Text

Response to Request for Additional Information - Application for Technical Specification Improvement Regarding Steam Generator Tube Integrity
	ML063530484
Person / Time
Site:	Turkey Point
Issue date:	12/05/2006
From:	Jones T; Florida Power & Light Co
To:	; Document Control Desk, Office of Nuclear Reactor Regulation
References
	L-2006-229
	Download: ML063530484 (72)
	v • d • e

L-2006-229 10 CFR 50.90 Page 1 of 3 FPL DEC 0 5 2006 U.S. Nuclear Regulatory Commission Attn: Document Control Desk Washington, D. C. 20555 Re:

Turkey Point Units 3 and 4 Docket Nos. 50-250 and 50-251 Response to Request for Additional Information -

Application for Technical Specification Improvement Regarding Steam Generator Tube Integrity

References:

1. FPL letter L-2006-074, Application for Technical Specification Improvement Regarding Steam Generator Tube Integrity, April 27, 2006.

2. NRC letter to FPL, Turkey Point Nuclear Plant, Units 3 and 4-Request for Additional Information Regarding Scope of Steam Generator Tube Integrity Technical Specification Amendment Request (TAC Nos. MD1389 and MD1390), August 31, 2006.

3. FPL letter L-2006-092, License Amendment Request for Steam Generator Alternate Repair Criteria for Tube Portion within the Tubesheet, April 27, 2006.

4. FPL letter L-2006-228, Revision to License Amendment Request for Steam Generator Alternate Repair Criteria for Tube Portion within the Tubesheet, October 3, 2006.

5. NRC letter to FPL, Turkey Point Nuclear Plant, Units 3 and 4 - Issuance of Amendments Regarding Steam Generator Alternate Repair Criteria, November 1, 2006.

By letter L-2006-074, dated April 27, 2006, (Reference 1) Florida Power and Light Company (FPL) requested to amend Facility Operating Licenses DPR-31 and DPR-41 for Turkey Point Units 3 and 4. The proposed amendments revise the Technical Specification (TS) requirements related to 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."

In Reference 2, the NRC Staff issued a request for additional information (RAI) regarding the amendment request. Enclosure 1 provides FPL's response to the requested information. Based on conversations with the Staff, the response due date specified in Reference 2 was extended to allow sufficient time to address additional questions identified by the Staff on October 18, 2006.

an FPL Group company

L-2006-229 10 CFR 50.90 Page 2 of 3 provides the revised proposed marked-up TS pages incorporating several changes as discussed below. By letter L-2006-092, dated April 27, 2006, (Reference 3) as revised by letter L-2006-228, dated October 3, 2006, (Reference 4), FPL submitted proposed amendments to revise TS 3/4.4.5, Steam Generator Surveillance Requirements to exclude the region of the steam generator tubes below 17 inches from the top of the hot leg tubesheet from the inspection requirements. On November 1, 2006, the NRC issued amendments 231 and 226 (Reference 5) approving the requested changes to TS 3/4.4.5, Steam Generator Surveillance Requirements.

Amendments 231 and 226 revised TS 4.4.5.4, Acceptance Criteria, Item 6) Plugging Limit, and Item 8) Tube Inspection. The proposed marked-up TS pages provided in Enclosure 2 to this letter have been updated to reflect the TS changes approved by amendments 231 and 226.

Additionally, the changes to Acceptance Criteria, Items 6 and 8 approved by the NRC per amendments 231 and 226 affect the new Steam Generator (SG) Program TS Section 6.8.4.j proposed by FPL letter L-2006-074. The conforming changes to TS Section 6.8.4.j are incorporated into the proposed marked-up TS pages provided in Enclosure 2 to this letter.

References 3 and 4 also included a proposed revision to TS 3.4.6.2.c. consistent with the proposed change submitted by FPL letter L-2006-074; therefore eliminating the need to request a change to TS 3.4.6.2.c. under this amendment request. The proposed marked-up TS pages provided in Enclosure 2 to this letter have been updated to reflect the change to TS 3.4.6.2.c.

approved by the NRC per amendments 231 and 226.

In addition, Enclosure 2, Proposed Marked-up TS Pages, incorporates the following editorial changes as discussed in the response to RAI questions 1, 2, 9 and 10:

1. The statement "per Surveillance Requirement 4.4.6.2.1.c." has been removed from TS Table 3.3-4, Action 26-3 and from TS 3.4.6.1, Action a.3.

2. The new SR 4.4.6.2.1.e is corrected to be consistent with SR 3.4.13.2 in TSTF-449, Rev.

4 which establishes this primary-to-secondary leakage limit as "<150 gallons per day through any one SG."

3. The statement "or repaired" has been removed from 6.8.4.j.c.

4. "Degradation" has been changed to "flaws" in 6.8.4.j.c.1 and 6.8.4.j.c.2.

For consistency, Enclosure 2 to this letter replaces Enclosure 2, Proposed Marked-up TS Pages, of FPL letter L-2006-074. The above changes to the proposed amendments request submitted by FPL letter L-2006-074 are editorial in nature and therefore, do not alter the significant hazards consideration or the environmental assessment previously submitted. to this letter provides the proposed revised TS pages reflecting the changes discussed above. For consistency, Enclosure 3 to this letter replaces Enclosure 3, Proposed Revised TS Pages, of FPL letter L-2006-074. to this letter provides the existing TS Bases pages marked-up to show the revised proposed changes as discussed in the Response to Request for Additional Information, questions 4, 5, 6, 7, 12, and 13 (Enclosure 1 to this letter). For consistency, Enclosure 4 to this letter

L-2006-229 10 CFR 50.90 Page 3 of 3 replaces Enclosure 4, Proposed TS Bases Pages, of FPL letter L-2006-074. The marked-up TS Bases pages are provided for information only.

Please contact Mr. James Connolly, Licensing Manager at 305-246-6632 if there are any questions about this submittal.

Very truly yo(s Terry 0. o s

g!'

Vice Presi dent Turkey Point Nuclear Plant ENCLOSURES

1. Response to NRC Request for Additional Information

2. Proposed Technical Specification Changes (Mark up)

3. Proposed Technical Specification Pages

4. Proposed Technical Specification Bases Pages (Mark up for information only) cc:

Regional Administrator, Region II, USNRC USNRC Project Manager, Turkey Point Senior Resident Inspector, USNRC, Turkey Point W. A. Passetti, Florida Department of Health

ENCLOSURE 1 RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION to L-2006-229 Page 1 of 6 RESPONSE TO NRC REQUEST FOR ADDITIONAL INFORMATION By letter dated April 27, 2006, Florida Power & Light Company (FPL) requested an amendment to the Turkey Point Unit 3 and 4 Technical Specifications (TSs) regarding steam generator (SG) tube integrity, based on TS Task Force traveler TSTF-449.

The U.S. Nuclear Regulatory Commission (NRC) staff has reviewed this request and finds that the following additional information is needed to complete the review.

1.

On pages 6 and 15 of Enclosure 2, the proposed revisions to TS Table 3.3-4, Action 26-3, and TS 3.4.6.1, Action a.3, add the statement "per Surveillance Requirement 4.4.6.2.1.c." The purpose of adding this statement is not clear since Surveillance Requirement (SR) 4.4.6.2.1.c has no additional details. In addition, the proposed revisions to these action statements require the Reactor Coolant System (RCS) water inventory balance to be performed at least once per 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months , which appears to conflict with the 24-hour requirement in the current SR 4.4.6.2.1.c and the proposed 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months in the current application. Please explain the purpose of adding this statement or discuss your plans to remove it.

FPL agrees with the Staff's comment and the statement "per Surveillance Requirement 4.4.6.2.1.c." has been removed from TS Table 3.3-4, Action 26-3 and from TS 3.4.6.1, Action a.3, in response to this RAI. The current NRC approved design and licensing basis at Turkey Point Units 3 and 4 requires the 8 hour9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months frequency for these action statements with both the Particulate and Gaseous Radioactivity Monitoring Systems inoperable.

2.

On page 17 of Enclosure 2, the proposed revision to SR 4.4.6.2.1.c changes the frequency of performing the RCS water inventory balance from 24 to 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months .

Even though TSTF-449 states a frequency of 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months , this change must be justified on a plant-specific basis. Please provide a technical justification for why this change is acceptable for Turkey Point or modify your proposed TS to be consistent with your current TS with respect to this issue.

The technical justification for this change was provided on page 7 of Enclosure 1 (under 9.0 PRECEDENT item 2) in our submittal dated April 27, 2006 (L-2006-074). This change is appropriate because a 72-hour frequency is a reasonable interval to trend leakage and to provide an early indication of gradual RCS deterioration. The 72-hour frequency also provides conformance with the primary-to-secondary monitoring and trending frequency of the changes herein for Turkey Point SR 4.4.6.2.1.e and TSTF-449, Rev. 4, IST SR 3.4.13.2. Furthermore, the water inventory balance verification is not used for the prompt identification of rapid changes in RCS leakage rates. Other methods are available to the operators to provide prompt indication of any significant increases in RCS leakage, including the RCS leakage detection instrumentation required by Turkey Point Units 3 and 4 TS LCO 3.3.3.1 (Radiation Monitoring) and LCO 3.4.6.1 (Leakage Detection Systems). Please refer to the April 27, 2006 submittal for further details.

to L-2006-229 Page 2 of 6 Additionally, on page 17 of Enclosure 2, it was noted that new SR 4.4.6.2.1.e, as proposed in our submittal dated April 27, 2006 (L-2006-074), incorrectly limits primary-to-secondary leakage to "<150 gallons per day through any one SG." SR 3.4.13.2 in TSTF-449, Rev. 4 establishes this limit as "<150 gallons per day through any one SG."

Accordingly, the revised Enclosure 2 corrects the leakage limit for this SR.

3.

The current Bases for TS 3/4.4.4.6.2 (as shown on page 4 of Enclosure 4) states that the dosage contribution from the tube leakage will be limited to a small fraction of 10 CFR Part 100 dose guideline values. However, on page 7 and 12 of Enclosure 4, the proposed Bases state that the dose consequences are within the limits of 10 CFR Part 100 as well as 10 CFR Part 50.67. Please clarify whether the current NRC approved accident source term is based on Part 100 (which is referenced in the current TS Bases), Part 50.67 or both?

The accident analyses for Turkey Point Units 3 and 4 include Part 50.67 for the fuel handling accident, and Part 100 for the remainder of the accident analyses. Therefore, the current NRC approved accident source term is based on both Part 100 and Part 50.67.

4.

It is the staff's understanding that the accident analysis for Turkey Point assumes that accident induced leakage does not exceed 500 gpd in any one of the three SGs and the total leakage from all SGs does not exceed 1 gpm at accident conditions.

There are five instances (pages 7, 8, 12, 13, and 18 of Enclosure 4) where the accident induced leakage assumption is cited in the Bases. The accident analysis assumptions discussed on these pages vary and in some cases could be potentially misinterpreted. Please confirm the staff's understanding of your accident analysis assumptions concerning primary-to-secondary leakage and discuss your plans to modify the proposed Bases to more clearly define your accident analysis leakage assumptions. In addition, on page 13 of Enclosure 4, there is a statement that the 500 gpd primary-to-secondary leakage in each SG at accident conditions is relatively inconsequential. This statement appears to contradict the previous paragraph and other portions of your submittal. Please clarify.

The Staff's understanding is correct that the accident analysis requires both conditions to be met (i.e., 1 gpm total through all SGs and 500 gallons per day through any one SG at accident conditions). The primary-to-secondary leakage safety analysis assumption for individual events varies. The assumption varies depending on whether the primary-to-secondary leakage from a single SG can adversely affect the dose consequences for the event. In which case, the affected SG is assumed to have the maximum allowable leakage (500 gallons per day). For example, the SGTR accident analysis assumes primary-to-secondary leakage is 500 gallons per day through each of the two intact SGs at accident conditions. While the affected (ruptured) SG in the SGTR event assumes the primary-to-secondary leakage rate associated with a double-ended rupture of a single tube. For the SLB event, the accident analysis assumes a maximum primary-to-secondary leakage of 500 gallons per day at accident conditions through the affected SG and also conservatively assumes this leakage through each of the two intact SGs. The locked rotor event is limiting for site radiation dose releases and assumes a total primary-to-secondary to L-2006-229 Page 3 of 6 leakage from all SGs of 1 gpm at accident conditions. Similarly, only the total primary-to-secondary leakage is important for the RCCA ejection event and a total primary-to-secondary leakage from all SGs of 1 gpm at accident conditions is assumed.

Minor changes were made to the wording for the instances on page 7, 8, and 12 of to make these descriptions uniform and consistent with the current NRC approved design and licensing basis. The wording in the first paragraph on page 13 of specifically discusses SGTR and minor changes were made to be consistent with the current NRC approved design and licensing basis and to clarify that the dose consequence contribution from primary-to-secondary leakage from the two intact SGs is inconsequential compared to the dose consequence from leakage from the double-ended rupture of a single tube in the affected SG. The wording on page 18 of Enclosure 4 also discusses SGTR and was modified to be consistent with the current NRC approved design and licensing basis.

5.

On page 8 of Enclosure 4, the last sentence of the third paragraph states that the accident induced leakage rate assumption conservatively bounds the expected total accident primary-to-secondary leakage based on the allowable operational leakage rate as an initial condition and considers any leakage changes as a result of the accident induced changes in primary-to-secondary pressure differential. This statement appears to imply that, by satisfying the operating leakage limit, the accident induced leakage limit would never be exceeded. Since operating experience indicates that this is not the case, please discuss your plans to remove or modify this statement. In addition, discuss your plans to include the definition of accident induced leakage into the Bases. The definition is in TSTF-449 (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 intent of the proposed wording in this paragraph in the Limiting Condition of Operation (LCO) Section of proposed B3/4.4.5 is to maintain consistency with TSTF-449, and add additional information to provide an engineering justification for the conclusion that the limit on operational leakage contained in LCO 3.4.6.2 is significantly less than the conditions assumed in the accident analyses and that the accident analysis assumption includes any primary-to-secondary leakage induced during the accident. The comparable paragraph in TSTF-449 is applicable to the current NRC approved design and licensing basis for Turkey Point Units 3 and 4. Therefore, the proposed paragraph in B3/4.4.5 is modified to be consistent with TSTF-449 to simplify this submittal and to eliminate potential misinterpretation. In addition, the TSTF-449 definition of accident induced leakage was added to this paragraph. Also, a revision to the proposed text in an earlier paragraph in B3/4.4.5 is revised for consistency.

