Text

Additional Information for Technical Specification Change 05-09 - Application for Technical Specification Improvement Regarding Steam Generator Tube Integrity and Deletion of License Condition
	ML071010153
Person / Time
Site:	Sequoyah
Issue date:	04/02/2007
From:	Morris G; Tennessee Valley Authority
To:	; Document Control Desk, NRC/NRR/ADRO
References
	TVA-SQN-TS-05-09
	Download: ML071010153 (60)
	v • d • e

Tennessee Valley Authority, Post Office Box 2000, Soddy-Daisy, Tennessee 37384-2000 April 2, 2007 TVA-SQN-TS-05-09 10 CFR 50.90 U.S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, D. C. 20555-0001 Gentlemen:

In the Matter of Docket No. 50-328 Tennessee Valley Authority SEQUOYAH NUCLEAR PLANT (SQN) - UNIT 2 - ADDITIONAL INFORMATION FOR TECHNICAL SPECIFICATION (TS) CHANGE 05 APPLICATION FOR TECHNICAL SPECIFICATION IMPROVEMENT REGARDING STEAM GENERATOR TUBE INTEGRITY AND DELETION OF LICENSE CONDITION

Reference:

NRC letter to TVA dated February 28, 2007, "'Sequoyah Nuclear Plant, Unit 2 - Request for Additional Information Regarding Steam Generator Tube Integrity Technical Specification Amendment (TAC NO. MD0145)"

By the reference letter, NRC staff requested additional information to support staff review of SQN TS Change 05-09. In response to the reference letter, TVA is providing the requested information.

The enclosed information provides TVA responses to NRC questions and includes new TS and TS Bases markups. The new TS and Bases markups reflect discussion with your staff during a February 13, 2007, telephone call. The enclosed markups supersede those previously provided by TVA.

Prinled on recycled paper

U.S. Nuclear Regulatory Commission Page 2 April 2, 2007 provides TVA responses. Enclosure 2 provides the new set of TS page markups. Enclosure 3provides the new set of TS Bases page markups.

TVA's schedule for implementing TS Change 05-09 will be during the Unit 2 Cycle 15 refueling outage (outage scheduled to begin in April 2008) . Accordingly, TVA requests NRC approval by January 2008 to allow for TS implementation during the Unit 2 Cycle 15 refueling outage.

TVA has determined that the enclosed changes do not affect the original evaluation of proposed changes and TVA's review for the no significant hazards considerations provided in TVA's original February 15, 2006, submittal.

Additionally, in accordance with 10 CE'R 50.91(b) (1), TVA is sending a copy of this letter and enclosures to the Tennessee State Department of Public Health.

There are no commitments contained in this submittal.

If you have any questions about this change, please contact me at 843-7170.

I declare under penalty of perjury that the foregoing is true and correct. Executed on this 2nd day of April, 2007.

Sincerely,%

Glenn W. Morris Manager, Site Licensing and Industry Affairs

Enclosures:

1. TVA Responses to NRC Questions

2. New Technical Specification Page Markups

3. New Technical Specification Bases Page Markups cc: See page 3

U.S. Nuclear Regulatory Commission Page 3 April 2, 2007 Enclosures cc (Enclosures):

Mr. Lawrence E. Nanney, Director Division of Radiological Health Third Floor L&C Annex 401 Church Street Nashville, Tennessee 37243-1532 Mr. Brendan Moroney, Senior Project Manager U.S. Nuclear Regulatory Commission Mail Stop 08G-9a One White Flint North 11555 Rockville Pike Rockville, Maryland 20852-2739

ENCLOSURE 1 TENNESSEE VALLEY AUTHORITY SEQUOYAH NUCLEAR PLANT (SQN)

UNIT 2 TVA Responses to NRC Request for Additional Information Regarding SQN TS Change 05-09 NRC Question 1 On page E2-22 of your November 30, 2006, response, the proposed TS 6.8.4.k.d, "Provisions for SG Tube Inspections," contains a statement about, "meeting the requirements of d.1, d.2, d.3, and d.4 below..."

