The words "per SG" have been deleted to accurately reflect Surry accident analysis assumptions.

Additional references (1 0 CFR 50.67 and RG 1. I 83) have been included and one reference deleted (10 CFR 100) in the TS Bases to reflect Surry's approved licensing and design bases regarding the dose consequences associated with design basis accidents.

New TS 6.4.Q, Steam Generator Program, has been incorporated into SPS TS.

New SPS TS 6.6.A.3, Steam Generator Tube lnspection Report, has been incorporated into SPS TS. The TS 6.6.A.3 text is identical to the revised ITS 5.6.9 text with the exception of the use of the term "after the initial entry into MODE 4," since Surry's TS do not use the MODE plant condition terminology. This phrase has been revised to I

"after Tavg exceeds 200°F" for consistency with SPS TS reactor operating condition terminology.

Page 5 of 5

Serial No. 06-1021 Docket Nos. 50-280 and 281 ATTACHMENT 3 PROPOSED TECHNICAL SPECIFICATIONS PAGES (MARK-UP)

Virginia Electric and Power Company (Dominion)

Surry Power Station Units 1 and 2

TECHNICAL SPECIFICATION TABLE OF CONTENTS SECTION TITLE PAGE DELETED EMERGENCY POWER SYSTEM TS 3.16-1 LOOP STOP VALVE OPERATION TS 3.17-1 MOVABLE INCORE INSTRUMENTATION TS 3.18-1 MAIN CONTROL ROOM BOTTLED AIR SYSTEM TS 3.19-1 SHOCK SUPPRESSORS (SNUBBERS)

TS 3.20- 1 DELETED AUXILIARY VENTILATION EXHAUST FILTER TRAINS TS 3.22-1 CONTROL AND RELAY ROOM VENTILATION SUPPLY FLLTER TS 3.23-1 TRAINS 4.0 SURVEILLANCE REQUIREMENTS 4.1 OPERATIONAL SAFETY REVIEW 4.2 AUGMENTED INSPECTIONS TS 4.2-1 4.3 DELETED f

4.4 CONTAINMENT TESTS TS 4.4-1 4.5 SPRAY SYSTEMS TESTS TS 4.5-1 4.6 EMERGENCY POWER SYSTEM PERIODIC TESTING TS 4.6-1 4.7 MAIN STEAM LINE TRIP VALVES TS 4.7-1 4.8 AUXILIARY FEEDWATER SYSTEM TS 4.8-1 4.9 RADIOACTIVE GAS STORAGE MONITORING SYSTEM TS 4.9-1 4.10 REACTIVITY ANOMALIES 4.1 1 SAFETY INJECTION SYSTEM TESTS 4.12 VENTILATION FILTER TESTS TS 4.12-1 4.14 DELETED Amendment Nos. 24k~&K+

TS iii TECHNICAL SPECIFICATION TABLE OF CONTENTS SECTION TITLE AUGMENTED INSERVICE INSPECTION PROGRAM FOR HIGH ENERGY LINES OUTSIDE OF CONTAINMENT LEAKAGE TESTING OF MISCELLANEOUS RADIOACTIVE MATERIALS SOURCES SHOCK SUPPRESSORS (SNUBBERS)

DELETED STEAM CONTROL ROOM AIR FILTRATION SYSTEM DESIGN FEATURES 5.1 SITE 5.2 CONTAINMENT 5.3 REACTOR 5.4 FUEL STORAGE ADMINISTRATIVE CONTROLS ORGANIZATION, SAFETY AND OPERATION REVIEW GENERAL NOTIFICATION AND REPORTING REQUIREMENTS ACTION TO BE TAKEN IF A SAFETY LIMIT IS EXCEEDED UNIT OPERATING PROCEDURES AND PROGRAMS STATION OPERATING RECORDS STATION REPORTING REQUIREMENTS ENVIRONMENTAL QUALIFICATIONS PROCESS CONTROL PROGRAM AND OFFSITE DOSE CALCULATION MANUAL PAGE TS 4.15-1 Amendment Nos..243azB242.

TS 1.0-8 W.

STAGGERED TEST BASIS A staggered test basis shall consist of:

a.

A test schedule for n systems, subsystems, trains or other designated components obtained by dividing the specified test interval into n equal subintervals, and

b.

The testing of one system, subsystem, train, or other designated component at the beginning of each subinterval.

Amendment Nos. l9hmH98

Insert 1 (in TS Section 1.0 DEFINITIONS - New Item XI X. LEAKAGE LEAKAGE shall be:

a. Identified LEAKAGE

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

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

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

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

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

5&\\0c.&e \\ fcmumhec as 7 s 3. \\. c.cl.3

-.y-w

\\-/ 5 or suspected leakage from the Reactor Coolant System shall be investigate-(

and evaluated. At least two means shall be available to detect reactor coolant system \\

I leakage. One of these means must depend on the detection of radionuclides in the h

and the source of the n, the reactor shall be ed within an additional aluations are that

Insert 2 (in TS Section 3.1.C - Replace existing TS 3.1.C.1 through.6)

The following specifications are applicable to RCS operational LEAKAGE whenever Tavg (average RCS temperature) exceeds 200°F (200 degrees Fahrenheit).

1 1 Specifications

1. RCS operational LEAKAGE shall be limited to:

a. No pressure boundary LEAKAGE,

b. 1 gpm unidentified LEAKAGE,

c. 10 gpm identified LEAKAGE, and

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

2.

a. If RCS operational LEAKAGE is not within the limits of 3.1.C.1 for reasons other than pressure boundary LEAKAGE or primary to secondary LEAKAGE, reduce LEAKAGE to within the specified limits within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months .

b. If the LEAKAGE is not reduced to within the specified limits within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months , the unit shall be brought to HOT SHUTDOWN within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and COLD SHUTDOWN within the following 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months .

3.

If RCS pressure boundary LEAKAGE exists, or primary to secondary LEAKAGE is not within the limit specified in 3.1.C.l.d, the unit shall be brought to HOT SHUTDOWN within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and COLD SHUTDOWN within the following 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months .

\\/below shall be functional as a pressure isolation device, except as specified leakage shall not exceed the amounts indicated.

Max. Allowable Leakage (see note Unit 1 Unit 2 (a) below)

Loop A, Cold Leg Loop B, Cold Leg Loop C, Cold Leg 31-79, I-SI-241 2-SI-79,231-241

$5.0 gprn for each valve

b. If Specificatio be met, an orderly shutdown shall be initiated and within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in &e=#~&p;"

-within the following 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months .

Notes (a)

1.

Leakage rates less than or equal to 1.0 gprn are considered acceptable.

2.

Leakage rates greater than 1.0 gpm but less than or equal to 5.0 gprn are considered acceptable if the latest measured rate has not exceeded the rate determined by the previous test by an amount that reduces the margin between measured leakage rate and the maximum permissible rate of 5.0 gprn by 50% or greater.

3.

Leakage rates greater than 1.0 gprn but less than or equal to 5.0 gprn are considered unacceptable if the latest measured rate exceeded the rate determined by the previous test by an amount that reduces the margin between measured leakage rate and the maximum permissible rate of 5.0 gprn by 50% or greater.

4.

Leakage rates greater than 5.0 gprn are considered unacceptable.

Control System.

Detection of leaks from the Coolant System is by more of the following:

1. An increased amount to maintain normal level in the pressurizer.

2.

A high temperature to collect reactor head flange leakage.

3.

Containment sump

4.

Containment press e, temperature, and humidity in*

7' If there is contamination of the reactor c o o l a n b e radiation monitoring

TS 3.1-15

-TUSBR~

3

~ 4 ~ 3 4 -

indicate the ?ejec&:z:z primar system 1 blowdo monitor.

Referen es +

F S F, Section 4.2.7 - @or Coolant sys@ Leakage

&AR, Section 14.3.h Rupure of a M d S t e a m Pipe D.

Maximum Reactor Coolant Activity Specifications

1. The total specific activity of the reactor coolant due to nuclides with half-lives of more than 15 minutes shall not exceed ioo/E pCi/cc whenever the reactor is critical or the average temperature is greater than 500°F, where E is the average sum of the beta and gamma energies, in Mev, per disintegration. If this limit is not satisfied, the reactor shall be shut down and cooled to 500°F or less within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months after detection.

Should this limit be exceeded by 25%, the reactor shall be made subcritical and cooled to 500°F or less within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months after detection.