6.

On pages 14 and 17 of Enclosure 4, there appear to be two typographical errors.

The first is under the paragraph for "IDENTIFIED LEAKAGE" towards the end of the first sentence. The sentence reads: ".... and is well with in the capability...1' The sentence should read: "1... and is well within the capability..." The second one

Enclosure I to L-2006-229 Page 4 of 6 is under the list of "References." Reference 6 should be 10 CFR 50.67 instead of 10 CFR 50.76.

FPL agrees with the Staff's comment and "with in" has been replaced with "within". In addition, "10 CFR 50.76" has been changed to "10 CFR 50.67".

7.

On page 17 of Enclosure 4, you stated that the 150-gpd limit is measured at room temperature as described in Reference 1. Please confirm that this is the correct reference. In addition, discuss your plans to cite reference 5 at this location since reference 5 also discusses this issue.

The references have been modified to only cite Reference 5 (the correct reference) in response to this RAI.

8.

There are several proposed changes to the Bases for the Reactor Coolant System leakage section that go beyond TSTF-449. Please confirm that all of the proposed changes are consistent with your current design and licensing bases. If they are not consistent, please provide a technical justification for the differences or discuss your plans to remove them.

TSTF-449 uses the standard technical specifications (NUREG-1431) as a starting bases document and details a number of changes to Bases Section B3.4.13, "RCS Operational LEAKAGE." In our April 27, 2006 submittal, FPL adopted NUREG-1431 as the starting bases document and modified it to incorporate both the changes introduced by TSTF-449 and those changes necessary to maintain consistency with the current NRC approved design and licensing basis for Turkey Point Units 3 and 4. The proposed bases changes that go beyond TSTF-449 are discussed below. A few changes that are in addition to those proposed in our April 27, 2006 submittal are also discussed below.

a. In our April 27, 2006 submittal, the third paragraph in the Background section of NUREG-1431 B3.4.13 (i.e., beginning with "10CFR50, Appendix, A, GDC 30 (Ref.1)...") was modified. Upon further review, this paragraph in NUREG 1431 is appropriate and replaces the proposed paragraph. A conforming change was made to replace Reference 1 with "10 CFR 50, Appendix A, GDC 30."

b. In our April 27, 2006 submittal the discussion in the Applicable Safety Analyses section of NUREG-1431 B3.4.13 was modified for Turkey Point Units 3 and 4 proposed bases section B3/4.4.6.2 to be consistent with the current NRC approved design and licensing basis for Turkey Point Units 3 and 4. The changes eliminated inconsistencies with current NRC approved design and licensing basis for Turkey Point Units 3 and 4, including an inconsistency regarding the steam line break (SLB) accident being considered more limiting than other accidents. The applicable points from the discussion in the Applicable Safety Analyses section of NUREG-1431 B3.4.13 were retained and summarized in the first paragraph of the Applicable Safety Analyses section of B3/4.4.6.2 for Turkey Point Units 3 and 4. Nonetheless, to more closely align the Turkey Point Units 3 and 4 bases section B3/4.4.6.2 to NUREG-1431 B3.4.13 the proposed bases text is modified to recognize that accidents for to L-2006-229 Page 5 of 6 which the radiation dose release path is primary-to-secondary leakage, the locked rotor accident is the limiting accident for site radiation dose release consistent with the current NRC approved design and licensing basis for Turkey Point Units 3 and 4.

c. In our April 27, 2006 submittal, the first paragraph of NUREG-1431 Bases SR 3.4.13.1 is used as the first paragraph for Turkey Point Units 3 and 4 Bases SR 4.4.6.2.1 and is consistent with the current NRC approved design and licensing basis.

d. In our April 27, 2006 submittal, the second, third, fourth and fifth paragraphs in NUREG-1431 Bases SR 3.4.13.1 are added as item c under Turkey Point Units 3 and 4 Bases SR 4.4.6.2.1 to provide an understanding of the surveillance requirements consistent with the current NRC approved design and licensing basis.

e. In our April 27, 2006 submittal, items a, b, and d under Turkey Point Units 3 and 4 Bases SR 4.4.6.2.1 were added to address monitoring of the containment atmosphere radioactivity levels, containment sump, and reactor head flange leak-off consistent with the current NRC approved Turkey Point Units 3 and 4 design and licensing basis.

f. In our April 27, 2006 submittal, item e under Limiting Condition for Operation is added to provide an understanding of the LCO for RCS Pressure Isolation Valve Leakage consistent with the current NRC approved Turkey Point Units 3 and 4 design and licensing basis.

g. In our April 27, 2006 submittal, items c and d are added under ACTIONS to provide an understanding of the required actions for RCS Pressure Isolation Valve Leakage consistent with the current NRC approved Turkey Point Units 3 and 4 design and licensing basis.

h. In our April 27, 2006 submittal, SR 4.4.6.2.2 is added to provide an understanding of the existing surveillance requirement for pressure isolation valves consistent with the current NRC approved Turkey Point Units 3 and 4 design and licensing basis.

The following provides FPL's response to the additional questions communicated by the Staff on October 18, 2006.

9.

"or repaired" should be removed from 6.8.4.j.c since there are no approved repair methods for Turkey Point.

FPL agrees to make the requested change to 6.8.4.j.c.

10.

"Degradation" should be changed to "flaws" in 6.8.4.j.c.1 and 6.8.4.j.c.2 since "flaws" is used in the new technical specification whereas degradation was used in the current technical specifications.

FPL agrees to make the requested changes to 6.8.4.j.c. 1 and 6.8.4.j.c.2.

11.

The added sentence in 6.8.4.j.d regarding the length of inspection is not needed since only need to inspect to identify flaws that exceed the repair criteria. There are no to L-2006-229 Page 6 of 6 repair criteria in the lower part of the tubesheet (assuming the H*/B* amendment is approved).

The Staff recently asked FPL to incorporate conforming changes per the LAR requesting a one-time change for alternate repair criteria for the portion of the SG tubes within the tubesheet (FPL Letter L-2006-228). The Staff also suggested that the conforming changes for this one-time change should be worded similar to those recently approved for Vogtle Units 1 and 2. The added sentence as proposed in 6.8.4.j.d is consistent with wording approved by the Staff on September 12, 2006 in Amendments 146 and 126 for Vogtle Units 1 and 2 respectively for a similar one-time change.

Further, if the added sentence in 6.8.4.j.d is removed, the requirements of the sentences that precede it could be misinterpreted to require that the portion of tubing that is more than 17" below the top of the hot leg tubesheet must be inspected.

12..

On page 7 of 18, the phrase, ", which is conservative and includes any increase as a result of accident induced conditions." should be removed. This statement implies that meeting the operational leakage limit will ensure the accident limit is met. This is not supported by evaluation of operating experience data.

FPL agrees to make the requested change. In addition, to be consistent with TSTF-449, FPL proposes to replace this wording with ", or is assumed to increase to these levels as a result of accident induced conditions."

13.

On page 12 of 18, the 3rd sentence under "Applicable Safety Analyses" should have the following text added to make it consistent with TSTF 449: "or is assumed to increase to these levels as a result of accident induced conditions."

FPL agrees with the requested change. However, the 3rd sentence only discusses one of two leakage limits (i.e., 500 gallons per day), whereas the 4th sentence discusses both leakage limits. Therefore, FPL proposes that similar words, which are more consistent with TSTF-449 Insert B 3.4.13.A, be added to the 4th sentence as shown in bold underlined type below.

"The primary-to-secondary leakage safety analysis assumption for individual events varies. The assumption varies depending on whether the primary-to-secondary leakage from a single steam generator (SG) can adversely affect the dose consequences for the event. In which case, the affected SG is assumed to have the maximum allowable leakage (500 gallons per day). Collectively, however, the safety analyses for events resulting in steam discharge to the atmosphere assume that primary-to-secondary leakage from all steam generators (SGs) is 1 gpm total and 500 gallons per day through any one SG at accident conditions, or increases to these levels as a result of accident induced conditions. The LCO requirement to limit primary-to-secondary leakage through any one SG to less than or equal to 150 gpd at room temperature is significantly less than the conditions assumed in the safety analysis."

L-2006-229, TS Mark up and Inserts Page 1 of 23 ENCLOSURE 2 Technical Specification Mark Up and Inserts

L-2006-229, TS Mark up and Inserts INDEX Page 2 of 23 LIMITING CONDITIONS FOR OPERATION AND SURVEILLANCE REQUIREMENTS SECTION PAGE 3/4.4 REACTOR COOLANT SYSTEM ESG TUBE INTEGRITY]

3/4.4.1 REACTOR COOLANT LOOPS AND COOLANT CIRCULATION Startup and Power Operation..................................

3/4 4-1 Hot Standby................................................

3/4 4-2 H ot S hutdow n...

3/4 4-3 Cold Shutdown - Loops Filled.......

3/4 4-5 Cold Shutdown - Loops Not Filled....................

3/4 4-6 3/4.4.2 SAFETY VALVES Shutdow n........

3/4 4-7 Operating..................................................

3/4 4-8 3/4.4.3 PRESSU R IZER 3/4 4-9 3/4.4.4 RELIEF VALVES-ý 3/44-10 3/4.4.5 STEAM GENERATORI

....................................... 3/44-11 TA 4.4-1 MINIMU UMBER OF STE GENERATORS T EINSPECTED".-.,,,1 DURING IN VICE INSPECTIO.

/44-16 TABLE 4.4-2 STEAM GENERA'r* TUBE INSPECT 3/4 7

3/4.4.6 REACTOR COOLANT SYSTEM LEAKAGE Leakage D etection System s..........................................................................

3/4 4-18 O perational Leakage.....................................................................................

3/4 4-19 TABLE 3.4-1 REACTOR COOLANT SYSTEM PRESSURE ISOLATION VALVES............

3/4 4-22 3/4.4.7 C H E M IS T R Y.................................................................................................

3/4 4-23 TABLE 3.4-2 REACTOR COOLANT SYSTEM CHEMISTRY LIMITS.................................

3/4 4-24 TABLE 4.4-3 REACTOR COOLANT SYSTEM CHEMISTRY LIMITS SURVEILLANCE R E Q U IR E M E N TS........................................................................................

3/4 4-25 3/4.4.8 S PEC IFIC A C TIV ITY....................................................................................

3/4 4-26 FIGURE 3.4-1 DOSE EQUIVALENT 1-131 REACTOR COOLANT SPECIFIC ACTIVITY LIMIT VERSUS PERCENT OF RATED THERMAL POWER WITH THE REACTOR COOLANT SPECIFIC ACTIVITY > lgCi/gram DO SE EQ U IVA LENT 1-131...........................................................................

3/4 4-27 TABLE 4.4-4 REACTOR COOLANT SPECIFIC ACTIVITY SAMPLE AND ANALYSIS P R O G R A M.................................................................................................

3/4 4-2 8 TURKEY POINT - UNITS 3 & 4 vii AMENDMENT NOSD132

L-2006-229, TS Mark up and Inserts Page 3 of 23 INDEX ADMINISTRATIVE CONTROLS SECTION PAGE 6.6 DELETED..........................................................................................................................

6-12 6.7 DELETED..........................................................................................................................

6-12 6.8 PROCEDURES AND PROGRAMS...................................................................................

6-13 6,9 REPORTING REQUIREM ENTS........................................................................................

6-18 6,9.1 ROUTINE REPORTS....................................................................................................

6-18 Startup Report.........................................................................................................

6-18 Annual Reports........................................................................................................

6-19 Annual Radiological Environmental Operating Report............................................

6-20 Annual Radioactive Effl uent Release Report..........................................................

6-20 Peaking Factor Limit Report....................................................................................

6-21 Core Operating Lim its Report..................................................................................

6-21 6.9.2 SPECIAL REPORTS.....

6-22 6.10 DELETED....................... \\.............................................................................

6-23 Isteam Generator Tube Inspection Report 6-22 TURKEY POINT-UNITS 3 & 4 xvi AMENDMENT NO3 ANEII

L-2006-229, TS Mark up and Inserts Page 4 of 23 DEFINITIONS FREQUENCY NOTATION DOSE EQUIVALENT 1-131 1.12 DOSE EQUIVALENT 1-131 shall be that concentration of 1-131 (microCurie/gram) which alone would produce the same thyroid dose as the quantity and isotopic mixture of 1-131, 1-132, 1-133,1-134, and 1-135 actually present. The thyroid dose conversion factors used for this calculation shall be those listed in Table III of TID-14844, "Calculation of Distance Factors for Power and Test Reactor Sites" or Table E-7 of NRC Regulatory Guide 1.109, Revision 1, October 1977.

E-AVERAGE DISINTEGRATION ENERGY 2-'

1.13 E shall be the average (weighted in proportion to the concentration of each radionuclide in the reactor coolant at the time of sampling) of the sum of the average beta and gamma energies per disintegration (MeV/d) for the radionuclides in the sample isotopes, other than iodines, with half lives greater than 30 minutes, making up at least 95 percent of the total non-iodine activity in the coolant.

1.14 The FREQUENCY NOTATION specified for the performance of Surveillance Requirements shall correspond to the intervals defined in Table 1.1.

GAS DECAY TANK SYSTEM 1.15 A GAS DECAY TANK SYSTEM shall be any system designed and installed to reduce radioactive gaseous effluents by collecting Reactor Coolant System off gases from the Reactor Coolant System and providing for delay or holdup for the purpose of reducing the total radioactivity prior to release to the environment.

IDENTIFIED LEAKAGE 1.16 IDENTIFIED LEAKAGE shall be:

a.

Leakage (except CONTROLLED LEAKAGE) into closed systems, such as pump seal or valve packing leaks that are captured and conducted to a sump or collecting tank, or

b.

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

c.

Reactor Coolant System leakage through a steam generator to the Secondary Coolant SysteI I(pri mary-to-secondary leakage) I TURKEY POINT - UNITS 3 & 4 1-3 AMENDMENT

L-2006-229, TS Mark up and Inserts Page 5 of 23 DEFINITIONS OPERABLE - OPERABILITY 1.17 A system, subsystem, train, component or device shall be OPERABLE or have OPERABILITY when it is capable of performing its specified function(s), and when all necessary attendant instrumentation, controls, electrical power, cooling or seal water, lubrication or other auxiliary equipment that are required for the system, subsystem, train, component, or device to perform its function(s) are also capable of performing their related support function(s).