Since there is now a proposed fifth paragraph under this section (i.e., W* Inspection), the statement above should refer to meeting the requirements of d.1, d.2, d.3, d.4, and d.5. Please discuss your plans to modify this statement.

TVA Response TVA has added "and d.5" to the proposed TS 6.8.4.k.d.

NRC Question 2 In Question #4 of the November 7, 2006, RAI, the staff requested that your proposed TS define the abbreviations "ODSCC" (outside diameter stress corrosion cracking) and "TSP" (tube support plate). Proposed TS 6.8.4.k.b.1, page E2-19, spells out the term "outside diameter stress corrosion cracking" but does not follow it with the abbreviation "ODSCC." Therefore, the abbreviation "ODSCC" is still not clearly defined when it is introduced on page E2-20. Also on page E2-20, the abbreviation "GL" is not defined when it is introduced ("GL 95-05 Voltage-Based ARC (Tube Support Plate [TSP])." Please discuss your plans to ensure abbreviations are defined (e.g., words spelled out, followed by abbreviation in parentheses).

TVA Response TVA has added the acronyms "ODSCC" and "GL" where it is appropriate for first time use.

NRC Question 3 In Question #5 of the November 7, 2006, RAI, the staff requested clarification on the descriptions of leakage limits in the proposed TS and TS Bases because they were inconsistent with the TSTF-449 language and appeared incomplete in the way they addressed non-faulted steam generators and alternate repair criteria (ARC).

The proposed TS Bases, on page E3-6 under "Applicable Safety Analyses," now state, "In these analyses, the steam discharge to the atmosphere is based on a primary to secondary leakage of 0.1 gallons E1-I

NRC Question 3 (Continued) per minute (gpm) for the non-faulted SGs and 3.7 gpm for the faulted SG with no more than 1.0 gpm of the 3.7 gpm coming from non-alternate repair criteria." This statement still leaves out the phrase from TSTF-449, "or is assumed to increase to [1.0 gpm or the plant-specific limits] as a result of accident-induced conditions." Please discuss your plans to modify your proposal to reflect that leakage may increase as a result of accident-induced conditions.

In addition, this statement implies that the exceptions to the 1.0 gpm limit are simply based on whether the leakage is addressed by an alternate repair criteria. Although this may currently be the case (i.e., the only exceptions to the 1 gpm limit are for ARC sources), it is possible that the staff could approve exceptions to the 1.0 gpm limit for sources of leakage other than those addressed by ARC and the staff may not permit the leakage from all ARC sources to be excluded from the 1.0 gpm limit. As a result, please discuss your plans to modify this statement to reflect this consideration.

This same paragraph indicates that "This limit [presumably the 3.7 gpm limit] is approved for use for alternate repair criteria (ARC) and W*

leakage calculations." Please discuss your plans to modify this statement per the discussion above regarding exclusions to the 1.0 gpm limit. In addition, it is not clear why the W* leakage calculations are called out separately from other alternate repair criteria. As a result, discuss your plans to clarify this part of the sentence.

This same paragraph indicates that for non-ARC applications, the accident-induced leakage in the faulted steam generator is limited to 1.0 gpm which is bounded by the maximum leakage established by the plant safety analysis. Please discuss your plans to clarify this statement since the accident analysis simply assumes a leakage rate irrespective of the source of the leakage. (The staff notes that the TSTF-449 accident-induced leakage performance criteria imposes restrictions on how much leakage can come from specific sources when satisfying the various aspects of the performance criteria.)

Since similar comments apply to the discussion of the Limiting Condition for Operation (LCO) on page E3-8, please discuss your plans to modify this paragraph consistent with the comments above. In addition, discuss your plans to replace "SG leakage" on page E3-8 with "primary to secondary leakage" to make it consistent with the new terminology introduced in TSTF-449 (and your proposal on pages E2-3 and E2-4).

TVA Response TVA has revised the subject TS Bases paragraph on page E3-6 to describe and clarify SQN's accident analyses assumptions. The following paragraph is added to page E3-6:

"The analysis for design basis accidents and transients other than a SGTR assume the SG tubes retain their structural integrity (i.e.,

they are assumed not to rupture). In these analyses, the steam E1-2

discharge to the atmosphere depends on the accident and whether there are faulted steam generators associated with the accident.