Insert 3 (in TS 3.1.C Basis)

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 I I coolant LEAKAGE, through either normal operational wear or mechanical deterioration.

The purpose of the RCS Operational LEAKAGE limiting condition for operation (LCO) is to limit system operation in the presence of LEAKAGE from these sources to amounts that do not compromise safety.

This LC0 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 monitoring reactor coolant LEAKAGE into the containment area is necessary. Quickly separating the identified LEAKAGE from the unidentified LEAKAGE is necessary to provide quantitative information to the operators, allowing them to take corrective action should a leak occur that is detrimental to the safety of the facility and the public.

Leakage from the RCS is collected in the containment or by other systems. These systems are the Main Steam System, Condensate and Feedwater System, the Gaseous and Liquid Waste Disposal Systems, the Component Cooling System, and the Chemical and Volume Control System.

Detection of leaks from the RCS is by one or more of the following:

1. An increased amount of makeup water required to maintain normal level in the pressurizer.

2. A high temperature alarm in the leakoff piping provided to collect reactor head flange leakage.

3. Containment sump water level indication.

4. Containment pressure, temperature, and humidity indication.

If there is significant radioactive contamination of the reactor coolant, the radiation monitoring system provides a sensitive indication of primary system leakage. Radiation monitors which indicate primary system leakage include the containment gas and particulate monitors, the condenser air ejector monitor, the component cooling water monitor, and the steam generator blowdown monitor.

A limited amount of leakage inside containment is expected from auxiliary systems that cannot be made 100% leaktight. Leakage from these systems should be detected, located, and isolated from the containment atmosphere, if possible, to not interfere with RCS leakage detection.

This LC0 deals with protection of the reactor coolant pressure boundary (RCPB) from degradation and the core from inadequate cooling, in addition to preventing the accident analyses radiation release assumptions from being exceeded. The consequences of violating this LC0 include the possibility of a loss of coolant accident (LOCA).

APPLICABLE SAFETY ANALYSES - Except for primary to secondary LEAKAGE, the safety analyses do not address operational LEAKAGE. However, other operational LEAKAGE is related to the safety analyses for LOCA; the amount of leakage can affect the probability of such an event. The safety analysis for an event resulting in steam discharge to the atmosphere assumes that primary to secondary LEAKAGE from all steam generators (SGs) is 1 gpm or increases to 1 gpm as a result of accident induced conditions. The LC0 requirement to limit primary to secondary LEAKAGE through any one SG to less than or equal to 150 gallons per day is significantly less than the conditions assumed in the safety analysis.

Primary to secondary LEAKAGE is a factor in the dose releases outside containment resulting from a main steam line break (MSLB) accident. Other accidents or transients involve secondary steam release to the atmosphere, such as a steam generator tube rupture (SGTR). The leakage contaminates the secondary fluid.

The UFSAR (Ref. 2) analysis for SGTR assumes the contaminated secondary fluid is released via power operated relief valves or safety valves. The source term in the primary system coolant is transported to the affected (ruptured) steam generator by the break flow. The affected steam generator discharges steam to the environment for 30 minutes until the generator is manually isolated. The 1 gpm primary to secondary LEAKAGE transports the source term to the unaffected steam generators. Releases continue through the unaffected steam generators until the Residual Heat Removal System is placed in service.

The MSLB is less limiting for site radiation releases than the SGTR. The safety analysis for the MSLB accident assumes 1 gpm total primary to secondary LEAKAGE, including 500 gpd leakage into the faulted generator. The dose consequences resulting from the MSLB and the SGTR accidents are within the limits defined in the plant licensing basis.

The RCS operational LEAKAGE satisfies Criterion 2 of 10 CFR 50.36(c)(2)(ii).

LIMITING CONDITIONS FOR OPERATION - 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 LC0 could result

in continued degradation of the RCPB. LEAKAGE past seals and gaskets is not pressure boundary LEAKAGE.

Unidentified LEAKAGE One gallon per minute (gpm) of unidentified LEAKAGE is allowed as a reasonable minimum detectable amount that the containment air monitoring and containment sump level monitoring equipment can detect within a reasonable time period.

Violation of this LC0 could result in continued degradation of the RCPB, if the LEAKAGE is from the pressure boundary.

Identified LEAKAGE Up to 10 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. ldentified 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 LC0 could result in continued degradation of a component or system.

Primary to Secondary LEAKAGE through Anv 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. 3).

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

APPLICABILITY - In REACTOR OPERATION conditions where Tavg exceeds 200°F, I I the potential for RCPB LEAKAGE is greatest when the RCS is pressurized.

In COLD SHUTDOWN and REFUELING SHUTDOWN, LEAKAGE limits are not required because the reactor coolant pressure is far lower, resulting in lower stresses and reduced potentials for LEAKAGE.

LC0 3.1.C.5 measures leakage through each individual pressure isolation valve (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 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.

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

3.1.C.2.b and 3.1.C.3 If any pressure boundary LEAKAGE exists, or primary to secondary LEAKAGE is not within limit, or if unidentified or identified LEAKAGE cannot be reduced to within limits within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months , the reactor must be 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 HOT SHUTDOWN within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and COLD SHUTDOWN within the following 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months . This action reduces the LEAKAGE and also reduces the factors I I that tend to degrade the pressure boundary.

The allowed completion times are reasonable, based on operating experience, to reach the required unit conditions from full power conditions in an orderly manner and without challenging unit systems. In COLD SHUTDOWN, the pressure stresses acting on the RCPB are much lower, and further deterioration is much less likely.

REFERENCES

1. UFSAR, Chapter 4, Surry Units 1 and 2.

2. UFSAR, Chapter 14, Surry Units 1 and 2.

3. NEI 97-06! "Steam Generator Program Guidelines."

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

by a bubble in the pressurizer and/or pressurizer safety valves. A single PORV has adequate relieving capability to protect the Reactor Vessel from overpressurization when the transient is limited to either (1) the start of an idle Reactor Coolant Pump with the secondary water temperature of a steam generator 5 50°F above the RCS cold leg temperature or (2) the start of a charging pump and its injection into a water solid RCS.

The limitation for a maximum of one charging pump allowed OPERABLE and the surveillance required to verify that two charging pumps are inoperable below 350°F provide assurance that a mass addition pressure transient can be relieved by the operation of a single PORV, or equivalent.

The Safety Injection accumulators are not considered a credible mass input mechanism for RCS low temperature overpressurization concerns. There are administrative controls to ensure isolation, including de-energizing the Safety Injection (SI) accumulator isolation valves, during plant shutdown conditions (RCS pressure less than 1000 psig) to prevent inadvertent SI accumulator discharge into the RCS for low temperature overpressurization concerns. An undesired pressurizer PORV lift due to inadvertent SI accumulator discharge is not possible when SI accumulator pressure is less than the low temperature PORV lift setpoint specified in TS 3.1.G.

Therefore, SI accumulator isolation, and verification of such isolation is not necessary when SI accumulator pressure is less than the low temperature PORV setpoint.

A maximum pressurizer narrow range level of 33% has been selected to provide sufficient time, approximately 10 minutes, for operator response in case of a malfunction resulting in maximum charging flow from one charging pump (530 gpm). Operator action would be initiated by at least two alarms that would occur between the normal operating level and the maximum allowable level (33%). When both PORVs are inoperable and it is impossible to manually open at least one PORV, additional administrative controls shall be implemented to prevent a pressure transient that would exceed the limits of Appendix G to 10 CFR Part 50.

The requirements of this specification are only applicable when the Reactor Vessel head is bolted.

When the Reactor Vessel head is unbolted, a RCS pressure of < 100 psig will lift the head, thereby creating a relieving capability equivalent to at least one PORV.

Amendment Nos. 4iWhd%+

Insert 4 (New TS 3.1.H)

H. Steam Generator (SG) Tube lntecrritv Applicability The following specifications are applicable whenever Tavg (average RCS temperature) exceeds 200°F (200 degrees Fahrenheit).

Specifications I.

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.

2. If the requirements of 3.1.H.1 are not met for one or more SG tubes, then perform the following1:

a. Within 7 days, verify tube integrity of the affected tube(s) is maintained until the next refueling outage or SG tube inspection; and

b. Plug the affected tube(s) in accordance with the Steam Generator Program prior to Tavg exceeding 200°F following the next refueling outage or SG tube I I inspection.