OPERATIONAL MODE - MODE 1.18 An OPERATIONAL MODE (i.e., MODE) shall correspond to any one inclusive combination of core reactivity condition, power level, and average reactor coolant temperature specified in Table 1.2.

PHYSICS TESTS 1.19 PHYSICS TESTS shall be those tests performed to measure the fundamental nuclear characteristics of the reactor core and related instrumentation: (1) described in Chapter 13.5 of the FSAR, (2) authorized under the provisions of 10 CFR 50.59, or (3) otherwise approved by the Commission.

PRESSURE BOUNDARY LEAKAGE lprima to-secondary I 1.20 PRESSURE BOUNDARY LEAKAGE shall be leakage (except steam generator tube leakage) through a nonisolable fault in a Reactor Coolant System component body, pipe wall, or vessel wall.

PURGE - PURGING 1.21 PURGE or PURGING shall be any controlled process of discharging air or gas from a confinement to maintain temperature, pressure, humidity, concentration or other operating condition, in such a manner that replacement air or gas is required to purify the confinement.

TURKEY POINT - UNITS 3 & 4 1-4 AMENDMENT

L-2006-229, TS Mark up and Inserts Page 6 of 23 TABLE 3.3-4 (Continued)

TABLE NOTATIONS During COREALTERATIONS or movement of irradiated fuel within the containment comply with Specification 3/4.9.13.

With irradiated fuel in the spent fuel pits.

Unit 4 Spent Fuel Pool Area is monitored by Plant Vent radioactivity instrumentation.

Note 1 Either the particulate or gaseous channel in the OPERABLE status will satisfy this LCO.

Note 2 Containment Gaseous Monitor Setpoint -

(3.2 x 10 4 ) CPM,

(

F)

Actual Purge Flow Where F =

(35,000 CFM)

Design Purge Flow (35,000 CFM)

Setpoint may vary according to current plant conditions provided that the release rate does not exceed allowable limits provided in the Offsite Dose Calculation Manual.

ACTION STATEMENTS ACTION 26 -

In MODES 1 thru 4: With both the Particulate and Gaseous Radioactivity Monitoring Systems inoperable, operation may continue for up to 7 days provided:

1)

A Containment sump level monitoring system is OPERABLE,

2)

Appropriate grab samples are obtained and analyzed at least once per 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months ,

3)

A ReactqLL n

t er inventory balance is performed at least once per 8 our stead state operation except when operating in shutdown cooling mode, F8-Iand

4)

Containment Purge, Exhaust and Instrument Air Bleed Valves are maintained closed.

Otherwise, be in at least HOT STANDBY within the next 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 (ACTION 27 applies in MODES 5 and 6).

TURKEY POINT - UNITS 3 & 4 3/4 3-37 AMENDMENT

L-2006-229, TS Mark up and Inserts Page 7 of 23 3/4.4.5 STEAM GENE:RATO SF_*

LIMITING CONDITION FOR OPERATION 3.4.5 *1ach steam generator shall be OPERABLE.,---

ACIN*APPLICABILITY:

MODES 1, 2, 3 and 4.

P/A With one or more steam generators inoperable, restore the inoperable generator(s) to OPEAL ttspirt inraing Ta,9 above 200°F.

SURVEILLANCE REQUIREMENTS 4.4.5.0 Each steam generator shall be demonstrated OPERABLE by performance of the following augmented inservice inspection program and the requirements of Specification 4.0.5.

4...Steam Generator Sample Selection and Inspection - Each steam generator shall be determined-"*____

SOPERABLE during shutdown by selecting and inspecting at least the minimum number of steam generators spcfed in Table 4.4-1.

5 Sea Generator Tube Sample Selection and Inspection - The steam generator tube minimum sample

/size, inspection result classification, and the corresponding action required shall be as specified in Table 4.4-2.

The inservice inspection of steam generator tubes shall be performed at the frequencies specified in ISpecification 4.4.5.3 and the inspected tubes shall be verified acceptable per the acceptance criteria of Specfictio 4..5..

Te tbesselcte fo eah isericeinspection salicuea es

%o h

oa number of tubes in all steam generators; the tubes selected for these inspections shall be selected on a random basis except:

a.

Where experience in similar plants with similar water chemistry indicates critical areas to be inspected, then at least 50% of the tubes inspected shall be from these critical areas;/

b.

The first sample of tubes selected for each inservice inspection (subsequent to the preservice/

IINSERT C [* inspection) oflihR each steam generator shall include:

5eparate Action entry is allowed for each 5G tube.

TURKEY POINT-UNITS 3 & 4 3/4 4-11 AMENDMENT NOS.(rAND'

L-2006-229, TS Mark up and Inserts Page 8 of 23 EACTOR COOLANT SYSTEM S

AM GENERATORS SURV LANCE RE UIREMENTS Continued)

1)

All nonplugged tubes that previously had detectable wall penetrations reaterthan 20%),

2 Tubes in those areas where experience has indicated potential pro ems, and

3)

A tube inspection (pursuant to Specification 4.4.5.4a.8) shall b performed on each elected tube. If any selected tube does not permit the pass e of the eddy current probe f

a tube inspection, this shall be recorded and an adjace tube shall be selected and su cted to a tube inspection.

c.

The tubes sele ed as the second and third samples in the i ervice inspection may be less than a full tube inspec tn by concentrating (selecting at least 5 /o of the tubes to be inspected) the inspection on those reas of the tube sheet array and on ose portions of the tubes where tubes with imperfections w previously found.

The results of each sample inspection sh be classified into one o he following three categories:

CateQory Inspection Results C-1 Less tha 5% oft total tubes inspected are degraded tubes and none of the insp ted bes are defective.

C-2 One or mor es, but not more than 1% of the total tubes inspected are defective, r be een 5% and 10% of the total tubes inspected are degrade 'ubes.

C-3 Mor han 10% ofthe tal tubes inspected are degraded tubes or more th 1% of the inspecte ubes are defective.

Note:

In all inspectio

, previously degraded tubes ust exhibit significant (greater than 10%)

further wall netrations to be included in the a ve percentage calculations.

THIS PAGE DELETED TURKEY POINT - UNITS 3 & 4 3/4 4-12 AMENDMENT NOS. &

NDQ

L-2006-229, TS Mark up and Inserts Page 9 of 23 REACTOR COOLANT SYSTEM TEAM GENERATORS SUR ILANCE REQUIREMENTS (Continued) 4.4.5.3 Ins ction Frequencies - The above required inservice inspections of steam generator besshall be performed at following frequencies:

a.

T first inservice inspection shall be performed after 6 Effective Full Po r Months but within 24 cale dar months following replacement of steam generators. Subsequ t inservice inspections shall Iperformed at intervals of not less than 12 nor more than 24 endar months after the previou inspection. If two consecutive inspections following servi under AVT conditions, not including t preservice inspection, result in all inspection results alling into the C-1 category or if two consec

ve inspections demonstrate that previously obse ed degradation has not continued and no additio I degradation has occurred, the inspection i rval may be extended to a maximum of onc per 40 months.

b.

If the results of the in ervice inspection of a steam ge rator conducted in accordance with Table 4.4-2 at 40-mon intervals fall in Category C-, the inspection frequency shall be increased to at least once per 20 m ths. The increase in i ection frequency shall apply until the subsequent inspections satfy the criteria of Sp ification 4.4.5.3a; the interval may then be extended to a maximum of o e per 40 mont and

c.

Additional, unscheduled inservice i specti s shall be performed on each steam generator in accordance with the first sample ins ec n specified in Table 4.4-2 during the shutdown subsequent to any of the following co itions:

1)

Primary-to-secondary tub leak ot including leaks originating from tube-to-tube sheet welds) in exces of the its of Spe *fication 3.4.6.2, or

2)

A seismic occurre greater than the erating Basis Earthquake, or

3)

A loss-of-cool accident resulting in rapid pressurization of the primary system, or

4)

A main ste line or feedwater line break resulti in rapid depressurization of the affected eamn generator.

THIS PAGE DELETED TURKEY POINT - UNITS 3 & 4 3/4 4-13 AMENDMENT NoSt ND E3

L-2006-229, TS Mark up and Inserts Page 10oaf 23 REACTOR COOLANT SYSTEM STEAM GENERATORS THIS PAGE DELETED ILLANCE REQUIREMENTS ('Continued) 4.4.5.4 Ac ance Criteria

a.

s used in this specification:

1)

Imperfection means an exception to the dimensions, finish or ntour of a tube from that required by fabrication drawings or specifications. Eddy-cu nt testing indications below

% of the nominal tube wall thickness, if detectable, ma e considered as im rfections;

2)

De ra tion means a service-induced cracking, w tage, wear or general corrosion occurring n either inside or outside of a tube;

3)

De raded Tu means a tube containing i erfections greater than or equal to 20% of the nominal wa hickness caused by degr ation;

4)

% Degradation me s the percentag of the tube wall thickness affected or removed by degradation;

5)

Defect means an imperfe n

such severity that it exceeds the plugging limit. A tube containing a defect is defecti

6)

Plugging Limit means th imper tion depth at or beyond which the tube shall be This text is removed from service cause it m become unserviceable rn th n i

n relocatedx t o the a

00 the nominal tul wall thickne*_

.For Unilt 3 during Refuelig relocated ta the Outage 23 and th ubsequent operatinkcycles until the next scheduled inspection, and proposed new 5G for Unit 4 dunn efueling Outage 23 and e subsequent operating cycles until the next Program as a scheduled ins ction, this criterion does not ply to degradation identified in the portion conforming change of the tube low 17 inches from the top of the ot leg tubesheet. Degradation found in the portio /'of.

the tube bl w1 in h sfrom the o

the hot leg tubsheet does not consistent with 1

requireuugging. For Unit 3 during Refueling Outa 23 and the subsequent operating license amendment cycle until the next scheduled inspection, and for Unt4 during Refueling Outage 23 and request L-2006-th ubsequent operating cycles until the next schedule inspection, all tubes with 228, and gradation identified in the portion of the tube within the Ngion from the top of the hot Amendments Nos.

eg tubesheet to 17 inches below the top of the tubesheet s II be removed from service; 231 and 226.

7 Unserviceable describes the condition of a tube if it leaks or co ins a defect large enough to affect its structural integrity in the event of an Operating asis Earthquake, a loss-of-coolant accident, or a steam line or feedwater line break as s.cified in 4.4.5.3c,

/

above;

8)

Tube Inspection means an inspection of the steam generator tube from the oint of entry (hot leg side) completely around the U-bend to the top support of the cold leg, r from the point of er~try ('cold leg side) completely around the U-bend and to the bottom of e hot le__gJ. IFor Unit 3 during Refueling Outage 23 and the subsequent otperating cycles *0til the1 next scheduled inspection, and for Unit 4 during Refueling Outage 23 and the l

subsequent operating cycles until the next scheduled inspection, the portion of the Xtub'j lbelow 17 inches from the top of the hot leg tubesheet is excludeSM and

,KEY POINT - UNITS 3 & 4 314 4-14 AMENDMENTS NOS.(ýýANDJ*

TUR

L-2006-229, TS Mark up and Inserts Page 11 of 23 REACTOR COOLANT SYSTEM EAM GENERATORS SURV LANCE REQUIREMENTS (Continued)

9)

Preservice Inspection means an inspection of the full length of each tu in each steam generator performed by eddy current techniques prior to service to es lish a baseline condition of the tubing.

b.

The s am generator shall be determined OPERABLE after completing e corresponding actions (plugya ubes exceeding the plugging limit and all tubes containing th ugh-wall cracks) required by Table 4-2.

4.4.5.5 Reports

a.

Within 15 days fo wing the completion of each inservice in ection of steam generator tubes, the number of tubes lugged in each steam generator sh be reported to the Commission in a Special Report pursu t to Specification 6.9.2;

b.

The complete results of t steam generator tube i ervice inspection shall be submitted to the Commission in a Special Re ort pursuant to Spe ication 6.9.2 within 12 months following the completion of the inspection.

is Special Rep shall include:

1)

Number and extent of tub inspec d,

2)

Location and percent of wall-t '

ness penetration for each indication of an imperfection, and

3)

Identification of tubes pl ged.

c.

Results of steam generator t e inspections whi fall into Category C-3 shall be reported to the Commission pursuant to 1 FR Part 50.72 and p r to resumption of plant operation. This report shall provide a de ription of investigations co ucted to determine cause of the tube degradation and corre ve measures taken to prevent currence.

THIS PAGE DELETED TURKEY POINT - UNITS 3 & 4 3/4 4-15 AMENDMENT NOS.ANDE

L-2006-229, TS Mark up and Inserts Page 12 of 23 TABLE 4.4-:1 MINIMUM NUMBER OF STEAM GENERATORS TO BE INSPECTED DURING INSERVICE INSPECTION Preservice Inspection No Yes No. of Steam Generators per Unit Three Thr irst Inservice Inspection All o

2 Sec nd & Subsequent Inservice Inspections Onel

/One2 Table Notation

1.

The inservice inspecti may be limited to one steam generator o rotating schedule encompassing 9%

of the tubes if the result f the first or previous inspections indic e that all steam generators are performing in a like mann

. Note that under some circumsta es, the operating conditions in one or more steam generators ma e found to be more severe tha those in other steam generators. Under such circumstances the samp sequence shall be modifie to inspect the most severe conditions.

2.

The other steam generator not ins cted during the fir inservice inspection shall be inspected. The third and subsequent inspections should flowtheinstruc' n described in 1 above.

THIS PAGE DELETED TURKEY POINT - UNITS 3 & 4 3/4 4-16 AMENDMENT NOS.

AND'

C:

ý0 0

z C

Cl) m z

z z0 49)

TABLE 4-2 STEAM GENERATOR TUBE INSPECTION

"'ýz 1st SAMPLE INSPECTION 2nd SAMPLE INSPECTION 3rd SAMP*INSPECTION

+

+ -,-

Zesult Action Required Result Action Required Result,

Action Required A minimum Of S Tubes Per S.G.