For a steamline break (SLB), the maximum primary to secondary leakage under accident conditions is limited to 3.7 gpm from the faulted SG and 0.1 gpm from each of the non-faulted SGs. Of the 3.7 gpm primary to secondary leak rate assumed during the SLB, no more than 1.0 gpm can come from sources that have not been specifically exempted from the 1.0 gpm limit by the NRC. The leakage attributed to the flaws left in service as a result of implementing TS 6.8.4.k.c.l and .2 have been exempted from the 1.0 gpm limit by the NRC staff. For other accidents that assume a faulted SG (e.g., feedwater line break), the maximum primary to secondary leakage under accident conditions is limited to 1.0 gpm from the faulted SG and 0.1 gpm from each of the non-faulted SGs.

For accidents in which there are no faulted SGs, the primary to secondary leakage is limited to 0.1 gpm from each SG. For accidents that do not involve fuel damage, the primary coolant activity level of DOSE EQUIVALENT 1-131 is assumed to be equal to the LCO 3.4.8, "Specific Activity," limits. For accidents that assume fuel damage, the primary coolant activity is a function of the amount of activity released from the damaged fuel. The dose consequences of these events are within the limits of GDC 19 (Ref. 2), 10 CFR 100 (Ref.3), or the NRC approved licensing basis."

In addition, TVA has revised the subject TS Bases paragraph on page E3-8 as follows:

"The accident induced leakage performance criterion ensures that the primary to secondary leakage caused by the design basis accident, other than a SGTR, is within the accident analysis assumptions. The accident analyses assumptions are discussed in the Applicable Safety Analyses section. 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."

NRC Question 4 In Question #17 of the November 7, 2006, RAI, the staff asked for clarification regarding the discussion in the Bases on maintaining tube integrity. The staff's concern was that the discussion should be clear about the need to maintain integrity of all tubes in service.

Since the "ACTIONS" in proposed TS 3.4.5 only directly address flawed tubes inadvertently left in service following an inspection, the Bases should clarify that integrity must be maintained for all tubes in service. The latest proposal, in the "ACTIONS" section on page E3-9, adds a phrase stating that the tube integrity requirement, "applies to any SG tube; plugged or not plugged." This suggests that in order to operate the plant you will be required to demonstrate the integrity of even those tubes already removed from service due to flaws. Please discuss your plans to clarify this explanation in your Bases of the requirement to maintain tube integrity (i.e., applies to any SG tube, either inadvertently not plugged or left in service in accordance with the approved repair criteria).

E1-3

TVA Response TVA has incorporated the staff's comment and replaced the proposed TS Bases language "(applies to any SG tube; plugged or not plugged)" with

"(applies to any SG tube, either inadvertently not plugged or left in service in accordance with the approved repair criteria)."

NRC Question 5 In Question #19 of the November 7, 2006, RAI, the staff noted that the entire paragraph on page E3-12 beginning with, "Wastage-type defects

...... " was essentially replaced with TSTF-449. Your response proposes to delete the first sentence of the paragraph.

Please discuss your plans to remove this paragraph from your Bases.

TVA Response TVA has revised the TS markup to remove the entire paragraph beginning on page E3-12.

NRC Question 6 In Question #20 of the November 7, 2006, RAI, the staff asked for clarification of the leakage sources used in an equation for calculating postulated steam line break leakage on page E3-13 in the proposed TS Bases. In your response, the title of the section containing this equation was changed to, "Calculation of Accident Leakage for Voltage-Based Alternate Repair Criteria (ARC)." This title does not match the calculation because the calculation includes postulated leakage from the W* ARC, which is not a voltage-based ARC.

In addition, the title, "Postulated steam line break (SLB) leakage" for the equation on page E3-13 is misleading since it only represents postulated leakage associated with implementation of the GL 95-05 and W* ARC. Also on page E3-13, the definition of "ARCGL95-0 5 " is not completely accurate because it is the leakage from predominantly axially oriented ODSCC indications as determined in accordance with the ARC, and from the results of the SG tube inspections. The proposal defines "ARCGL gs-os" as the "normal SLB leakage derived from ARC methods and the SG tube inspections."