3. If the required actions of Specification 3.1.H.2 are not completed within the specified completion time, or SG tube integrity is not maintained, the unit shall be brought to HOT SHUTDOWN within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and COLD SHUTDOWN within the following 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months .

Note:

1. A separate TS action entry is allowed for each SG tube.

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 LC0 3.1. A 2

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 6.4.Q, "Steam Generator (SG) Program," requires that a program be established and implemented to ensure that SG tube integrity is maintained. Pursuant to Specification 6.4.Q, 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 6.4.Q.

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).

APPLICABLE SAFETY ANALYSES - The steam generator tube rupture (SGTR) accident is the limiting design basis event for SG tubes and avoiding an SGTR is the basis for this Specification. The analysis of an SGTR event assumes a bounding primary to secondary LEAKAGE rate of 1 gpm, which is conservative with respect to the operational LEAKAGE rate limits in Specification 3.1.C, "RCS Operational LEAKAGE,"

plus the leakage rate associated with a double-ended rupture of a single tube. The UFSAR analysis for SGTR assumes the contaminated secondary fluid is released via power operated relief valves or safety valves. The source term in the primary system coolant is transported to the affected (ruptured) steam generator by the break flow. The affected steam generator discharges steam to the environment for 30 minutes until the generator is manually isolated. The 1 gpm primary to secondary LEAKAGE transports the source term to the unaffected steam generators. Releases continue through the unaffected steam generators until the Residual Heat Removal System is placed in service.

The analyses for design basis accidents and transients other than a SGTR assume the SG tubes retain their structural integrity (i.e., they are assumed not to rupture.) In these analyses, the steam discharge to the atmosphere is based on the total primary to secondary LEAKAGE from all SGs of 1 gallon per minute or is assumed to increase to I gallon per minute as a result of accident induced conditions. For accidents that do not involve fuel damage, the primary coolant activity level of DOSE EQUIVALENT 1-131 is assumed to be within Specification 3.1.D, "Maximum Reactor Coolant Activity," limits.

For accidents that assume fuel damage, the primary coolant activity is a function of the amount of activity released from the damaged fuel. The dose consequences of these

events are within the limits of GDC 19 (Ref. 2), 10 CFR 50.67 (Ref. 3) or Regulatory Guide I. I83 (Ref. 4), as appropriate.

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

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

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

In the context of this Specification, a SG tube is defined as the entire length of the tube, including the tube wall between the tube-to-tubesheet weld at the tube inlet and the tube-to-tubesheet weld at the tube outlet. 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 6.4.Q, "Steam Generator Program,"

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

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

The structural integrity performance criterion provides a margin of safety against tube burst or collapse under normal and accident conditions, and ensures structural integrity of the SG tubes under all anticipated transients included in the design specification.

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

case-by-case basis. The division between primary and secondary classifications will be based on detailed analysis andlor testing.

Structural integrity requires that the primary membrane stress intensity in a tube not exceed the yield strength for all ASME Code, Section Ill, Service Level A (normal operating conditions) and Service Level B (upset or abnormal conditions) transients included in the design specification. This includes safety factors and applicable design basis loads based on ASME Code, Section Ill, Subsection NB (Ref. 5) and Draft Regulatory Guide 1.121 (Ref. 6).

The accident induced leakage performance criterion ensures that the primary to secondary LEAKAGE caused by a design basis accident, other than a SGTR, is within the accident analysis assumptions. The accident analysis assumes that accident induced leakage does not exceed 1 gpm. The accident induced leakage rate includes any primary to secondary LEAKAGE existing prior to the accident in addition to primary to secondary LEAKAGE induced during the accident.

The operational LEAKAGE performance criterion provides an observable indication of SG tube conditions during plant operation. The limit on operational LEAKAGE is contained in Specification 3.1.C, "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.

APPLICABILIN - 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 when Tavg exceeds 200°F.

I I RCS conditions are far less challenging in COLD SHUTDOWN and REFUELING SHUTDOWN than during INTERMEDIATE SHUTDOWN, HOT SHUTDOWN, REACTOR CRITICAL and POWER OPERATION.

In COLD SHUTDOWN and REFUELING SHUTDOWN, 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.

3.1.H.2.a and b Specification 3.1.H.2 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 4.19. An evaluation of' SG tube integrity of the affected tube(s) must be made. Steam generator tube integrity is based on meeting the SG performance criteria described in the Steam Generator Program. The SG repair criteria define limits on SG tube degradation that allow for flaw growth between inspections while still providing assurance that the SG performance criteria will continue to be met. In order to determine if a SG tube that should have been plugged has tube integrity, an evaluation must be completed that demonstrates that the SG performance criteria will continue to be met until the next refueling outage or SG tube inspection. The tube integrity determination is based on I I 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, Specification 3.1.H.3 applies.

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

I I If the evaluation determines that the affected tube(s) have tube integrity, required action 3.1.H.2.b allows unit operation to continue until the next refueling outage or SG I I 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 Tavg exceeding 200°F following the next refueling outage or SG I I inspection. This completion time is acceptable since operation until the next inspection is supported by the operational assessment.

If the required actions and associated completion times of Specification 3.1.H.2 are not met or if SG tube integrity is not being maintained, the reactor must be brought to HOT SHUTDOWN within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and COLD SHUTDOWN within the following 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months .

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

REFERENCES I.

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

2. 10 CFR 50 Appendix A, GDC 19.

3. 10 CFR 50.67.

4. Regulatory Guide 1.183, "Alternative Radiological Source Terms for Evaluating Design Basis Accidents at Nuclear Power Reactors," July 2000.

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

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

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

DESCRIPTION I. Control Rod Assemblies Control Rod Assemblies Refueling Water Chemical Addition Tank Pressurizer Safety Valves Main Steam Safety Valves Containment Isolation Trip Refueling System Interlocks Service Water System Deleted

-3ebekted Diesel Fuel Supply Deleted TABLE 4.1-2A MINIMUM FREQUENCY FOR EQUIPMENT TESTS

13. Main Steam Line Trip Valves TEST FREQUENCY Rod drop times of all full Prior to reactor criticality:

length rods at hot conditions

a. For all rods following each removal of the reactor vessel head

b. For specially affected individual rods following any maintenance on or modification to the control rod drive system which could affect the drop time of those specific rods, and

c. Once per 18 months Partial movement of all rods Quarterly Functional Once per 18 months Setpoint Setpoint

Functional

Functional

Functional Per the Inservice Testing Program Per the Inservice Testing Program Once per 18 months Prior to refueling Once per 18 months

Fuel Inventory 5 dayslweek Functional Before each startup (TS 4.7)

(Full Closure)

The provisions of Specification 4.0.4.

are not applicable FSAR SECTION REFERENCE 7

TABLE 4.1-2A(CONTINUED)

DESCRIPTION

19. Primary Coolant System MINIMUM FREQUENCY FOR EQUIPMENT TESTS TEST FREQUENCY Functional

1. Periodic leakage tes listed in S~ecification

20. Containment Purge Functional MOV Leakage

21. Deleted

22. RCS Flow Flow 2 273,000 gpm

23. Deleted accompli~hed prior to entering POWER OPERATION after every time the plant is placed in COLD SHUTDOWN for refueling, after each time the plant is placed in COLD SHUTDOWN for 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months if testing has not been accomplished in the preceding 9 months, and prior to returning the valve to service after maintenance, repair or replacement work is performed.

Semi-Annual (Unit at power or shutdown) if purge valves are operated during interval(c)

Once per 18 months UFSAR SECTION REFERENCE (a) To satisfy ALARA requirements, leakage may be measured indirectly (as from the performance of pressure indicators) if accomplished in accordance with approved procedures and supported by computations showing that the method is capable of demonstrating valve compliance with the leakage criteria.

(b) Minimum differential test pressure shall not be below 150 psid.

(c) Refer to Section 4.4 for acceptance criteria.

See Specification 4.1.D.

Insert 5 (New TS 4.13) 4.1 3 RCS OPERATIONAL LEAKAGE Applicability The following specifications are applicable to RCS operational LEAKAGE whenever Tavg (average RCS temperature) exceeds 200°F (200 degrees Fahrenheit).

0 biective To verify that RCS operational LEAKAGE is maintained within the allowable limits.