-H

-I C-A I

ni rn H

ni C7 None N/A N/A N

N/A lug defective tubes C-1 None N/A N/A an spect addi-tional tubes in C-1 None this S.G.

Plug d ctive tubes C-2 C-2 insct additional 4S tubes subes in this S.G.

Perform action C-3 for C-3 result of first sample Perform action for C-3 result of first N/A N/A sample Inspect all tubes All other None in this S.G. plug S.G.s are N/A N/A defective tube nd C-1 inspect 2S es in Some S.G.s each er S.G.

C-2 but no Perform acti for additional C-2 result of sec N/A N/A otification to NRC S.G.s are sample pursuant to Sec-C-3 tion 4.4.5.5c.

Additional Inspect all tubes in S.G. is each S.G. and plug C-3 defective tubes.

N N/A Notification to NRC pursuant to Section 4.4.5.5C.

-v CA) 0

-h "4

LA)

C0' 3

(A 90 S=-% Where n is the number of steam generators inspected during an inspection.

n

L-2006-229, TS Mark up and Inserts Page 14 of 23 3/4.4.5 INSERT A SG tube integrity shall be maintained AND All SG tubes satisfying the tube repair criteria shall be plugged in accordance with the SG Program.

3/4.4.5 INSERT B

a.

With one or more SG tubes satisfying the tube repair criteria and not plugged in accordance with the Steam Generator Program;

1.

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

2.

Plug the affected tube(s) in accordance with the Steam Generator Program prior to entering HOT SHUTDOWN following the next refueling outage or SG tube inspection.

b.

With the requirements and associated allowable outage time of Action a above not met or SG tube integrity not maintained, be in HOT STANDBY within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in COLD SHUTDOWN within the next 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months .

3/4.4.5 INSERT C Verify SG tube integrity in accordance with the Steam Generator Program.

3/4.4.5 INSERT D Verify that each inspected SG tube that satisfies the tube repair criteria is plugged in accordance with the Steam Generator Program prior to entering HOT SHUTDOWN following a SG tube inspection.

L-2006-229, TS Mark up and Inserts Page 15 of 23 REACTOR COOLANT SYSTEM 3/4.4.6 REACTOR COOLANT SYSTEM LEAKAGE LEAKAGE DETECTION SYSTEMS LIMITING CONDITION FOR OPERATION 3.4.6.1 The following Reactor Coolant System Leakage Detection Systems shall be OPERABLE:

a.

The Containment Atmosphere Gaseous or Particulate Radioactivity Monitoring System, and

b.

A Containment Sump Level Monitoring System.

APPLICABILITY:

MODES 1, 2, 3 and 4.

ACTION:

a.

With both the Particulate and Gaseous Radioactivity Monitoring Systems inoperable, operation may continue for up to 7 days provided:

1)

A Containment Sump Level Monitoring System is OPERABLE;

2)

Appropriate grab samples are obtained and analyzed at least once per 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months ; 3

,*Reactor Coolant System water inventory balance is performed at least once pe J

-dring steady state operation)except when operating in shutdown cooling mode; and

's

4)

Containment Purge, Exhaust and Instrument Air Bleed valves are maintained closed.

Otherwise, be in at least HOT STANDBY within the next 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 .

b.

With no Containment Sump Level Monitoring System operable, restore at least one Containment Sump Level Monitoring System to OPERABLE status within 7 days, or be in at least HOT STANDBY 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 .

SURVEILLANCE REQUIREMENTS 4.4.6.1 The Leakage Detection System shall be demonstrated OPERABLE by:

a.

Containment Atmosphere Gaseous and Particulate Monitoring System-performance of CHANNEL CHECK, CHANNEL CALIBRATION and ANALOG CHANNEL OPERATIONAL TEST at the frequencies specified in Table 4.3-3, and

b.

Containment Sump Level Monitoring System-performance of CHANNEL CALIBRATION at least once per 18 months.

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.

TURKEY POINT - UNITS 3 & 4 3/4 4-18 AMENDMENT NOS.

ND 32

L-2006-229, TS Mark up and Inserts Page 16 of 23 REACTOR COOLANT SYSTEM OPERATIONAL LEAKAGE LIMITING CONDITION FOR OPERATING Ioperational 3..6.2 Reactor Coolant Syster$leakage shall be limited to:ý

a.

No PRESSURE BOUNDARY LEAKAGE,

b.

1 GPM UNIDENTIFIED LEAKAGE,

c.

150 gallons per day primary-to-secondary leakage through any one steam generator (SG),

d 10 GPM IDENTIFIED LEAKAGE from the Reactor Coolant System, and e

Leakage as specified in Table 3.4-1 up to a maximum of 5 GPM at a Reactor Coolant System pressure of 2235 + 20 psig from any Reactor Coolant System Pressure Isolation Valve specified in Table 3 4-1.*

APPLICABILITY:

MODES 1, 2, 3 and 4..

Ior with primary-to-secondary leakaae not within limit. I ACTION_.

a.

With any PRESSURE BOUNDARY LEAKAGEbe in at least HOT STANDBY within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in COLD SHUTDOWN withinthe foliown 30- hours, Irimary-to-secondary leakave, IoperationalI

b.

With any Reactor Coolant Systemrneakage greater than any one of the above limits, excluding/

PRESSURE BOUNDARY LEAKAGE, and leakage from Reactor Coolant System Pressure Isolation Valves, reduce the leakage rate to within limits within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months or be in at least HOT STANDBY within the next 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 .,

c.

With any Reactor Coolant System Pressure Isolation Valve leakage greater than allowed by 3.4.6.2 e above operation may continue provided:

1.

Within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months verify that at least two valves in each high pressure line having a non-functional valve are in, and remain in that mode corresponding to the isolated condition, i.. e., manual valves shall be locked in the closed position, motor operated valves shall be placed in the closed position and power supplies deenergized.

Follow applicable ACTION statement for the affected system, and

Test pressure less than 2235 psig are allowed.

Minimum differential test pressure shall not be less than 150 psid.

Observed leakage shall be adjusted for the actual test pressure up to 2235 psig assuming the leakage to be directly proportional to pressure differential to the one-half power.

TURKEY POINT - UNITS 3 & 4 3/4 4-19 AMENDMENTS NOS.(

AAND j'

L-2006-229, TS Mark up and Inserts Page 17 of 23 REACTOR COOLANT SYSTEM OPERATIONAL LEAKAGE LIMITING CONDITION FOR OPERATION (Continued)

2.

The leakage* from the remaining isolating valves in each high pressure line having a valve not meeting the criteria of Table 3.4-1, as listed in Table 3.4-1, shall be determined and recorded daily. The positions of the other valves located in the high pressure line having the leaking valve shall be recorded daily unless they are manual valves located inside containment.

Otherwise be in at least HOT STANDBY within the next 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 .

d.

With any Reactor Coolant System Pressure Isolation Valve leakage greater than 5 gpm, reduce leakage to below 5 gpm within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months , or be in at least HOT STANDBY within the next 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 .

SURVEILLANCE REQUIREMENTS 4.4.6.2.

L~k~

1 Reactor Coolant Systemrleakages shall be demonstrated to be within each of the above limits by:

a.

Monitoring the containment atmosphere gaseous or particulate radioactivity monitor at least once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

7ce

and

b.

Monitoring the containment sump level at least o ce per 1 hours1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months .

C.

Permance o Reac Coolant System wat i ento balance within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months a achievin seady-s

ýtaemoeraton**anat le nce per 2(J hour ereafter pera excep a no more a

ours shall e apse e een any two successive inventory balances; sand

d.

Monitoring the Reactor Head Flange Leakoff System at least once per 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

2 Each Reactor Coolant System Pressure Isolation Valve specified in Table 3.4-1 shall be demonstrated OPERABLE by verifying leakage* to be within its limit:

a.

At least once per 18 months.

b.

Prior to entering MODE 2 whenever the plant has been in COLD SHUTDOWN for 7 days or more and if leakage testing has not been performed in the previous 9 months, and

c.

Prior to returning the valve to service following maintenance, repair or replacement work on the valve.

le.

Verifying primary-to-secondary leakage is < 150 gallons per day through any one 5G at least once per 72*** hours.

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.

r 1

INot applicable to primary-to-secondary leakage.I l

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.

Saverage coolant temperature being changed by less than 5ýF/hour.

,*,=.

TURKEY POINT - UNITS 3 & 4 3/4 4-20 AMENDMENT NOS.&ND8

L-2006-229, TS Mark up and Inserts Page 18 of 23 ADMINISTRATIVE CONTROLS PROCEDURES AND PROGRAMS (Continued)

The combined As-left leakage rates determined on a maximum pathway leakage rate basis for all penetrations shall be verified to be less than 0.60 L0, prior to increasing primary coolant temperature above 200OF following an outage or shutdown that included Type B and Type C testing only.

The As-found leakage rates, determined on a minimum pathway leakage rate basis, for all newly tested penetrations when summed with the As-left minimum pathway leakage rate leakage rates for all other penetrations shall be less than 0.6 La, at all times when containment integrity is required.

3)

Overall air lock leakage acceptance criteria is _ 0.05 La, when pressurized to P.

The provisions of Specification 4.0.2 do not apply to the test frequencies contained within the Containment Leakage Rate Testing Program.

Technical Specifications (TS) Bases Control Program This program provides a means for processing changes to the Bases of these Technical Specifications.

a.

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

b.

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

1.

Change in the TS incorporated in the license or

2.

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

c.

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

d.

Proposed changes that meet the criteria of Specification 6.8.4 i.b. above shall be reviewed and approved by the NRC prior to implementation. Changes to the Bases implemented without prior NRC approval shall be provided to the NRC on a frequency consistent with 10 CFR 50.71(e).

6.8.5 Administrative procedures shall be developed and implemented to limit the working hours of personnel who perform safety-related functions, e.g. licensed Senior Operators, licensed Operators, health physicists, auxiliary operators, and key maintenance personnel. The procedures shall include guidelines on working hours that ensure that adequate shift coverage is maintained without routine heavy use of overtime for individuals.

Any deviation from the working hour guidelines shall be authorized by the applicable department manager or higher levels of management, in accordance with established procedures and with documentation of the basis for granting the deviation. Controls shall be included in the procedures to require a periodic independent review be conducted to ensure that excessive hours have not been assigned. Routine deviation from the working hour guidelines shall not be authorized, TURKEY POINT - UNITS 3 & 4 6-18 AMENDMENT NOS4 ANI*

L-2006-229, TS Mark up and Inserts Page 19 of 23 ADMINISTRATIVE CONTROLS - INSERT 6.8.4.1

j.

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:

a. Provisions for condition monitoring assessments. Condition monitoring assessment means an evaluation of the "as found" condition of the tubing with respect to the performance criteria for structural integrity and accident induced leakage. The "as found" condition refers to the condition of the tubing during an SG inspection outage, as determined from the inservice inspection results or by other means, prior to the plugging of tubes.

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

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

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

2. Accident induced leakage performance criterion: The primary-to-secondary accident induced leakage rate for any design basis accident, other than 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 total through all SGs and 500 gallons per day through any one SG.

L-2006-229, TS Mark up and Inserts Page 20 of 23

3.

The operational leakage performance criterion is specified in LCO 3.4.6.2, "Reactor Coolant System Operational Leakage."

c.

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

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

1. For Unit 3 during Refueling Outage 23 and the subsequent operating cycles until the next scheduled inspection, and for Unit 4 during Refueling Outage 23 and the subsequent operating cycles until the next scheduled inspection, flaws found in the portion of the tube below 17 inches from the top of the hot leg tubesheet do not require plugging.

2. For Unit 3 during Refueling Outage 23 and the subsequent operating cycles until the next scheduled inspection, and for Unit 4 during Refueling Outage 23 and the subsequent operating cycles until the next scheduled inspection, all tubes with flaws identified in the portion of the tube within the region from the top of the hot leg tubesheet to 17 inches below the top of the tubesheet shall be removed from service.

d. Provisions for SG tube inspections. Periodic SG tube inspections shall be performed. The number and portions of the tubes inspected and methods of inspection shall be performed with the objective of detecting flaws of any type (e.g., volumetric flaws, axial and circumferential cracks) that may be present along the length of the tube, from the tube-to-tubesheet weld at the tube inlet to the tube-to-tubesheet weld at the tube outlet, and that may satisfy the applicable tube repair criteria. For Unit 3 during Refueling Outage 23 and the subsequent operating cycles until the next scheduled inspection, and for Unit 4 during Refueling Outage 23 and the subsequent operating cycles until the next scheduled inspection, the portion of the tube below 17 inches from the top of the hot leg tubesheet is excluded. The tube-to-tubesheet weld is not part of the tube. In addition to meeting the requirements of d.1, d.2, and d.3 below, the inspection scope, inspection methods, and inspection intervals shall be such as to ensure that SG tube integrity is maintained until the next SG inspection. An assessment of degradation shall be performed to determine the type and location of flaws to which the tube may be susceptible and, based on this assessment, to determine which inspection methods need to be employed and at what locations.

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

2. Inspect 100% of the tubes at sequential periods of 120, 90, and, thereafter, 60 effective full power months. The first sequential period

L-2006-229, TS Mark up and Inserts Page 21 of 23 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 outages nearest the end of the period. No SG shall operate for more than 48 effective full power months or two refueling outages (whichever is less) without being inspected.

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

e. Provisions for monitoring operational primary-to-secondary leakage.

L-2006-229, TS Mark up and Inserts Page 22 of 23 ADMINISTRATIVE CONTROLS

3.

WCAP-10054-P, Addendum 2, Revision 1 (proprietary), "Addendum to the Westinghouse Small Break ECCS Evaluation Model Using the NOTRUMP Code: Safety Injection in the Broken Loop and Improved Condensation Model," October 1995.*

4.

WCAP-12945-P, "Westinghouse Code Qualification Document For Best Estimate LOCA Analysis," Volumes I-V, June 1996.**

5.

USNRC Safety Evaluation Report, Letter from R. C. Jones (USNRC) to N. J. Liparulo (W),

"Acceptance for Referencing of the Topical Report WCAP-12945(P) 'Westinghouse Code Qualification Document for Best Estimate Loss of Coolant Analysis,' "June 28, 1996.**

6.

Letter dated June 13, 1996, from N. J. Liparulo (A) to Frank R. Orr (USNRC), "Re-Analysis Work Plans Using Final Best Estimate Methodology."R y

7.