Specifications A. Verify RCS operational LEAKAGE is within the limits specified in TS 3.1.C by performance of RCS water inventory balance once every 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .I1 I I B. Verify primary to secondary LEAKAGE is 5 150 gallons per day through any one SG once every 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months .'

Notes:

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

2. Not applicable to primary to secondary LEAKAGE.

BASES SURVEILLANCE REQUIREMENTS (SR)

Verifying RCS LEAKAGE to be within the Limiting Condition for Operation (LCO) limits ensures the integrity of the reactor coolant pressure boundary (RCPB) is maintained.

Pressure boundary LEAKAGE would at first appear as unidentified LEAKAGE and can only be positively identified by inspection. It should be noted that LEAKAGE past seals and gaskets is not pressure boundary LEAKAGE. Unidentified LEAKAGE and identified LEAKAGE are determined by performance of an RCS water inventory balance.

The RCS water inventory balance must be performed with the reactor at steady state I I operating conditions (stable pressure, temperature, power level, pressurizer and

makeup tank levels, makeup and letdown, and RCP seal injection and return flows).

The surveillance is modified by two notes. Note 1 states that this SR is not required to be completed until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after establishing steady state operation. The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months allowance provides sufficient time to collect and process all necessary data after stable unit conditions are established.

Steady state operation is required to perform a proper inventory balance since calculations during maneuvering are not useful.

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

An early warning of pressure boundary LEAKAGE or unidentified LEAKAGE is provided by the automatic systems that monitor the containment atmosphere radioactivity and the containment sump level. It should be noted that LEAKAGE past seals and gaskets is not pressure boundary LEAKAGE. These leakage detection systems are specified in the TS 3.1.C Bases.

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

The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months frequency is a reasonable interval to trend LEAKAGE and recognizes the I I importance of early leakage detection in the prevention of accidents.

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 LC0 3.1.H, "Steam Generator Tube Integrity," should be evaluated. The 150 gallons per day limit is measured at room temperature as described in Reference 4.

The operational LEAKAGE rate limit applies to LEAKAGE through any one SG.

If it is not practical to assign the LEAKAGE to an individual SG, all the primary to secondary LEAKAGE should be conservatively assumed to be from one SG. The surveillance is modified by a Note, which states that the Surveillance is not required to be performed until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after establishment of steady state operation. For RCS primary to secondary LEAKAGE determination, steady state is defined as stable RCS pressure, temperature, power level, pressurizer and makeup tank levels, 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. 4).

REFERENCES

1. UFSAR, Chapter 4, Surry Units I and 2.

2. UFSAR, Chapter 14, Surry Units 1 and 2.

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

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

4.19 STEAM GENERA OR INSERVICE INSPECTION Applicability \\

Applies to the periodic 1 service inspection of the Obiective To provide assurance of the steam generator pressure boundaries.

Specifications

\\ /

A. Each steam generator shall be operable pursuant to Specification 3.1.A.2 by performance of the inservice inspection program and the requirement of Specification 4.2&

- Each steam generator shall be and inspection at least the C. Steam Generator Tube Sample Selection and &spection - The steam generator tube minimum sample sige, inspection result classi nd the corresponding action I

Amendment No. +&-&I&&

from these critical areas.

b. The first sample of tubes inspection (subsequent to the preservice inspection)

1.

All nonplugged tubes that eviously h detectable wall penetrations 8"'

ae

3.

A tube inspectio pursuant to Specification 4.19 a.8 shall be performed P

B tube. If any selected tube does the passage of probe for a tube inspection, this

adjacen&ube shall be selected and subjected to a tube inspection.

c. The tubes

1.

The tubes selected from those areas of the tube sheet were previously found.

2.

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

The results of each sample one of the following three categories:

Category C-1 Less than 5% of the total tubes degraded tubes and none of the inspec d tubes are defective.

J tubes, but not more than 1% o the total tubes inspected are between 5% and 10% of the total bes inspected are degraded a

C-3 10% of the total tubes inspected are degr ed tubes or more than tubes are defective. 4 Note:

In all must exhibit significant in the above percentage calculations.

D. Inspected Frequencies - The spections of steam generator tubes shall be performed at the

a. The first inservice inspection e performed after 6 Effective Full Power

. Subsequent inservice 12 nor more than 24 secutive inspections reservice inspection, r if two consecutive n has not continued n interval may be Amend ent N 65, nit

$fix+

20 months. The

1. Primary-to-second luding leaks originating from tube-to-tube sheet ts of Specification 3.1.C.6.

2. A seismic occu g Basis Earthquake.

3. A loss-of-coolant ccident requiring engineered safeguards.

P line or feedwater line break. \\

a. As used in thi finish or contour of a tube Eddy-current

2. Degradation means a cracking, wastage, wear or general corrosion occurring on of a tube.

3. Degraded Tube means imperfections 2 20% of the nominal wall thickness caused wall thickness affected or

which the tube shall prior to the it leaks or contains a defect event of an Operating Basis line or feedwater line break

8. Tube Inspection means of the steam generator tube from the point of entry (hot leg around the U-bend to the top support of the cold leg.

ngth of each tube in es prior to service to shall be performed during subsequent completing the imit and all tubes

F. Reports '/

a. Following number of tubes within 15 days.

b. The complete inspection shall be was completed.

This report shall include:

1. Number and extent of tube ' spec d.

2. Location and percent of wall-ickness penetration for each indication of an imperfection. X

3. Identification of tubes gugged. \\

into Category C-3 and by special report a description of and corrective

erator tubes ensure

d. The program for tion of Regulatory s essential in order to maintain surveil1 event that there is evidence of that corrective measures can be The unit is expected to be o in a manner such that the secondary coolant mits found to result in negligible corrosion of aintained within be limited by the limitatin of steam

~

m T

n f

F k

Ame dme No 4,

TS 4.19-10 l+.!d+%

postulated accidents.

age of 500 gallons per rs of steam generator and an unscheduled required of all tubes with imperfec ceeding the plugging limit which, by the of the tube nominal wall thickness. Steam additional inspection, and revision of Specification, if necessary.

TABLE 4.19-1 MINIMUM NUMBER OF STEAM GENERATORS TO BE INSPECTED DURING INSERVICE INSPECTION No Yes Two Three Two Three First Inservice Inspection All Second & Subsequent Inservice Inspection>

Table Notation:

1. The inservice inspection may be limited to the number of steam generators in the plan performing in a like manner. Note that un found to be more severe than those in 0th inspect the most severe conditions.

should follow the instructions described in 1 above.

TABLE 4.19-2 STEAM GENERATOR TUBE INSPECTION I st SAMPLE INSPECTION

//

2nd SAMPLE INSPECTION 3rd SAMPLE INSPECTION Action Required Result Action Required N/A Action Required Result

+

Plug defective None and inspect addition*

Plug defective tubes and inspect addit-4s tubes in 2 s tub& in this S.G.

Plug defective tubes erforrn action >

Perform action for C-3 result of first sample 11 other S.G.s are C-1 4 for C-3 result of first sample Special Report None Some S.G.s C-2 but no additional S.G. are C-3 Perform action for C-2 result of second sample Additional S.G. is C-3 Inspect all tubes in each S.G.

and plug defective tubes Special Report N

S = 3- % Where N is the number of steam generators in the unit, and n is the number of steam generators inspected during an inspection n

Insert 6 (in TS 4.19 - Replace existina TS 4.19 in its entirety) 4,19 STEAM GENERATOR (SG) TUBE INTEGRITY Applicability Applies to the verification of SG tube integrity in accordance with the Steam Generator Program.

Obiective To provide assurance of SG tube integrity.

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

B. Verify that each inspected SG tube that satisfies the tube repair criteria is plugged in accordance with the Steam Generator Program prior to Tavg exceeding 200°F following a SG tube inspection.

I I SURVEILLANCE REQUIREMENTS (SR)

During shutdown periods the SGs are inspected as required by this SR and the Steam Generator Program. NEI 97-06, Steam Generator Program Guidelines (Ref. I), and its referenced EPRl Guidelines, establish the content of the Steam Generator Program.

Use of the Steam Generator Program ensures that the inspection is appropriate and consistent with accepted industry practices.

During SG inspections a condition monitoring assessment of the SG tubes is performed.

The condition monitoring assessment determines the "as found" condition of the SG tu~bes. The purpose of the condition monitoring assessment is to ensure that the SG performance criteria have been met for the previous operating period.