WCAP-12610-P-A, "VANTAGE+ Fuel Assembly Reference Core Report," S. L. Davidson and T. L. Ryan, April 1995.

The analytical methods used to determine Rod Bank Insertion Limits and the All Rods Out position shall be those previously reviewed and approved by the NRC in:

1.

WCAP-9272-P-A, "Westinghouse Reload Safety Evaluation Methodology," July 1985.

The ability to calculate the COLR nuclear design parameters are demonstrated in:

1.

Florida Power & Light Company Topical Report NF-TR-95-01, "Nuclear Physics Methodology for Reload Design of Turkey Point & St. Lucie Nuclear Plants."

Topical Report NF-TR-95-01 was approved by the NRC for use by Florida Power & Light Company in:

1.

Safety Evaluation by the Office of Nuclear Reactor Regulations Related to Amendment No. 174 to Facility Operating License DPR-31 and Amendment No. 168 to Facility Operating License DPR-41, Florida Power & Light Company Turkey Point Units 3 and 4, Docket Nos. 50-250 and 50-251.

The AFD, FQ(Z), FAH, K(Z), and Rod Bank Insertion Limits shall be determined such that all applicable limits of the safety analyses are met. The CORE OPERATING LIMITS REPORT, including any mid-cycle revisions or supplements thereto, shall be provided upon issuance, for each reload cycle, to the NRC Document Control Desk fIE with copies to the Regional Administrator and Resident Inspector, unless otherwise approved by the Commission.

1INSERT[

6.9.1.8 ISPECIAL REPORTS 6.9.2 Special reports shall be submitted to the Regional Administrator of the Regional Office of the NRC within the time period specified for each report as stated in the Specifications within Sections 3.0, 4.0, or 5.0.

This reference is only to be used subsequent to NRC approval.

- As evaluated in NRC Safety Evaluation dated December 20, 1997.

TURKEY POINT - UNITS 3 & 4 6-22 AMENDMENT NOS.(9ANDG

L-2006-229, TS Mark up and Inserts Page 23 of 23 ADMINISTRATIVE CONTROLS - INSERT 6.9.1.8 STEAM GENERATOR TUBE INSPECTION REPORT 6.9.1.8 A report shall be submitted within 180 days after the initial entry into MODE 4 following completion of an inspection performed in accordance with Specification 6.8.4.j, 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.

ENCLOSURE 3 Proposed Technical Specification Pages

L-2006-229, Proposed TS Pages Page 1 of 20 INDEX LIMITING CONDITIONS FOR OPERATION AND SURVEILLANCE REQUIREMENTS SECTION PAGE 3/4.4 REACTOR COOLANT SYSTEM 3/4.4.1 3/4.4.2 3/4.4.3 3/4.4.4 3/4.4.5 3/4.4.6 TABLE 3.4-1 3/4.4.7 TABLE 3.4-2 TABLE 4.4-3 3/4.4.8 FIGURE 3.4-1 TABLE 4.4-4 REACTOR COOLANT LOOPS AND COOLANT CIRCULATION Startup and Pow er O peration.........................................................................

H ot S ta n d b y...................................................................................................

H ot S h utd ow n.................................................................................................

Cold Shutdown - Loops Filled.........................

Cold Shutdown - Loops Not Filled....................................

SAFETY VALVES S h u td o w n...............................................................................................

O p e ra tin g...............................................................................................

P R E S S U R IZ E R..............................................................................................

R E L IE F V A LV E S............................................................................................

STEAM GENERATOR (SG) TUBE INTEGRITY..........................

REACTOR COOLANT SYSTEM LEAKAGE Leakage D etection System s...........................................................................

O pe ratio na l Lea ka ge......................................................................................

REACTOR COOLANT SYSTEM PRESSURE ISOLATION VALVES............

C H E M IS T R Y..................................................................................................

REACTOR COOLANT SYSTEM CHEMISTRY LIMITS.................................

REACTOR COOLANT SYSTEM CHEMISTRY LIMITS SURVEILLANCE R E Q U IR E M E N T S...........................................................................................

S P E C IF IC A C T IV IT Y......................................................................................

DOSE EQUIVALENT 1-131 REACTOR COOLANT SPECIFIC ACTIVITY LIMIT VERSUS PERCENT OF RATED THERMAL POWER WITH THE REACTOR COOLANT SPECIFIC ACTIVITY > 1 ýtCi/gram D O S E EQ U IV A LE N T 1-131............................................................................

REACTOR COOLANT SPECIFIC ACTIVITY SAMPLE AND ANALYSIS P R O G RA M...................................................................................................

3/4 4-1 3/4 4-2 3/4 4-3 3/4 4-5 3/4 4-6 3/4 4-7 3/4 4-8 3/4 4-9 3/4 4-10 3/4 4-11 3/4 4-18 3/4 4-19 3/4 4-22 3/4 4-23 3/4 4-24 3/4 4-25 3/4 4-26 3/4 4-27 3/4 4-28 TURKEY POINT - UNITS 3 & 4 vii AMENDMENT NOS.

AND

L-2006-229, Proposed TS Pages INDEX Page 2 of 20 ADMINISTRATIVE CONTROLS SECTION PAGE 6.6 DELETED..........................................................................................................................

6-12 6.7 DELETED..........................................................................................................................

6-12 6.8 PRO CEDURES AND PROG RAM S...................................................................................

6-13 6.9 REPO RTING REQ UIREM ENTS.......................................................................................

6-18 6.9.1 RO UTINE REPO RTS....................................................................................................

6-18 Startup Report.........................................................................................................

6-18 Annual Reports........................................................................................................

6-19 Annual Radiological Environm ental O perating Report............................................

6-20 Annual Radioactive Effl uent Release Report..........................................................

6-20 Peaking Factor Lim it Report....................................................................................

6-21 Core O perating Lim its Report..................................................................................

6-21 Steam G enerator Tube Inspection Report..............................................................

6-22 6.9.2 SPECIAL REPO RTS.....................................................................................................

. 6-22a 6.10 DELETED........................................................................................................................

6-23 TURKEY POINT - UNITS 3 & 4 xvi AMENDMENT NOS.

AND

L-2006-229, Proposed TS Pages Page 3 of 20 DEFINITIONS FREQUENCY NOTATION DOSE EQUIVALENT 1-131 1.12 DOSE EQUIVALENT 1-131 shall be that concentration of 1-131 (microCurie/gram) which alone would'produce the same thyroid dose as the quantity and isotopic mixture of 1-131, 1-132, 1-133, 1-134, and 1-135 actually present. The thyroid dose conversion factors used for this calculation shall be those listed in Table III of TID-14844, "Calculation of Distance Factors for Power and Test Reactor Sites" or Table E-7 of NRC Regulatory Guide 1.109, Revision 1, October 1977.

E-AVERAGE DISINTEGRATION ENERGY 1.13 E shall be the average (weighted in proportion to the concentration of each radionuclide in the reactor coolant at the time of sampling) of the sum of the average beta and gamma energies per disintegration (MeV/d) for the radionuclides in the sample isotopes, other than iodines, with half lives greater than 30 minutes, making up at least 95 percent of the total non-iodine activity in the coolant.

1.14 The FREQUENCY NOTATION specified for the performance of Surveillance Requirements shall correspond to the intervals defined in Table 1.1.

GAS DECAY TANK SYSTEM 1.15 A GAS DECAY TANK SYSTEM shall be any system designed and installed to reduce radioactive gaseous effluents by collecting Reactor Coolant System off gases from the Reactor Coolant System and providing for delay or holdup for the purpose of reducing the total radioactivity prior to release to the environment.

IDENTIFIED LEAKAGE 1.16 IDENTIFIED LEAKAGE shall be:

a.

Leakage (except CONTROLLED LEAKAGE) into closed systems, such as pump seal or valve packing leaks that are captured and conducted to a sump or collecting tank, or

b.

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

c.

Reactor Coolant System leakage through a steam generator to the Secondary Coolant System (primary-to-secondary leakage).

TURKEY POINT - UNITS 3 & 4 1-3 AMENDMENT NOS.

AND

L-2006-229, Proposed TS Pages Page 4 of 20 DEFINITIONS OPERABLE - OPERABILITY 1.17 A system, subsystem, train, component or device shall be OPERABLE or have OPERABILITY when it is capable of performing its specified function(s), and when all necessary attendant instrumentation, controls, electrical power, cooling or seal water, lubrication or other auxiliary equipment that are required for the system, subsystem, train, component, or device to perform its function(s) are also capable of performing their related support function(s).

OPERATIONAL MODE - MODE 1.18 An OPERATIONAL MODE (i.e., MODE) shall correspond to any one inclusive combination of core reactivity condition, power level, and average reactor coolant temperature specified in Table 1.2.

PHYSICS TESTS 1.19 PHYSICS TESTS shall be those tests performed to measure the fundamental nuclear characteristics of the reactor core and related instrumentation: (1) described in Chapter 13.5 of the FSAR, (2) authorized under the provisions of 10 CFR 50.59, or (3) otherwise approved by the Commission.

PRESSURE BOUNDARY LEAKAGE 1.20 PRESSURE BOUNDARY LEAKAGE shall be leakage (except primary-to-secondary leakage) through a nonisolable fault in a Reactor Coolant System component body, pipe wall, or vessel wall.

PURGE - PURGING 1.21 PURGE or PURGING shall be any controlled process of discharging air or gas from a confinement to maintain temperature, pressure, humidity, concentration or other operating condition, in such a manner that replacement air or gas is required to purify the confinement.

TURKEY POINT - UNITS 3 & 4 1-4 AMENDMENT NOS.

AND

L-2006-229, Proposed TS Pages Page 5 of 20 TABLE 3.3-4 (Continued)

TABLE NOTATIONS During CORE ALTERATIONS or movement of irradiated fuel within the containment comply with Specification 3/4.9.13.

With irradiated fuel in the spent fuel pits.

Unit 4 Spent Fuel Pool Area is monitored by Plant Vent radioactivity instrumentation.

Note 1 Either the particulate or gaseous channel in the OPERABLE status will satisfy this LCO.

Note 2 Containment Gaseous Monitor Setpoint =

(3.2 x 104) CPM, F)

Actual Purge Flow Where F -

CFM)

Design Purge Flow(35,000 CFM)

ACTION 26 -

Setpoint may vary according to current plant conditions provided that the release rate does not exceed allowable limits provided in the Offsite Dose Calculation Manual.

ACTION STATEMENTS In MODES 1 thru 4: With both the Particulate and Gaseous Radioactivity Monitoring Systems inoperable, operation may continue for up to 7 days provided:

1)

A Containment sump level monitoring system is OPERABLE,

2)

Appropriate grab samples are obtained and analyzed at least once per 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months ,

3)

A Reactor Coolant System water inventory balance is performed at least once per 8*** hours except when operating in shutdown cooling mode, and

4)

Containment Purge, Exhaust and Instrument Air Bleed Valves are maintained closed.

Otherwise, be in at least HOT STANDBY within the next 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 (ACTION 27 applies in MODES 5 and 6).

- - 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.

TURKEY POINT - UNITS 3 & 4 3/4 3-37 AMENDMENT NOS.

AND

L-2006-229, Proposed TS Pages Page 6 of 20 REACTOR COOLANT SYSTEM 3/4.4.5 STEAM GENERATOR (SG) TUBE INTEGRITY LIMITING CONDITION FOR OPERATION 3.4.5 SG tube integrity shall be maintained AND All SG tubes satisfying the tube repair criteria shall be plugged in accordance with the SG Program.

APPLICABILITY:

MODES 1, 2, 3 and 4.

ACTION:

a.

With one or more SG tubes satisfying the tube repair criteria and not plugged in accordance with the Steam Generator Program;

1.

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

2.

Plug the affected tube(s) in accordance with the Steam Generator Program prior to entering HOT SHUTDOWN following the next refueling outage or SG tube inspection.

b.

With the requirements and associated allowable outage time of Action a above not met or SG tube integrity not maintained, be in HOT STANDBY within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in COLD SHUTDOWN within the next 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months .

SURVEILLANCE REQUIREMENTS 4.4.5.1 Verify SG tube integrity in accordance with the Steam Generator Program.

4.4.5.2 Verify that each inspected SG tube that satisfies the tube repair criteria is plugged in accordance with the Steam Generator Program prior to entering HOT SHUTDOWN following a SG tube inspection.

Separate Action entry is allowed for each SG tube.

TURKEY POINT - UNITS 3 & 4 3/44-11 AMENDMENT NOS.

AND

L-2006-229, Proposed TS Pages Page 7 of 20 THIS PAGE DELETED TURKEY POINT - UNITS 3 & 4 3/4 4-12 AMENDMENT NOS.

AND

L-2006-229, Proposed TS Pages Page 8 of 20 THIS PAGE DELETED TURKEY POINT - UNITS 3 & 4 3/4 4-13 AMENDMENT NOS.

AND

L-2006-229, Proposed TS Pages Page 9 of 20 THIS PAGE DELETED TURKEY POINT - UNITS 3 & 4 3/4 4-14 AMENDMENT NOS.

AND

L-2006-229, Proposed TS Pages Page 10 of 20 THIS PAGE DELETED TURKEY POINT - UNITS 3 & 4 3/4 4-15 AMENDMENT NOS.

AND

L-2006-229, Proposed TS Pages Page 11 of 20 THIS PAGE DELETED TURKEY POINT - UNITS 3 & 4 3/4 4-16 AMENDMENT NOS.

AND

L-2006-229, Proposed TS Pages Page 12 of 20 THIS PAGE DELETED TURKEY POINT - UNITS 3 & 4 3/4 4-17 AMENDMENT NOS.

AND

L-2006-229, Proposed TS Pages Page 13 of 20 REACTOR COOLANT SYSTEM 3/4.4.6 REACTOR COOLANT SYSTEM LEAKAGE LEAKAGE DETECTION SYSTEMS LIMITING CONDITION FOR OPERATION 3.4.6.1 The following Reactor Coolant System Leakage Detection Systems shall be OPERABLE:

a.

The Containment Atmosphere Gaseous or Particulate Radioactivity Monitoring System, and

b.

A Containment Sump Level Monitoring System.

APPLICABILITY:

MODES 1, 2, 3 and 4.

ACTION:

a.

With both the Particulate and Gaseous Radioactivity Monitoring Systems inoperable, operation may continue for up to 7 days provided:

1)

A Containment Sump Level Monitoring System is OPERABLE;

2)

Appropriate grab samples are obtained and analyzed at least once per 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months ;

3)

A Reactor Coolant System water inventory balance is performed at least once per 8*

hours except when operating in shutdown cooling mode; and

4)

Containment Purge, Exhaust and Instrument Air Bleed valves are maintained closed.

Otherwise, be in at least HOT STANDBY within the next 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 .

b.

With no Containment Sump Level Monitoring System operable, restore at least one Containment Sump Level Monitoring System to OPERABLE status within 7 days, or be in at least HOT STANDBY 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 .

SURVEILLANCE REQUIREMENTS 4.4.6.1 The Leakage Detection System shall be demonstrated OPERABLE by:

a.

Containment Atmosphere Gaseous and Particulate Monitoring System-performance of CHANNEL CHECK, CHANNEL CALIBRATION and ANALOG CHANNEL OPERATIONAL TEST at the frequencies specified in Table 4.3-3, and

b.

Containment Sump Level Monitoring System-performance of CHANNEL CALIBRATION at least once per 18 months.

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.

TURKEY POINT - UNITS 3 & 4 3/4 4-18 AMENDMENT NOS.

AND

L-2006-229, Proposed TS Pages Page 14 of 20 REACTOR COOLANT SYSTEM OPERATIONAL LEAKAGE LIMITING CONDITION FOR OPERATING 3.4.6.2 Reactor Coolant System operational leakage shall be limited to:

a.

No PRESSURE BOUNDARY LEAKAGE,

b.

1 GPM UNIDENTIFIED LEAKAGE,

c.

150 gallons per day primary-to-secondary leakage through any one steam generator (SG),

d.

10 GPM IDENTIFIED LEAKAGE from the Reactor Coolant System, and

e.

Leakage as specified in Table 3.4-1 up to a maximum of 5 GPM at a Reactor Coolant System pressure of 2235 +/- 20 psig from any Reactor Coolant System Pressure Isolation Valve specified in Table 3.4-1.*

APPLICABILITY:

MODES 1, 2, 3 and 4.

ACTION:

a.

With any PRESSURE BOUNDARY LEAKAGE, or with primary-to-secondary leakage not within limit, be in at least HOT STANDBY 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 .

b.

With any Reactor Coolant System operational leakage greater than any one of the above limits, excluding primary-to-secondary leakage, PRESSURE BOUNDARY LEAKAGE, and leakage from Reactor Coolant System Pressure Isolation Valves, reduce the leakage rate to within limits within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months or be in at least HOT STANDBY within the next 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 .

c.

With any Reactor Coolant System Pressure Isolation Valve leakage greater than allowed by 3.4.6.2.e above operation may continue provided:

1.

Within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months verify that at least two valves in each high pressure line having a non-functional valve are in, and remain in that mode corresponding to the isolated condition, i.e., manual valves shall be locked in the closed position; motor operated valves shall be placed in the closed position and power supplies deenergized.

Follow applicable ACTION statement for the affected system, and

Test pressure less than 2235 psig are allowed.

Minimum differential test pressure shall not be less than 150 psid.

Observed leakage shall be adjusted for the actual test pressure up to 2235 psig assuming the leakage to be directly proportional to pressure differential to the one-half power.

TURKEY POINT - UNITS 3 & 4 3/4 4-19 AMENDMENT NOS.

AND

L-2006-229, Proposed TSPages Page 15 of 20 REACTOR COOLANT SYSTEM OPERATIONAL LEAKAGE LIMITING CONDITION FOR OPERATION (Continued)

2.

The leakage* from the remaining isolating valves in each high pressure line having a valve not meeting the criteria of Table 3.4-1, as listed in Table 3.4-1, shall be determined and recorded daily. The positions of the other valves located in the high pressure line having the leaking valve shall be recorded daily unless they are manual valves located inside containment.

Otherwise be in at least HOT STANDBY within the next 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 .

d.

With any Reactor Coolant System Pressure Isolation Valve leakage greater than 5 gpm, reduce leakage to below 5 gpm within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months , or be in at least HOT STANDBY within the next 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 .

SURVEILLANCE REQUIREMENTS 4.4.6.2.1 Reactor Coolant System operational leakages shall be demonstrated to be within each of the above limits by:

a.

Monitoring the containment atmosphere gaseous or particulate radioactivity monitor at least once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

b.

Monitoring the containment sump level at least once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

c.

Performance of a Reactor Coolant System water inventory balance at least once per 72*** hours; and

d.

Monitoring the Reactor Head Flange Leakoff System at least once per 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months ; and

e.

Verifying primary-to-secondary leakage is < 150 gallons per day through any one SG at least once per 72*** hours.

4.4.6.2.2 Each Reactor Coolant System Pressure Isolation Valve specified in Table 3.4-1 shall be demonstrated OPERABLE by verifying leakage* to be within its limit:

a.

At least once per 18 months.

b.

Prior to entering MODE 2 whenever the plant has been in COLD SHUTDOWN for 7 days or more and if leakage testing has not been performed in the previous 9 months, and

c.

Prior to returning the valve to service following maintenance, repair or replacement work on the valve.

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.

Not applicable to primary-to-secondary leakage.

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.

TURKEY POINT - UNITS 3 & 4 3/4 4-20 AMENDMENT NOS.

AND

L-2006-229, Proposed TS Pages Page 16 of 20 ADMINISTRATIVE CONTROLS PROCEDURES AND PROGRAMS (Continued)

The combined As-left leakage rates determined on a maximum pathway leakage rate basis for all penetrations shall be verified to be less than 0.60 La, prior to increasing primary coolant temperature above 200°F following an outage or shutdown that included Type B and Type C testing only.

The As-found leakage rates, determined on a minimum pathway leakage rate basis, for all newly tested penetrations when summed with the As-left minimum pathway leakage rate leakage rates for all other penetrations shall be less than 0.6 La, at all times when containment integrity is required.

3)

Overall air lock leakage acceptance criteria is _< 0.05 La, when pressurized to Pa.

The provisions of Specification 4.0.2 do not apply to the test frequencies contained within the Containment Leakage Rate Testing Program.

i.

Technical Specifications (TS) Bases Control Program This program provides a means for processing changes to the Bases of these Technical Specifications.

a.

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

b.

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

1.

Change in the TS incorporated in the license or

2.

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

c.

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

d.

Proposed changes that meet the criteria of Specification 6.8.4 i.b. above shall be reviewed and approved by the NRC prior to implementation. Changes to the Bases implemented without prior NRC approval shall be provided to the NRC on a frequency consistent with 10 CFR 50.71(e).

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:,

a.

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

TURKEY POINT - UNITS 3 & 4 6-18 AMENDMENT NOS.

AND

L-2006-229, Proposed TS Pages Page 17 of 20 ADMINISTRATIVE CONTROLS PROCEDURES AND PROGRAMS (Continued)

b.

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

1.

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

2.

Accident induced leakage performance criterion: The primary-to-secondary accident induced leakage rate for any design basis accident, other than 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 total through all SGs and 500 gallons per day through any one SG.

3.

The operational leakage performance criterion is specified in LCO 3.4.6.2, "Reactor Coolant System Operational Leakage."

c.

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

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

depth based criteria:

1.

For Unit 3 during Refueling Outage 23 and the subsequent operating cycles until the next scheduled inspection, and for Unit 4 during Refueling Outage 23 and the subsequent operating cycles until the next scheduled inspection, flaws found in the portion of the tube below 17 inches from the top of the hot leg tubesheet does not require plugging.

2.

For Unit 3 during Refueling Outage 23 and the subsequent operating cycles until the next scheduled inspection, and for Unit 4 during Refueling Outage 23 and the subsequent operating cycles until the next scheduled inspection, all tubes with flaws identified in the portion of the tube within the region from the top of the hot leg tubesheet to 17 inches below the top of the tubesheet shall be removed from service.

TURKEY POINT - UNITS 3 & 4 6-18a AMENDMENT NOS.

AND

L-2006-229, Proposed TS Pages Page 18 of 20 ADMINISTRATIVE CONTROLS PROCEDURES AND PROGRAMS (Continued)

d.

Provisions for SG tube inspections. Periodic SG tube inspections shall be performed.

The number and portions of the tubes inspected and methods of inspection shall be performed with the objective of detecting flaws of any type (e.g., volumetric flaws, axial and circumferential cracks) that may be present along the length of the tube, from the tube-to-tubesheet weld at the tube inlet to the tube-to-tubesheet weld at the tube outlet, and that may satisfy the applicable tube repair criteria. For Unit 3 during Refueling Outage 23 and the subsequent operating cycles until the next scheduled inspection, and for Unit 4 during Refueling Outage 23 and the subsequent operating cycles until the next scheduled inspection, the portion of the tube below 17 inches from the top of the hot leg tubesheet is excluded. The tube-to-tubesheet weld is not part of the tube. In addition to meeting the requirements of d.1, d.2, and d.3 below, the inspection scope, inspection methods, and inspection intervals shall be such as to ensure that SG tube integrity is maintained until the next SG inspection. An assessment of degradation shall be performed to determine the type and location of flaws to which the tube may be susceptible and, based on this assessment, to determine which inspection methods need to be employed and at what locations.

1.

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

2.

Inspect 100% of the tubes at sequential periods of 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 outages nearest the end of the period. No SG shall operate for more than 48 effective full power months or two refueling outages (whichever is less) without being inspected.

3.

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

e.

Provisions for monitoring operational primary-secondary leakage.

6.8.5 Administrative procedures shall be developed and implemented to limit the working hours of personnel who perform safety-related functions, e.g. licensed Senior Operators, licensed Operators, health physicists, auxiliary operators, and key maintenance personnel. The procedures shall include guidelines on working hours that ensure that adequate shift coverage is maintained without routine heavy use of overtime for individuals.

Any deviation from the working hour guidelines shall be authorized by the applicable department manager or higher levels of management, in accordance with established procedures and with documentation of the basis for granting the deviation. Controls shall be included in the procedures to require a periodic independent review be conducted to ensure that excessive hours have not been assigned. Routine deviation from the working hour guidelines shall not be authorized.

TURKEY POINT - UNITS 3 & 4 6-18b AMENDMENT NOS.

AND

L-2006-229, Proposed TS Pages Page 19 of 20 ADMINISTRATIVE CONTROLS

3.

WCAP-10054-P, Addendum 2, Revision 1 (proprietary), "Addendum to the Westinghouse Small Break ECCS Evaluation Model Using the NOTRUMP Code: Safety Injection in the Broken Loop and Improved Condensation Model," October 1995.*

4.

WCAP-12945-P, "Westinghouse Code Qualification Document For Best Estimate LOCA Analysis," Volumes I-V, June 1996.**

5.

USNRC Safety Evaluation Report, Letter from R. C. Jones (USNRC) to N. J. Liparulo (VV),

"Acceptance for Referencing of the Topical Report WCAP-12945(P) 'Westinghouse Code Qualification Document for Best Estimate Loss of Coolant Analysis,' "June 28, 1996.**

6.

Letter dated June 13, 1996, from N. J. Liparulo (WV) to Frank R. Orr (USNRC), "Re-Analysis Work Plans Using Final Best Estimate Methodology.""

7.

WCAP-1261 0-P-A, "VANTAGE+ Fuel Assembly Reference Core Report," S. L. Davidson and T. L. Ryan, April 1995.

The analytical methods used to determine Rod Bank Insertion Limits and the All Rods Out position shall be those previously reviewed and approved by the NRC in:

1.

WCAP-9272-P-A, "Westinghouse Reload Safety Evaluation Methodology," July 1985.

The ability to calculate the COLR nuclear design parameters are demonstrated in:

1.

Florida Power & Light Company Topical Report NF-TR-95-01, "Nuclear Physics Methodology for Reload Design of Turkey Point & St. Lucie Nuclear Plants."

Topical Report NF-TR-95-01 was approved by the NRC for use by Florida Power & Light Company in:

1.

Safety Evaluation by the Office of Nuclear Reactor Regulations Related to Amendment No. 174 to Facility Operating License DPR-31 and Amendment No. 168 to Facility Operating License DPR-41, Florida Power & Light Company Turkey Point Units 3 and 4, Docket Nos. 50-250 and 50-251.

The AFD, FQ(Z), FAH, K(Z), and Rod Bank Insertion Limits shall be determined such that all applicable limits of the safety analyses are met. The CORE OPERATING LIMITS REPORT, including any mid-cycle revisions or supplements thereto, shall be provided upon issuance, for each reload cycle, to the NRC Document Control Desk with copies to the Regional Administrator and Resident Inspector, unless otherwise approved by the Commission.

STEAM GENERATOR TUBE INSPECTION REPORT 6.9.1.8 A report shall be submitted within 180 days after the initial entry into MODE 4 following completion of an inspection performed in accordance with Specification 6.8.4.j, Steam Generator (SG) Program. The report shall include:

a.

The scope of inspections performed on each SG,

b.

Active degradation mechanisms found,

This reference is only to be used subsequent to NRC approval.

- As evaluated in NRC Safety Evaluation dated December 20, 1997.

TURKEY POINT - UNITS 3 & 4 6-22 AMENDMENT NOS.

AND

L-2006-229, Proposed TS Pages Page 20 of 20 ADMINISTRATIVE CONTROLS STEAM GENERATOR TUBE INSPECTION REPORT (Cont'd)

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.

SPECIAL REPORTS 6.9.2 Special reports shall be submitted to the Regional Administrator of the Regional Office of the NRC within the time period specified for each report as stated in the Specifications within Sections 3.0, 4.0, or 5.0.

TURKEY POINT-UNITS 3 & 4 6-22a AMENDMENT NOS.

AND

L-2006-229, Bases Mark up and Inserts Page 1 of 18 ENCLOSURE 4 Marked Up Pages and Inserts for Technical Specification Bases Control Program, O-ADM-536

Procedure No.:

Procedure

Title:

Page:

8 I

Approval Date:

0-ADM-536 Technical Specification Bases Control Program 3/4/03 ENCLOSURE1 L-2006-229 (Page 2 of 4), Bases Mark up and Inserts Page 2 of 18 INDEX BASES SECTION PAGE 3/4.4 REACTOR COOLANT SYSTEM 3/4.4.1 REACTOR COOLANT LOOPS AND COOLANT CIRCULATION......................