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

lr~spection 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.

lr~spection 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 4.19.A. The frequency is determined by the operational assessment and other limits in the SG examination gluidelines (Ref. 7).

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 6.4.Q contains prescriptive requirements concerning inspection intervals to provide added assurance that the SG performance criteria will be met between scheduled inspections.

During an SG inspection, any inspected tube that satisfies the Steam Generator Program repair criteria is removed from service by plugging. The tube repair criteria delineated in Specification 6.4.Q 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 and Reference 7 provide 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 Tavg exceeding 200°F following a SG inspection ensures that I I th~e Surveillance has been completed and all tubes meeting the repair criteria are plugged prior to subjecting the SG tubes to significant primary to secondary pressure differential.

REFERENCES

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

2. 10 CFR 50 Appendix A, GDC 19.

3. 10 CFR 50.67.

4. Regulatory Guide 1.183, "Alternative Radiological Source Terms for Evaluating Design Basis Accidents at Nuclear Power Reactors," July 2000.

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

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

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

0. Radiological Environmental Monitoring Program A program shall be provided to monitor the radiation and radionuclides in the environs of the plant. The program shall provide (1) representative measurements of radioactivity in the highest potential exposure pathways, and (2) verification of the accuracy of the effluent monitoring program and modeling of environmental exposure pathways. The program shall (1) be contained in the ODCM, (2) conform to the guidance of Appendix I to 10 CFR Part 50, and (3) include the following:

1) Monitoring, sampling, analysis, and reporting of radiation and radionuclides in the environment in accordance with the methodology and parameters in the ODCM,

2) A Land Use Census to ensure that changes in the use of areas at and beyond the SITE BOUNDARY are identified and that modifications to the monitoring program are made if required by the results of this census, and

3) Participation in a Interlaboratory Comparison Program to ensure that independent checks on the precision and accuracy of the measurements of radioactive materials in environmental sample matrices are performed as part of the quality assurance program for environmental monitoring.

A secondary water chemistry monitoring program shall be provided to inhibit steam generator tube degradation. This program shall include the following:

1) Identification of a sampling schedule for the critical parameters and control points for these parameters;

2) Identification of the procedures used to quantify parameters that are critical to control points;

3) Identification of process sampling points;

4) Procedure for the recording and management of data;

5) Procedures defining corrective actions for off control point chemistry conditions; and

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

Amendment Nos. SFkmG9&

Insert 7 (new TS 6.4.Q)

Q. Steam Generator (SG) Program 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:

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.

2. 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.

a. 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.

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

c. The operational LEAKAGE performance criterion is specified in TS 3.1.C and 4.1 3, "RCS Operational LEAKAGE.

3. 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.

4. 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 4.a, 4.b, and 4.c 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.

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

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

c. If crack indications are found in any SG tube, then the next inspection for each SG for the degradation mechanism that caused the crack indication shall not exceed 24 effective full power months or one refueling outage (whichever is less).

If definitive information, such as from examination of a pulled tube, diagnostic non-destructive testing, or engineering evaluation indicates that a crack-like indication is not associated with a crack(s), then the indication need not be treated as a crack.

5. Provisions for monitoring operational primary to secondary LEAKAGE.

b. The results of specific activity analysis in which the primary coolant exceeded the limits of Specification 3.1.D.4. In addition, the information itemized in Specification 3.1.D.4 shall be included in this report.

Amendment Nos. %4&m&WL

Insert 8 (new TS 6.6.A.3) 3,. Steam Generator Tube Inspection Report A report shall be submitted within 180 days after Tavg exceeds 200°F following I I completion of an inspection performed in accordance with the Specification 6.4.Q1 Steam Generator (SG) Program. The report shall include:

The scope of inspections performed on each SG, Active degradation mechanisms found, Nondestructive examination techniques utilized for each degradation mechanism, Location, orientation (if linear), and measured sizes (if available) of service induced indications, Number of tubes plugged during the inspection outage for each active degradation mechanism, Total number and percentage of tubes plugged to date, The results of condition monitoring, including the results of tube pulls and in-situ testing, and The effective plugging percentage for all plugging in each SG.

Serial No. 06-1021 Docket Nos. 50-280 and 281 ATTACHMENT 4 PROPOSED TECHNICAL SPECIFICATIONS PAGES (TYPED)

Virginia Electric and Power Company (Dominion)

Surry Power Station Units 1 and 2

TECHNICAL SPECIFICATION TABLE OF CONTENTS SECTION TITLE PAGE DELETED EMERGENCY POWER SYSTEM LOOP STOP VALVE OPERATION TS 3.17-1 MOVABLE INCORE INSTRUMENTATION TS 3.18-1 MAIN CONTROL ROOM BOTTLED AIR SYSTEM TS 3.19-1 SHOCK SUPPRESSORS (SNUBBERS)

TS 3.20-1 DELETED AUXILIARY VENTILATION EXHAUST FILTER TRAINS TS 3.22-1 CONTROL AND RELAY ROOM VENTILATION SUPPLY FILTER TRAINS TS 3.23-1 SURVEILLANCE REQUIREMENTS TS 4.0-1 OPERATIONAL SAFETY REVIEW AUGMENTED INSPECTIONS DELETED CONTAINMENT TESTS SPRAY SYSTEMS TESTS EMERGENCY POWER SYSTEM PERIODIC TESTING MAIN STEAM LINE TRIP VALVES AUXILIARY FEEDWATER SYSTEM RADIOACTIVE GAS STORAGE MONITORING SYSTEM REACTIVITY ANOMALIES SAFETY INJECTION SYSTEM TESTS VENTILATION FILTER TESTS RCS OPERATIONAL LEAKAGE DELETED Amendment Nos.

TECHNICAL SPECIFICATION TABLE OF CONTENTS SECTION 4.15 4.16 4.17 4.18 4.19 4.20 TITLE AUGMENTED INSERVICE INSPECTION PROGRAM FOR HIGH ENERGY LINES OUTSIDE OF CONTAINMENT LEAKAGE TESTING OF MISCELLANEOUS RADIOACTIVE MATERIALS SOURCES SHOCK SUPPRESSORS (SNUBBERS)

DELETED STEAM GENERATOR (SG) TUBE INTEGRITY CONTROL ROOM AIR FILTRATION SYSTEM 5.0 DESIGN FEATURES 5.1 SITE 5.2 CONTAINMENT 5.3 REACTOR 5.4 FUEL STORAGE 6.0 ADMINISTRATIVE CONTROLS 6.1 ORGANIZATION, SAFETY AND OPERATION REVIEW 6.2 GENERAL NOTIFICATION AND REPORTING REQUIREMENTS 6.3 ACTION TO BE TAKEN IF A SAFETY LIMIT IS EXCEEDED 6.4 UNIT OPERATING PROCEDURES AND PROGRAMS 6.5 STATION OPERATING RECORDS 6.6 STATION REPORTING REQUIREMENTS 6.7 ENVIRONMENTAL QUALIFICATIONS 6.8 PROCESS CONTROL PROGRAM AND OFFSITE DOSE CALCULATION MANUAL PAGE TS 4.15-1 TS 4.16-1 TS 4.17-1 TS 4.19-1 1

TS 4.20-1 TS 5.1-1 TS 5.1-1 TS 5.2-1 TS 5.3-1 TS 5.4-1 TS 6.1-1 TS 6.1-1 TS 6.2-1 TS 6.3-1 TS 6.4-1 TS 6.5-1 TS 6.6-1 TS 6.7-1 TS 6.8-1 Amendment Nos.

W.

STAGGERED TEST BASIS A staggered test basis shall consist of:

a.

A test schedule for n systems, subsystems, trains or other designated components obtained by dividing the specified test interval into n equal subintervals, and

b.

The testing of one system, subsystem, train, or other designated component at the beginning of each subinterval.

X.

LEAKAGE LEAKAGE shall be:

a.

Identified LEAKAGE

1.

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

2.

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

3.

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

b.

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

c.

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

Amendment Nos.

C.

RCS Operational LEAKAGE Applicability The following specifications are applicable to RCS operational LEAKAGE whenever TaVg (average RCS temperature) exceeds 200°F (200 degrees Fahrenheit).