49 3/4.4.2 SA FE T Y V A LV E S.....................................................................................................

50 3/4.4.3 PR E SSU R IZ E R.........................................................................................................

51 3/4.4.4 RELIEF VALVES........

5.6)..T'UBE..INTER

ITY.

511 3/4.4.5 STEAM GENERATO S.................................................................

4 3/4.4.6 REACTOR COOLANT SYSTEM LEAKAGE........................................

3/4.4.7 C H E M IST R Y.............................................................................................................

56 3/4.4.8 SPECIFIC A CTIV ITY...............................................................................................

57 3/4.4.9 PRESSURE/TEMPERATURE LIMITS...................................................................

58 TABLE B 3/4.4-1 REACTOR VESSEL TOUGHNESS - UNIT 3.........................................

61 TABLE B 3/4.4-2 REACTOR VESSEL TOUGHNESS - UNIT 4.........................................

62 3/4.4.10 STRUCTURAL INTEGRITY....................................................................................

68 3/4.4.11 REACTOR COOLANT SYSTEM VENTS...............................................................

69 3/4.5 EMERGENCY CORE COOLING SYSTEMS 3/4.5.1 A C C U M U LA TO R S...................................................................................................

70 3/4.5.2 and 3/4.5.3 ECCS SU BSY STEM S................................................................................

71 3/4.5.4 REFUELING WATER STORAGE TANK................................................................

72 3/4.6 CONTAINMENT SYSTEMS 3/4.6.1 PRIMARY CONTAINMENT....................................................................................

73 3/4.6.2 DEPRESSURIZATION AND COOLING SYSTEMS..............................................

77 3/4.6.3 EMERGENCY CONTAINMENT FILTERING SYSTEM.......................................

78 3/4.6.4 CONTAINMENT ISOLATION VALVES................................................................

80 WVQ7flP~qJMS/Mrnjev

ATTACHMENT 1 L-2006-229 (Page 45 of 103), Bases Mark up and Inserts Page 3 of 18 TECHNICAL SPECIFICATION BASES 3/4.4 REACTOR COOLANT SYSTEM (Continued)

IINSERT B3/4.4.5I 3/4.4.5 STEAM GENERATOAS (sG UE N9

~rY S*urveillance Requirements for inspection of the steam generator tubes ensure that the st tral inte i of this portion of the RCS will be maintained. The program for inservice inspectio of steam generato bes is based on a modification of Regulatory Guide 1.83, Revision 1. Inservice spection of steam gener r tubing is essential in order to maintain surveillance of the conditions o e tubes in the event that the is evidence of mechanical damage or progressive degradat*

due to design, manufacturing erro or inservice conditions that lead to corrosion. Inservi inspection of steam generator tubing also pvides a means of characterizing the nature and cause any tube degradation so that corrective measures c be taken.

The plant is expected to be ope ed in a manner such that the s ondary coolant will be maintained within those chemistry limits found result in negligible corro n of the steam generator tubes. If the secondary coolant chemistry is not mai ined within these i its, localized corrosion may likely result in stress corrosion cracking. The extent cracking d ng plant operation would be limited by the limitation of steam generator tube leakage b een e Reactor Coolant System and the Secondary Coolant System (reactor-to-secondary leakage -

0 gallons per day per steam generator). Cracks having a reactor-to-secondary leakage less than is l1 it during operation will have an adequate margin of safety to withstand the loads impose during no al operation and by postulated accidents.

Operating plants have demonstrated that actor-to-seconda leakage of 500 gallons per day per steam generator can readily be detected b radiation monitors of s m generator blowdown. Leakage in excess of this limit will require pl shutdown and an unschedule spection, during which the leaking tubes will be located and plug Wastage-type defects unlikely with the all volatile treatment (AVT) the secondary coolant.

However, even if a ect should develop in service, it will be found during sc uled inservice steam generator tube e inations. Plugging will be required for all tubes with imperfecd ins exceeding the plugging limif 40% of the tube nominal wall thickness. Steam generator tube inspecti s of operating plants havy emonstrated the capability to reliably detect degradation that has penetrate 0% of the orgn ewall thickness.

vv uf.urý/[

I IWI III uluv

L-2006-229 ATTACgeHM1ENT 1, Bases Mark up and Inserts UEINTEGRITY (Page 46 of 103)

Page 4 of 18 ECHNICAL SPECIFICATION BASES 3/4.4 REACTOR COOLANT YSTEM (Continued)

[INSERT B3/4.4.5 3/4.4.5 STEAM GENERATO (Continued)

WhRenevits of any steam generator tubing inservice inspection fall into Catej ese results

~~ýý wilb rmpl eeCo~mmission in aSpeilR o Specification 6.9.2 fi ei nr within 30 days and prior to resumption o uch cases will be considered by the Commission on a case-by-case b may result in a nt for analysis, laboratory examinations, tests-a eddy-current inspection, and revision of the Tec ic ations, if n.

3/4.4.6 REACTOR COOLANT SYSTEM LEAKAGE 3/4.4.6.1 LEAKAGE DETECTION SYSTEMS The RCS Leakage Detection Systems required by this specification are provided to monitor and detect leakage from the reactor coolant pressure boundary to the containment. The containment sump level system is the normal sump level instrumentation. The Post Accident Containment Water Level Monitor

- Narrow range instrumentation also functions as a sump level monitoring system. In addition, gross leakage will be detected by changes in makeup water requirements, visual inspection, and audible detection. Leakage to other systems will be detected by activity changes (e.g., within the component cooling system) or water inventory changes (e.g., tank levels).

3/4.4.6.2 OPERATIONAL LEAKAGE

[INSERT B3/4.4.6.2 (follows Insert for B3/4.4.5)

PRESSURE BOUNDARY LEA E of any magnitude is u cceptable since it may be indicative of an impendin oss failure of the press boundary. Therefore, e prsence of any PRESSURE BOUNDARY AKAGE requires the unf o be promptly placed i OLD SHUTDOWN.

Industry experience s shown that while a lim d amount of leakage expected from the RCS e

unidentified porti of this leakage can be uced to a threshold lue of less than I gpm This threshold valu sufficiently low to ensur arly detection of addit' nal leakage.

thr e h lva lu,*l wt n

The tota team generator tube leak e limit of 1 gpm for a steam generators ensures at the dosage contri ution from the tube leaka will be limited to a s fraction of 10 CFR Part 0 dose guideline v

es in the event of either steam generator tube ture or steam line break he 500 gpd leakage imit per steam generator sures that steam genera r tube integrity is maintai in the event of a main steam line rupture or u er LOCA conditions.

The 10 gpm ID TIFIED LEAKAGE ' itation provides allowan for a limited amount of leakage from known ources whose presen will not interfere wit the detection of UNIDENTIFIED EAKAG y the Leakage Detect' Systems.

W97:DPS/ms/mra/ev

Procedure No.:

Procedure

Title:

Page:

57 Approval Date:

0-ADM-536 Technical Specification Bases Control Program 9/16/04 ATTACHMENT 1 L-2006-229 (Page 47 of 103), Bases Mark up and Inserts Page 5 of 18 TECHNICAL SPECIFICATION BASES 3/4.4 REACTOR COOLANT SYSTEM (Continued)

RlctdtB34,62ACON,]

3/4.4.6.2 OPERATIONAL LEAKAGE (Continued)

//

"The leakage tr-orfi -a-ny -R~bfTS-p-M

'cir-a~on-v-alve-is -suffici"ently low to ens-u-r-eea-r-y-e e-c i-o-n--o-possible in-series valve failure. It is apparent that when pressure isolation is provided by two in-series valves and when failure of one valve in the pair can gofor a substantial len of tie,

_erification of-,Iave integrity is require these*

valves ar~e

at in pre orpressuization anc ru r o the ow pressure pipingtvhatcourdreso ft R

CAnt valves should be and predcsto ensure lowroReact ro st failure sTreS c

n. MRequirements the chm ssure isola Limis provide s

add e qate cofosion potecgrity e

re teducin trobability of the alve failure and cS o e

t intersystem LOCA.

Leakage from ts pressure din oxe limits a tm and temp "erasr dpedt.

C sllowed limit 3/4.4.7 CHEMISTRY The limitations on Reactor Coolant System chemistry ensure that corrosion of the Reactor Coolant System is minimized and reduces the potef t on tesctur intert ofrtheR eactor ofailure due to stress corrosion. Maintaining the chemistry within the Steady-State Limits provides adequate corrosion protection to ensure the structural integrity of the Reactor Coolant System over the life of the plant. The associated effects of exceeding the oxygen, chloride, and fluoride limits are time and temperature dependent. Corrosion studies show that operation may be continued with contaminant concentration levels in excess of the Steady-State Limits, up to the Transient Limits, for the specified limited time intervals without having a significant effect on the structural integrity of the Reactor Coolant System.

The time interval permitting continued operation within the restrictions of the Transient Limits provides time for taking corrective actions to restore the contaminant concentrations to within the Steady-State Limits.

The Surveillance Requirements provide adequate assurance that concentrations in excess of the limits will be detected in sufficient time to take corrective action.

- o, r~ro 1iI[u

L-2006-229, Bases Mark up and Inserts Pa9e 6 of 18 INSERT B3/4.4.5 (0-ADM-536 - Technical Specification Bases Control Program)

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. SG tubes are an integral part of the reactor coolant pressure boundary (RCPB) and, as such, are relied on to maintain the primary system's pressure and inventory. The SG tubes isolate the radioactive fission products in the primary coolant from the secondary system.

In addition, as part of the RCPB, the SG tubes are unique in that they act as the heat transfer surface between the primary and secondary systems to remove heat from the primary system.

This Specification addresses only the RCPB integrity function of the SG. The SG heat removal function is addressed by LCO 3.4.1.1, "Reactor Coolant Loops and Coolant Circulation - Startup and Power Operation," LCO 3.4.1.2, "Hot Standby," LCO 3.4.1.3, "Hot Shutdown," LCO 3.4.1.4.1, "Cold Shutdown - Loops Filled," and LCO 3.4.1.4.2, "Cold Shutdown - Loops Not Filled."

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

SG tubing is subject to a variety of degradation mechanisms. SG 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 6.8.4.j, "Steam Generator (SG) Program," requires that a program be established and implemented to ensure that SG tube integrity is maintained. Pursuant to Specification 6.8.4.j, 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 6.8.4.j. 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 a SGTR is the basis for this Specification. The analysis of a SGTR event assumes a bounding primary-to-secondary leakage rate equal to 500 gpd for each of the two intact SGs plus the leakage rate associated with a double-ended rupture of a single tube in the third (ruptured)

SG. The accident analysis for a SGTR assumes the contaminated secondary fluid is released to the atmosphere via safety valves or atmospheric dump valves. No credit for iodine removal is taken for any steam released to the condenser prior to reactor trip and concurrent loss of offsite power.

L-2006-229, Bases Mark up and Inserts Page 7 of 18 INSERT B3/4.4.5 (0-ADM-536 - Technical Specification Bases Control Program)

The analysis for design basis accidents and transients other than a SGTR assume the SG tubes retain their structural integrity (i.e., they are assumed not to rupture). In the dose consequence analysis for these events the activity level in the steam discharged to the atmosphere is based on a primary-to-secondary leakage rate of 1 gpm total through all SGs and 500 gallons per day through any one SG at accident conditions, or is assumed to increase to these levels as a result of accident induced conditions. For accidents that do not involve fuel damage, the primary coolant activity level of DOSE EQUIVALENT 1-131 is assumed to be equal to the LCO 3.4.8, "Reactor Coolant System Specific Activity," limits. For accidents that assume fuel damage, the primary coolant activity is a function of the amount of activity released from the damaged fuel. The dose consequences of these events are within the limits of GDC 19 (Ref. 2), 10 CFR 100 (Ref. 3), 10 CFR 50.67 (Ref. 7) or the NRC approved licensing basis.

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

Limiting Condition for Operation (LCO)

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

During a 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 6.8.4.j 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.

L-2006-229, Bases Mark up and Inserts Page 8 of 18 INSERT B3/4.4.5 (0-ADM-536 - Technical Specification Bases Control Program)

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 verses displacement curve where the slope of the curve becomes zero." The structural integrity performance criterion provides guidance on assessing loads that have a significant effect on burst or collapse. In that context, the term "significant" is defined as "An accident loading condition other than differential pressure is considered significant when the addition of such loads in the assessment of the structural integrity performance criterion could cause a lower structural limit or limiting burst/collapse condition to be established." For tube integrity evaluations, except for circumferential degradation, axial thermal loads are classified as secondary loads. For circumferential degradation, the classification of axial thermal loads as primary or secondary loads will be evaluated on a case-by-case basis. The division between primary and secondary classifications will be based on detailed analysis and/or testing.

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

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

The accident induced leakage performance criterion ensures that the primary-to-secondary leakage caused by a design basis accident, other than a SGTR, is within the accident analysis assumptions. The accident analyses assume that accident induced leakage does not exceed 1 gpm total through all SGs and 500 gallons per day through any one of the three SGs at accident conditions. 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 LCO 3.4.6.2 and limits primary-to-secondary leakage through any one SG to 150 gpd at room temperature.

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.

L-2006-229, Bases Mark up and Inserts Page 9 of 18 INSERT B3/4.4.5 (0-ADM-536 - Technical Specification Bases Control Program)

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

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

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

a. 1 and a.2 ACTIONS a. 1 and a.2 apply 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 Surveillance Requirement (SR) 4.4.5.2.

An evaluation of SG tube integrity of the affected tube(s) must be made. SG 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, ACTION b applies.

An allowable outage time of seven days is sufficient to complete the evaluation while minimizing the risk of plant operation with a SG tube that may not have tube integrity.

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

L-2006-229, Bases Mark up and Inserts Page 10 of 18 INSERT B3/4.4.5 (0-ADM-536 - Technical Specification Bases Control Program) b.

If the requirements and associated allowable outage time of ACTION a are not met or if SG tube integrity is not being maintained, the reactor must be brought to HOT STANDBY 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 allowable outage times are reasonable, based on operating experience, to reach the desired plant conditions from full power conditions in an orderly manner and without challenging plant systems.