Specifications

1. RCS operational LEAKAGE shall be limited to:

a. No pressure boundary LEAKAGE,

b. 1 gpm unidentified LEAKAGE,

c. 10 gpm identified LEAKAGE, and

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

2.a. If RCS operational LEAKAGE is not within the limits of 3.1.C.1 for reasons other than pressure boundary LEAKAGE or primary to secondary LEAKAGE, reduce LEAKAGE to within the specified limits within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months .

b. If the LEAKAGE is not reduced to within the specified limits within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months , the unit shall be brought to HOT SHUTDOWN within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and COLD SHUTDOWN within the following 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months .

3.

If RCS pressure boundary LEAKAGE exists, or primary to secondary LEAKAGE is not within the limit specified in 3.1.C. 1.d, the unit shall be brought to HOT SHUTDOWN within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and COLD SHUTDOWN within the following 3 0 hours0 days 0 hours 0 weeks 0 months .

Amendment Nos.

4.

Detected or suspected leakage from the Reactor Coolant System shall be investigated and evaluated. At least two means shall be available to detect reactor coolant system leakage. One of these means must depend on the detection of radionuclides in the containment.

5.a. Prior to going critical all primary coolant system pressure isolation valves listed below shall be functional as a pressure isolation device, except as specified in 3.1.C.5.b. Valve leakage shall not exceed the amounts indicated.

Loop A, Cold Leg Loop B, Cold Leg Loop C, Cold Leg Max. Allowable Leakage (see note Unit 1 Unit 2

-SI-241 2-SI-79,2-SI-241 I

5.0 gprn for each valve 41-242 2-SI-82,241-242 41-243 2-SI-85,2431-243

b. If Specification 3.1.C.5.a cannot be met, an orderly shutdown shall be initiated and the reactor shall be in HOT SHUTDOWN within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in COLD SHUTDOWN within the following 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months .

(a)

1. Leakage rates less than or equal to 1.0 gprn are considered acceptable.

2.

Leakage rates greater than 1.0 gprn but less than or equal to 5.0 gprn are considered acceptable if the latest measured rate has not exceeded the rate determined by the previous test by an amount that reduces the margin between measured leakage rate and the maximum permissible rate of 5.0 gprn by 50% or greater.

3.

Leakage rates greater than 1.0 gpm but less than or equal to 5.0 gprn are considered unacceptable if the latest measured rate exceeded the rate determined by the previous test by an amount that reduces the margin between measured leakage rate and the maximum permissible rate of 5.0 gprn by 50% or greater.

4.

Leakage rates greater than 5.0 gprn are considered unacceptable.

Amendment Nos.

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 limiting condition for operation (LCO) is to limit system operation in the presence of LEAKAGE from these sources to amounts that do not compromise safety. This LC0 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 monitoring reactor coolant LEAKAGE into the containment area is necessary. Quickly separating the identified LEAKAGE from the unidentified LEAKAGE is necessary to provide quantitative information to the operators, allowing them to take corrective action should a leak occur that is detrimental to the safety of the facility and the public.

Leakage from the RCS is collected in the containment or by other systems. These systems are the Main Steam System, Condensate and Feedwater System, the Gaseous and Liquid Waste Disposal Systems, the Component Cooling System, and the Chemical and Volume Control System.

Detection of leaks from the RCS is by one or more of the following:

1.

An increased amount of makeup water required to maintain normal level in the pressurizer.

2. A high temperature alarm in the leakoff piping provided to collect reactor head flange leakage.

3.

Containment sump water level indication.

4.

Containment pressure, temperature, and humidity indication.

If there is significant radioactive contamination of the reactor coolant, the radiation monitoring system provides a sensitive indication of primary system leakage. Radiation monitors which indicate primary system leakage include the containment gas and particulate monitors, the condenser air ejector monitor, the component cooling water monitor, and the steam generator blowdown monitor.

A limited amount of leakage inside containment is expected from auxiliary systems that cannot be made 100% leaktight. Leakage from these systems should be detected, located, and isolated from the containment atmosphere, if possible, to not interfere with RCS leakage detection.

Amendment Nos.

This L C 0 deals with protection of the reactor coolant pressure boundary (RCPB) from degradation and the core from inadequate cooling, in addition to preventing the accident analyses radiation release assumptions from being exceeded. The consequences of violating this LC0 include the possibility of a loss of coolant accident (LOCA).

APPLICABLE SAFETY ANALYSES - Except for primary to secondary LEAKAGE, the safety analyses do not address operational LEAKAGE. However, other operational LEAKAGE is related to the safety analyses for LOCA; the amount of leakage can affect the probability of such an event. The safety analysis for an event resulting in steam discharge to the atmosphere assumes that primary to secondary LEAKAGE from all steam generators (SGs) is 1 gprn or increases to 1 gpm as a result of accident induced conditions. The LC0 requirement to limit primary to secondary LEAKAGE through any one SG to less than or equal to 150 gallons per day is significantly less than the conditions assumed in the safety analysis.

Primary to secondary LEAKAGE is a factor in the dose releases outside containment resulting from a main steam line break (MSLB) accident. Other accidents or transients involve secondary steam release to the atmosphere, such as a steam generator tube rupture (SGTR). The leakage contaminates the secondary fluid.

The UFSAR (Ref. 2) analysis for SGTR assumes the contaminated secondary fluid is released via power operated relief valves or safety valves. The source term in the primary system coolant is transported to the affected (ruptured) steam generator by the break flow. The affected steam generator discharges steam to the environment for 30 minutes until the generator is manually isolated. The 1 gpm primary to secondary LEAKAGE transports the source term to the unaffected steam generators. Releases continue through the unaffected steam generators until the Residual Heat Removal System is placed in service.

The MSLB is less limiting for site radiation releases than the SGTR. The safety analysis for the MSLB accident assumes 1 gpm total primary to secondary LEAKAGE, including 500 gpd leakage into the faulted generator. The dose consequences resulting from the MSLB and the SGTR accidents are within the limits defined in the plant licensing basis.

The RCS operational LEAKAGE satisfies Criterion 2 of 10 CFR 50.36(c)(2)(ii).

LIMITING CONDITIONS FOR OPERATION - 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 LC0 could result in continued degradation of the RCPB. LEAKAGE past seals and gaskets is not pressure boundary LEAKAGE.

Amendment Nos.

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

c. Identified LEAKAGE Up to 10 gpm of identified LEAKAGE is considered allowable because LEAKAGE is from known sources that do not interfere with detection of unidentified LEAKAGE and is well within the capability of the RCS Makeup System. Identified LEAKAGE includes LEAKAGE to the containment from specifically known and located sources, but does not include pressure boundary LEAKAGE or controlled reactor coolant pump (RCP) seal leakoff (a normal function not considered LEAKAGE). Violation of this LC0 could result in continued degradation of a component or system.

d. 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. 3). The Steam Generator Program operational LEAKAGE performance criterion in NEI 97-06 states, "The RCS operational primary to secondary leakage through any one SG shall be limited to 150 gallons per day." The limit is based on operating experience with SG tube degradation mechanisms that result in tube leakage. The operational leakage rate criterion in conjunction with the implementation of the Steam Generator Program is an effective measure for minimizing the frequency of steam generator tube ruptures.

APPLICABILITY - In REACTOR OPERATION conditions where Tavg exceeds 200°F, the potential for RCPB LEAKAGE is greatest when the RCS is pressurized.

In COLD SHUTDOWN and REFUELING SHUTDOWN, LEAKAGE limits are not required because the reactor coolant pressure is far lower, resulting in lower stresses and reduced potentials for LEAKAGE.

LC0 3.1.C.5 measures leakage through each individual pressure isolation valve (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.

Amendment Nos.

ACTIONS 3.1.C.2.a Unidentified LEAKAGE or identified LEAKAGE in excess of the LC0 limits must be reduced to within limits within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months . This completion time allows time to verify leakage rates and either identify unidentified LEAKAGE or reduce LEAKAGE to within limits before the reactor must be shut down. This action is necessary to prevent further deterioration of the RCPB.

3.1.C.2.b and 3.1.C.3 If any pressure boundary LEAKAGE exists, or primary to secondary LEAKAGE is not within limit, or if unidentified or identified LEAKAGE cannot be reduced to within limits within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months , the reactor must be 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 HOT SHUTDOWN within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and COLD SHUTDOWN within the following 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-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 unit conditions from full power conditions in an orderly manner and without challenging unit systems. In COLD SHUTDOWN, the pressure stresses acting on the RCPB are much lower, and fbrther deterioration is much less likely.

REFERENCES

1.

UFSAR, Chapter 4, Surry Units 1 and 2.

2.

UFSAR, Chapter 14, Surry Units 1 and 2.

3.

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

4.

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

Amendment Nos.

D.

Maximum Reactor Coolant Activity Specifications

1. The total specific activity of the reactor coolant due to nuclides with half-lives of more than 15 minutes shall not exceed ioo/E pCi/cc whenever the reactor is critical or the average temperature is greater than 500°F, where E is the average sum of the beta and gamma energies, in Mev, per disintegration. If this limit is not satisfied, the reactor shall be shut down and cooled to 500°F or less within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months after detection.

Should this limit be exceeded by 25%, the reactor shall be made subcritical and cooled to 500°F or less within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months after detection.

2. The specific activity of the reactor coolant shall be limited to 5 1.0 pCi/cc DOSE EQUIVALENT I-13 1 whenever the reactor is critical or the average temperature is greater than 500°F.

3.

The requirements of D-2 above may be modified to allow the specific activity of the reactor coolant > 1.0 pCi/cc DOSE EQUIVALENT 1-13 1 but less than 10.0 pCi/cc DOSE EQUIVALENT 1-13 1. Following shutdown, the unit may be restarted andlor operation may continue for up to 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months provided that operation under these circumstances shall not exceed 10 percent of the unit's total yearly operating time.

With the specific activity of the reactor coolant > 1.0 pCi/cc DOSE EQUIVALENT I-13 1 for more than 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months during one continuous time interval or exceeding 10.0 pCi/cc DOSE EQUIVALENT 1-13 1, the reactor shall be shut down and cooled to 500°F or less within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months after detection.

4.

If the specific activity of the reactor coolant exceeds l.O/~Ci/cc DOSE EQUIVALENT 1-13 1 or 1 0 0 1 ~

pCilcc, a report shall be prepared and submitted to the Commission pursuant to Specification 6.6.A.2. This report shall contain the results of the specific activity analysis together with the following information:

a.

Reactor power history starting 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months prior to the first sample in which the limit was exceeded,

b.

Clean-up system flow history starting 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months prior to the first sample in which the limit was exceeded, Amendment Nos.

H.

Steam Generator (SG) Tube Integrity Applicability The following specifications are applicable whenever Tavg (average RCS temperature) exceeds 200°F (200 degrees Fahrenheit).

Specifications

1.

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.

2.

If the requirements of 3.1.H. 1 are not met for one or more SG tubes, then perform the following: '

a. Within 7 days, verify tube integrity of the affected tube(s) is maintained until the next refueling outage or SG tube inspection; and

b. Plug the affected tube(s) in accordance with the Steam Generator Program prior to Tavg exceeding 200°F following the next refueling outage or SG tube inspection.

3.

If the required actions of Specification 3.1.H.2 are not completed within the specified completion time, or SG tube integrity is not maintained, the unit shall be brought to HOT SHUTDOWN within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and COLD SHUTDOWN within the following 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months .

Note:

1. A separate TS action entry is allowed for each SG tube.

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 LC0 3.1.A.2.

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

Amendment Nos.

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 6.4.4, "Steam Generator (SG) Program," requires that a program be established and implemented to ensure that SG tube integrity is maintained. Pursuant to Specification 6.4.4, 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 6.4.4. 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).

APPLICABLE SAFETY ANALYSES - The steam generator tube rupture (SGTR) accident is the limiting design basis event for SG tubes and avoiding an SGTR is the basis for this Specification.

The analysis of an SGTR event assumes a bounding primary to secondary LEAKAGE rate of 1 gpm, which is conservative with respect to the operational LEAKAGE rate limits in Specification 3.1.C, "RCS Operational LEAKAGE," plus the leakage rate associated with a double-ended rupture of a single tube. The UFSAR analysis for SGTR assumes the contaminated secondary fluid is released via power operated relief valves or safety valves. The source term in the primary system coolant is transported to the affected (ruptured) steam generator by the break flow. The affected steam generator discharges steam to the environment for 30 minutes until the generator is manually isolated. The 1 gpm primary to secondary LEAKAGE transports the source term to the unaffected steam generators. Releases continue through the unaffected steam generators until the Residual Heat Removal System is placed in service.

The analyses for design basis accidents and transients other than a SGTR assume the SG tubes retain their structural integrity (i.e., they are assumed not to rupture.) In these analyses, the steam discharge to the atmosphere is based on the total primary to secondary LEAKAGE from all SGs of 1 gallon per minute or is assumed to increase to 1 gallon per minute as a result of accident induced conditions. For accidents that do not involve fuel damage, the primary coolant activity level of DOSE EQUIVALENT 1-1 3 1 is assumed to be within Specification 3.1.D, "Maximum Reactor Coolant Activity," limits. For accidents that assume fuel damage, the primary coolant activity is a function of the amount of activity released from the damaged fuel. The dose consequences of these events are within the limits of GDC 19 (Ref. 2), 10 CFR 50.67 (Ref. 3) or Regulatory Guide 1.183 (Ref. 4), as appropriate.

Amendment Nos.

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

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

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

In the context of this Specification, a SG tube is defined as the entire length of the tube, including the tube wall between the tube-to-tubesheet weld at the tube inlet and the tube-to-tubesheet weld at the tube outlet. 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 6.4.4, "Steam Generator Program," and describe acceptable SG tube performance. The Steam Generator Program also provides the evaluation process for determining conformance with the SG performance criteria.

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

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

Amendment Nos.

Structural integrity requires that the primary membrane stress intensity in a tube not exceed the yield strength for all ASME Code, Section 111, 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 111, Subsection NB (Ref. 5) and Draft Regulatory Guide 1.12 1 (Ref. 6).

The accident induced leakage performance criterion ensures that the primary to secondary LEAKAGE caused by a design basis accident, other than a SGTR, is within the accident analysis assumptions. The accident analysis assumes that accident induced leakage does not exceed 1 gpm. The accident induced leakage rate includes any primary to secondary LEAKAGE existing prior to the accident in addition to primary to secondary LEAKAGE induced during the accident.

The operational LEAKAGE performance criterion provides an observable indication of SG tube conditions during plant operation. The limit on operational LEAKAGE is contained in Specification 3.1.C, "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 when TWg exceeds 200°F.

RCS conditions are far less challenging in COLD SHUTDOWN and REFUELING SHUTDOWN than during INTERMEDIATE SHUTDOWN, HOT SHUTDOWN, REACTOR CRITICAL and POWER OPERATION. In COLD SHUTDOWN and REFUELING SHUTDOWN, 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.

Amendment Nos.

3.1.H.2.a and b Specification 3.

1.2 applies if it is (

TS 3.1-30 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 4.19. An evaluation of SG tube integrity of the affected tube(s) must be made. Steam generator tube integrity is based on meeting the SG performance criteria described in the Steam Generator Program. The SG repair criteria define limits on SG tube degradation that allow for flaw growth between inspections while still providing assurance that the SG performance criteria will continue to be met. In order to determine if a SG tube that should have been plugged has tube integrity, an evaluation must be completed that demonstrates that the SG performance criteria will continue to be met until the next refueling outage or SG tube inspection. The tube integrity determination is based on the estimated condition of the tube at the time the situation is discovered and the estimated growth of the degradation prior to the next SG tube inspection. If it is determined that tube integrity is not being maintained, Specification 3.1.H.3 applies.

A completion time of 7 days is sufficient to complete the evaluation while minimizing the risk of unit 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 3.1.H.2.b allows unit 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 Tavg exceeding 200°F 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.

If the required actions and associated completion times of Specification 3.1.H.2 are not met or if SG tube integrity is not being maintained, the reactor must be brought to HOT SHUTDOWN within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and COLD SHUTDOWN within the following 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months .

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

Amendment Nos.

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

10 CFR 50 Appendix A, GDC 19.

10 CFR 50.67.

Regulatory Guide 1.183, "Alternative Radiological Source Terms for Evaluating Design Basis Accidents at Nuclear Power Reactors," July 2000.

ASME Boiler and Pressure Vessel Code, Section 111, Subsection NB.

Draft Regulatory Guide 1.12 1, "Basis for Plugging Degraded Steam Generator Tubes," August 1976.

EPRI, ccPressurized Water Reactor Steam Generator Examination Guidelines."

Amendment Nos.