Surveillance Requirements SR 4.4.5.1 During shutdown periods the SGs are inspected as required by this SR and the Steam Generator Program. NEI 97-06, "Steam Generator Program Guidelines" (Ref. 1), and its referenced EPRI Guidelines, establish the content of the Steam Generator Program. Use of the Steam Generator Program ensures that the inspection is appropriate and consistent with accepted industry practices.

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

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

The Steam Generator Program defines the frequency of SR 4.4.5.1. The frequency is determined by the operational assessment and other limits in the SG examination guidelines (Ref. 6). The Steam Generator Program uses information on existing degradations and growth rates to determine an inspection frequency that provides reasonable assurance that the tubing will meet the SG performance criteria at the next scheduled inspection. In addition, Specification 6.8.4.j contains prescriptive requirements concerning inspection intervals to provide added assurance that the SG performance criteria will be met between scheduled inspections.

L-2006-229, Bases Mark up and Inserts Page 11 of 18 INSERT B3/4.4.5 (0-ADM-536 - Technical Specification Bases Control Program)

SR 4.4.5.2 During a SG inspection any inspected tube that satisfies the Steam Generator Program repair criteria is removed from service by plugging. The tube repair criteria delineated in Specification 6.8.4.j are intended to ensure that tubes accepted for continued service satisfy the SG performance criteria with allowance for error in the flaw size measurement and for future flaw growth. In addition, the tube repair criteria, in conjunction with other elements of the Steam Generator Program, ensure that the SG performance criteria will continue to be met until the next inspection of the subject tube(s). Reference 1 provides guidance for performing operational assessments to verify that the tubes remaining in service will continue to meet the SG performance criteria.

The frequency of prior to entering HOT SHUTDOWN following a SG tube inspection ensures that the Surveillance has been completed and all tubes meeting the repair criteria are plugged prior to subjecting the SG tubes to significant primary-to-secondary pressure differential.

References

1.

NEI 97-06, "Steam Generator Program Guidelines"

2.

10 CFR 50 Appendix A, GDC 19

3.

10 CFR 100

4.

ASME Boiler and Pressure Vessel Code,Section III, Subsection NB

5.

Draft Regulatory Guide 1.121, "Bases for Plugging Degraded PWR Steam Generator Tubes," August 1976

6.

EPRI "Pressurized Water Reactor Steam Generator Examination Guidelines"

7.

10 CFR 50.67, "Accident source term"

L-2006-229, Bases Mark up and Inserts Page 12 of 18 INSERT B3/4.4.6.2 (0-ADM-536 - Technical Specification Bases Control Program)

Background

Components that contain or transport the coolant to or from the reactor core make up the Reactor Coolant System (RCS). Component joints are made by welding, bolting, rolling, or pressure loading, and valves isolate connecting systems from the RCS.

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

10 CFR 50, Appendix A, GDC 30 (Ref. 1), requires means for detecting and, to the extent practical, identifying the source of reactor coolant leakage. Regulatory Guide 1.45 (Ref. 2) describes acceptable methods for selecting leakage detection systems.

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.

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 LCO deals with protection of the 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 LCO include the possibility of a loss of coolant accident (LOCA).

Applicable Safety Analyses The primary-to-secondary leakage safety analysis assumption for individual events varies. The assumption varies depending on whether the primary-to-secondary leakage from a single steam generator (SG) can adversely affect the dose consequences for the event. In which case, the affected SG is assumed to have the maximum allowable leakage (500 gallons per day).

Collectively, however, the safety analyses for events resulting in steam discharge to the atmosphere assume that primary-to-secondary leakage from all steam generators (SGs) is 1 gpm total and 500 gallons per day through any one SG accident conditions or increases to these levels as a result of accident conditions. The LCO requirement to limit primary-to-secondary leakage through any one SG to less than or equal to 150 gpd at room temperature is significantly less than the conditions assumed in the safety analysis.

L-2006-229, Bases Mark up and Inserts Page 13 of 18 INSERT B3/4.4.6.2 (0-ADM-536 - Technical Specification Bases Control Program)

Primary-to-secondary leakage is a factor in the dose releases outside containment resulting from a locked rotor accident. To a lesser extent, other accidents or transients involve secondary steam release to the atmosphere, such as a SG tube rupture (SGTR). The leakage contaminates the secondary fluid.

The UFSAR (Ref. 3) analysis for SGTR assumes the contaminated secondary fluid is released to the atmosphere via the atmospheric dump valves and/or main steam safety valves for a limited period of time. Operator action is taken to isolate the affected SG within the time period. The 500 gallons per day primary-to-secondary leakage in each of the two intact SGs at accident conditions in the safety analysis assumption is relatively inconsequential.

Accidents for which the radiation dose release path is primary-to-secondary leakage, the locked rotor accident is more limiting for site radiation dose releases. The safety analysis for the locked rotor accident assumes that primary-to-secondary leakage from all SGs is 1 gpm total. The dose consequences resulting from the locked rotor accident are well within the limits defined in 10 CFR 100 or the NRC approved licensing basis (i.e., a small fraction of these limits).

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

Limiting Condition for Operation (LCO)

RCS operational leakage shall be limited to:

a.

PRESSURE BOUNDARY LEAKAGE No PRESSURE BOUNDARY LEAKAGE is allowed, being indicative of material deterioration. Leakage of this type is unacceptable as the leak itself could cause further deterioration, resulting in higher leakage. Violation of this LCO could result in continued degradation of the RCPB. Leakage past seals and gaskets is not PRESSURE BOUNDARY LEAKAGE.

b.

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

c.

IDENTIFIED LEAKAGE Up to 10 gpm of IDENTIFIED LEAKAGE is considered allowable because leakage is from known sources that do not interfere with detection of UNIDENTIFED 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 seal leak-off (a normal function not considered leakage). Violation of this LCO could result in continued degradation of a component or system.

L-2006-229, Bases Mark up and Inserts Page 14 of 18 INSERT B3/4.4.6.2 (0-ADM-536 - Technical Specification Bases Control Program)

d.

Primary-to-Secondary Leakage Through Any One SG The limit of 150 gpd per SG at room temperature is based on the operational leakage performance criterion in NEI 97-06, Steam Generator Program Guidelines (Ref. 4). 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 SG tube ruptures.

e.

RCS Pressure Isolation Valve Leakage RCS pressure isolation valve leakage is IDENTIFIED LEAKAGE into closed systems connected to the RCS. Isolation valve leakage is usually on the order of drops per minute.

Leakage that increases significantly suggests that something is operationally wrong and corrective action must be taken.

The specified leakage limits for the RCS pressure isolation valves are sufficiently low to ensure early detection of possible in-series check valve failure.

Applicability In MODES 1, 2, 3, and 4, the potential for reactor coolant PRESSURE BOUNDARY LEAKAGE is greatest when the RCS is pressurized.

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

ACTIONS a.

If any PRESSURE BOUNDARY LEAKAGE exists, or primary-to-secondary leakage is not within limit, 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 STANDBY 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.

L-2006-229, Bases Mark up and Inserts Page 15 of 18 INSERT B3/4.4.6.2 (0-ADM-536 - Technical Specification Bases Control Program) b.

UNIDENTIFIED LEAKAGE or IDENTIFIED LEAKAGE in excess of the LCO limits must be reduced to within the limits within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months . This allowable outage 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.

C.

The leakage from any RCS Pressure Isolation Valve is sufficiently low to ensure early detection of possible in-series valve failure. It is apparent that when pressure isolation is provided by two in-series valves and when failure of one valve in the pair can go undetected for a substantial length of time, verification of valve integrity is required.

With one or more RCS Pressure Isolation Valves with leakage greater than that allowed by Specification 3.4.6.2.e, within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months , at least two valves in each high pressure line having a non-functional valve must be closed and remain closed to isolate the affected line(s). In addition, the ACTION statement for the affected system must be followed and the leakage from the remaining Pressure Isolation Valves in each high pressure line having a valve not meeting the criteria of Table 3.4-1 shall be recorded daily. If these requirements are not met, the reactor must be brought to at least HOT STANDBY 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 .

d.

With one or more RCS Pressure Isolation Valves with leakage greater than 5 gpm, the leakage must be reduced to below 5 gpm within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months or the reactor must be brought to at least HOT STANDBY 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 allowable outage times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems. In MODE 5, the pressure stresses acting on the RCPB are much lower, and further deterioration is much less likely.

Surveillance Requirements SR 4.4.6.2.1 Verifying Reactor Coolant System leakage to be within the LCO limits ensures the integrity of the Reactor Coolant Pressure Boundary 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 a Reactor Coolant System water inventory balance.

L-2006-229, Bases Mark up and Inserts Page 16 of 18 INSERT B3/4.4.6.2 (0-ADM-536 - Technical Specification Bases Control Program) a and b.

These SRs demonstrate that the RCS operational leakage is within the LCO limits by monitoring the containment atmosphere gaseous or particulate radioactivity monitor and the containment sump level at least once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

c.

The RCS water inventory balance must be performed with the reactor at steady state operating conditions and near operating pressure. The Surveillance is modified by two notes. Note ***

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

Steady state operations 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 Reactor Coolant Pump seal injection and return flows.

An early warning of PRESSURE BOUNDARY LEAKAGE or UNIDENTIFIED LEAKAGE is provided by the automatic systems that monitor containment atmosphere radioactivity, containment normal sump inventory and discharge, and reactor head flange leak-off. It should be noted that leakage past seals and gaskets is not PRESSURE BOUNDARY LEAKAGE.

These leakage detection systems are specified in LCO 3.4.6.1, "Reactor Coolant System Leakage Detection Systems."

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

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

d.

This SR demonstrates that the RCS operational leakage is within the LCO limits by monitoring the Reactor Head Flange Leak-off System at least once per 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

L-2006-229, Bases Mark up and Inserts Page 17 of 18 INSERT B3/4.4.6.2 (0-ADM-536 - Technical Specification Bases Control Program) e.

This SR verifies that primary-to-secondary leakage is less than or equal to 150 gpd through any one SG. Satisfying the primary-to-secondary leakage limit ensures that the operational leakage performance criterion in the Steam Generator Program is met. If this SR is not met, compliance with LCO 3.4.5, "Steam Generator (SG) Tube Integrity," should be evaluated. The 150-gpd limit is measured at room temperature as described in Reference 5. 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 SR is modified by 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 reactor coolant pump 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. 5).

SR 4.4.6.2.2 It is apparent that when pressure isolation is provided by two in-series check valves and when failure of one valve in the pair can go undetected for a substantial length of time, verification of valve integrity is required. Since these valves are important in preventing overpressurization and rupture of the ECCS low pressure piping, which could result in a LOCA that bypasses containment, these valves should be tested periodically to ensure low probability of gross failure.

This SR verifies RCS Pressure Isolation Valve integrity thereby reducing the probability of gross valve failure and consequent intersystem LOCA. Leakage from the RCS pressure isolation valve.

is IDENTIFIED LEAKAGE and will be considered as a portion of the allowed limit.

References

1. 10 CFR 50, Appendix A, GDC 30

2. Regulatory Guide 1.45, May 1973

3. UFSAR, Section 14.2.4.1

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

5. EPRI "PWR Primary-to-Secondary Leak Guidelines"

L-2006-229 ATTACHMENT 1, Bases Mark up and Inserts (Page 48 of 103)

Page 18 of 18 TECHNICAL SPECIFICATION BASES 3/4.4 REACTOR COOLANT SYSTEM (Continued) 500 gpd through each of the 3/4.4.8 SPECIFIC ACTIVITY two intact steam Qenerators The limitations on the specific activity of the reactor coolan ensure that the resulting 2-hour doses at the rima SITE BOUNDARY will not exceed an appropriately smal fraction of 10 CFR Part 100 dose guideline values following a steam generator tube rupture accident in conjunction with an assumed steady-state tav, *-to-secondary steam generator leakage rate of 4-..

The values for the limits on specific activity represent limits based upon a parametric evaluation by the NRC of typical site locations. These values are conservative in that specific site parameters of the Turkey Point site, Units 3 and 4 site, such as SITE BOUNDARY location and meteorological conditions, were not considered in this evaluation.

The ACTION statement permitting POWER OPERATION to continue for limited time periods with the reactor coolant's specific activity greater than 1 microCurie/gram DOSE EQUIVALENT 1-131, but within the allowable limit shown on Figure 3.4-1, accommodates possible iodine spiking phenomenon which may occur following changes in THERMAL POWER.

The sample analysis for determining the gross specific activity and E can exclude the radioiodines because of the low reactor coolant limit of 1 microCurie/gram DOSE EQUIVALENT 1-131, and because, if the limit is exceeded, the radioiodine level is to be determined every 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months . If the gross specific activity level and radioiodine level in the reactor coolant were at their limits, the radioiodine contribution would be approximately 1%.

In a release of reactor coolant with a typical mixture of radioactivity, the actual radioiodine contribution would probably be about 20%. The exclusion of radionuclides with half-lives less than 30 minutes from these determinations has been made for several reasons. The first consideration is the difficulty to identify short-lived radionuclides in a sample that requires a significant time to collect, transport, and analyze. The second consideration is the predictable delay time between the postulated release of radioactivity from the reactor coolant to its release to the environment and transport to the SITE BOUNDARY, which is relatable to at least 30 minutes decay time. The choice of 30 minutes for the half-life cutoff was made because of the nuclear characteristics of the typical reactor coolant radioactivity.

Based upon the above considerations for excluding certain radionuclides from the sample analysis, the allowable time of 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months between sample taking and completing the initial analysis is based upon a typical time necessary to perform the sampling, transport the sample, and perform the analysis of about 90 minutes. After 90 minutes, the gross count should be made in a reproducible geometry of sample and counter having reproducible beta or gamma self-shielding properties. The counter should be reset to a reproducible efficiency versus energy.

It is not necessary to identify specific nuclides.

The radiochemical determination of nuclides should be based on multiple counting of the sample within typical counting basis following sampling of less than 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months , about 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months , about 1 day, about 1 week, and about 1 month.

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v t e Letter Sequence Response to RAI
TAC:MD0116, Steam Generator Tube Integrity (Open)
Initiation Request Acceptance... Administration Questions Answers 5 December 2006 1 March 2007 Results Approval... Other: ML071580291
MONTHYEAR2006-04-27 [Table View]

L-2006-229, Response to Request for Additional Information - Application for Technical Specification Improvement Regarding Steam Generator Tube Integrity

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