DESCRIPTION

1. Control Rod Assemblies Control Rod Assemblies Refueling Water Chemical Addition Tank Pressurizer Safety Valves Main Steam Safety Valves Containment Isolation Trip Refueling System Interlocks Service Water System Deleted Deleted Diesel Fuel Supply Deleted Main Steam Line Trip Valves TABLE 4.1 -2A MINIMUM FREQUENCY FOR EQUIPMENT TESTS FSAR SECTION TEST FREQUENCY REFERENCE Rod drop times of all full Prior to reactor criticality:

7 length rods at hot conditions

a. For all rods following each removal of the reactor vessel head

b. For specially affected individual rods following any maintenance on or modification to the control rod drive system whch could affect the drop time of those specific rods, and

c. Once per 18 months Partial movement of all rods Quarterly Functional Once per 18 months Setpoint Setpoint

Functional

Functional

Functional

Fuel Inventory Functional (Full Closure)

Per the Inservice Testing Program Per the Inservice Testing Program Once per 18 months Prior to refueling Once per 18 months Before each startup (TS 4.7)

The provisions of Specification 4.0.4.

are not applicable

TABLE 4.1 -2A(CONTNUED)

DESCRIPTION

19. Primary Coolant System MINIMUM FREQUENCY FOR EQUIPMENT TESTS TEST Functional

20. Containment Purge Functional MOV Leakage

21. Deleted

22. RCS Flow Flow 2 273,000 gpm UFSAR SECTION FREQUENCY REFERENCE

1. Periodc leakage testing(a)(b) on each valve listed in Specification 3.1.C.5.a shall be accomplished prior to entering POWER I

OPERATION after every time the plant is placed in COLD SHUTDOWN for reheling, after each time the plant is placed in COLD SHUTDOWN for 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months if testing has not been accomplished in the preceding 9 months, and prior to returning the valve to service after maintenance, repair or replacement work is performed.

Semi-Annual (Unit at power or shutdown) if purge valves are operated during interval(c)

Once per 18 months

23. Deleted (a) To satisfy ALARA requirements, leakage may be measured indirectly (as from the performance of pressure indicators) if accomplished in accordance with approved procedures and supported by computations showing that the method is capable of demonstrating valve compliance with the leakage criteria.

(b) Minimum differential test pressure shall not be below 150 psid.

(c) Refer to Section 4.4 for acceptance criteria.

See Specification 4.1.D.

3 a

B 0

R

4.13 RCS OPERATIONAL LEAKAGE Applicability The following specifications are applicable to RCS operational LEAKAGE whenever Tmg (average RCS temperature) exceeds 200°F (200 degrees Fahrenheit).

Objective To verify that RCS operational LEAKAGE is maintained within the allowable limits.

Specifications A.

Verify RCS operational LEAKAGE is within the limits specified in TS 3.1.C by performance of RCS water inventory balance once every 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months . '>

B.

Verify primary to secondary LEAKAGE is 5 150 gallons per day through any one SG once every 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months .'

Notes:

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

2.

Not applicable to primary to secondary LEAKAGE.

BASES SURVEILLANCE REQUIREMENTS (SR)

SR4.13.A Verifying RCS LEAKAGE to be within the Limiting Condition for Operation (LCO) limits ensures the integrity of the reactor coolant pressure boundary (RCPB) is maintained. Pressure boundary LEAKAGE would at first appear as unidentified LEAKAGE and can only be positively identified by inspection. It should be noted that LEAKAGE past seals and gaskets is not pressure boundary LEAKAGE. Unidentified LEAKAGE and identified LEAKAGE are determined by performance of an RCS water inventory balance.

The RCS water inventory balance must be performed with the reactor at steady state operating conditions (stable pressure, temperature, power level, pressurizer and makeup tank levels, makeup and letdown, and RCP seal injection and return flows). The surveillance is modified by two notes.

Note 1 states that this SR is not required to be completed until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after establishing steady state operation. The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months allowance provides sufficient time to collect and process all necessary data after stable unit conditions are established.

Amendment Nos.

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

An early warning of pressure boundary LEAKAGE or unidentified LEAKAGE is provided by the automatic systems that monitor the containment atmosphere radioactivity and the containment sump level. It should be noted that LEAKAGE past seals and gaskets is not pressure boundary LEAKAGE. These leakage detection systems are specified in the TS 3.1.C Bases.

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

The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months frequency is a reasonable interval to trend LEAKAGE and recognizes the importance of early leakage detection in the prevention of accidents.

SR 4.l3.B 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 LC0 3.1.H, "Steam Generator Tube Integrity," should be evaluated.

The 150 gallons per day limit is measured at room temperature as described in Reference 4. The operational LEAKAGE rate limit applies to LEAKAGE through any one SG.

If it is not practical to assign the LEAKAGE to an individual SG, all the primary to secondary LEAKAGE should be conservatively assumed to be from one SG. The surveillance is modified by a Note, which states that the Surveillance is not required to be performed until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after establishment of steady state operation. For RCS primary to secondary LEAKAGE determination, steady state is defined as stable RCS pressure, temperature, power level, pressurizer and makeup tank levels, 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 EPRl guidelines (Ref. 4).

REFERENCES

1. UFSAR, Chapter 4, Surry Units 1 and 2.

2.

UFSAR, Chapter 14, Surry Units 1 and 2.

3.

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

4.

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

Amendment Nos.

4.19 STEAM GENERATOR (SG) TUBE INTEGRITY Applicability Applies to the verification of SG tube integrity in accordance with the Steam Generator Program.

Objective To provide assurance of SG tube integrity.

Specifications A.

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

B.

Verify that each inspected SG tube that satisfies the tube repair criteria is plugged in accordance with the Steam Generator Program prior to Tavg exceeding 200°F following a SG tube inspection.

BASES SURVEILLANCE REQUIREMENTS (SR)

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

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

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

Amendment Nos.

The Steam Generator Program defines the frequency of SR 4.19.A. The frequency is determined by the operational assessment and other limits in the SG examination guidelines (Ref. 7). 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 6.4.4 contains prescriptive requirements concerning inspection intervals to provide added assurance that the SG performance criteria will be met between scheduled inspections.

During an SG inspection, any inspected tube that satisfies the Steam Generator Program repair criteria is removed from service by plugging. The tube repair criteria delineated in Specification 6.4.Q 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 and Reference 7 provide 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 Tavg exceeding 200°F following a SG inspection ensures that the Surveillance has been completed and all tubes meeting the repair criteria are plugged prior to subjecting the SG tubes to significant primary to secondary pressure differential.

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

10 CFR 50 Appendix A, GDC 19.

10 CFR 50.67.

Regulatory Guide 1.183, "Alternative Radiological Source Terms for Evaluating Design Basis Accidents at Nuclear Power Reactors," July 2000.

ASME Boiler and Pressure Vessel Code, Section 111, Subsection NB.

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

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

Amendment Nos.

Q. Steam Generator (SG) Program 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:

1. 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.

2. 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.

a. 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.

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

Leakage is not to exceed 1 gpm for all SG.

Amendment Nos.

c. The operational LEAKAGE performance criterion is specified in TS 3.1.C and 4.13, "RCS Operational LEAKAGE."

3. 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.

4. 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 4.a, 4.b, and 4.c 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.

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

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

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

5. Provisions for monitoring operational primary to secondary LEAKAGE.

Amendment Nos.

b. The results of specific activity analysis in which the primary coolant exceeded the limits of Specification 3.1.D.4. In addition, the information itemized in Specification 3. I.D.4 shall be included in this report.

3. Steam Generator Tube Inspection Report A report shall be submitted within 180 days after TaVg exceeds 200°F following completion of an inspection performed in accordance with the Specification 6.4.4, Steam Generator (SG) Program. The report shall include:

a. The scope of inspections performed on each SG,

b. Active degradation mechanisms found,

c. Nondestructive examination techniques utilized for each degradation mechanism,

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

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

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

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

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

Amendment Nos.

v t e Letter Sequence Response to RAI
TAC:MD0090, Steam Generator Tube Integrity (Open)
Initiation Request Acceptance... Administration Questions Answers 19 January 2007 Results Approval... Other: ML071580114
MONTHYEAR2007-01-19 [Table View]

ML070190655

Text

1.0 INTRODUCTION

2.0 DESCRIPTION

3.0 BACKGROUND

5.0 TECHNICAL ANALYSIS

6.0 REGULATORY ANALYSIS

10.0 REFERENCES

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