Lastly, the final paragraph of this section (page E3-14) is not clear in that (1) the combined leak rate from all sources must be less than the leak rate limit (i.e., not just the leak rate from all ARC); and (2) the term "above assumed leakage" does not appear to be necessary.

Please discuss your plans'to clarify this paragraph.

TVA Response TVA has revised the TS Bases pages E3-13 and E3-14 to clarify the equation titles and to clarify the accident induced leak rates from all sources. The elements of the equation are revised as follows:

c) Calculation of Operational Assessment (OA) Accident Induced Leakage E1-4

The postulated leakage during a Steam Line Break (SLB) shall be equal to the following equation:

Postulated SLB OA Leakage = ARC GL 95-0S + Assumed Leakage 0, <TTS

+ Assumed Leakage 8- <TTS + Assumed Leakage >12- <TTS + All other sources of accident induced primary to secondary leakage Where: ARC GL 95-05 is the SLB OA leakage for predominantly axially oriented outside diameter stress corrosion cracking indications as determined by the methodology described in GL 95-05.

Assumed Leakage 0- <TTS is the postulated OA leakage for undetected indications in SG tubes left in service between 0 and 8 inches below the TTS.

Assumed Leakage 8- <TTS is the conservatively assumed OA leakage from the total of identified and postulated unidentified indications in SG tubes left in service between 8 and 12 inches below the TTS. This is 0.0045 gpm multiplied by the number of indications. Postulated unidentified indications will be conservatively assumed to be in one SG. The highest number of identified indications left in service between 8 and 12 inches below TTS in any one SG will be included in this term.

Assumed Leakage >12" <TTS is the conservatively assumed OA leakage for the bounding SG tubes left in service below 12 inches below the TTS. This is 0.00009 gpm multiplied by the number of tubes left in service in the least plugged SG.

All other sources of accident induced primary to secondary leakage is the primary to secondary accident induced OA leakage from all other degradation mechanisms other than the voltage based axial ODSCC at tube support plates repair criteria and W*

leakage calculations as determined by the Operational Assessment.

d) Calculation of Condition Monitoring (CM) Accident Induced Leakage The postulated leakage during a SLB shall be equal to the following equation and is performed for each steam generator:

Postulated SLB CM Leakage = ARC GL 95-05 + Assumed Leakage 0" <TTS

+ Assumed Leakage 8"-2" <TTS + Assumed Leakage >12" <TTS + All other sources of accident induced primary to secondary leakage Where: ARC GL95-05 is the SLB CM leakage for predominately axially oriented ODSCC indications determined by the methodology described in GL 95-05.

Assumed Leakage 0, <TTS is the postulated CM leakage for indications detected in SG tubes between 0 and 8 inches below the TTS.

Assumed Leakage 8- <TTS is the conservatively assumed CM leakage from the total of identified and postulated unidentified indications in SG tubes left in service between 8 and 12 inches below the TTS. This is 0.0045 gpm multiplied by the number of indications.

E1-5

Assumed Leakage >12" <TTS is the conservatively assumed CM leakage for the bounding SG tubes in service 12 inches below the TTS.

This is 0.00009 gpm multiplied by the number of tubes left in service in the SG.

All other sources of accident induced primary to secondary leakage is the primary to secondary accident induced CM leakage from all other degradation mechanisms other than the voltage based axial ODSCC at tube support plates repair criteria and W*

leakage calculations as determined by Condition Monitoring.

The aggregate calculated accident induced primary to secondary SLB leakage from the application of all ARC and the accident induced leakage from all other sources shall be reported to the NRC in accordance with Technical Specification 6.9.1.16.4. The combined calculated leak rate from all ARC and all other sources of accident induced leakage must be less than the accident induced leakage rate assumed in the SLB accident analyses.

NRC Question 7 As a result of this review, the staff also noted the following editorial comments:

a. Proposed TS 6.8.4.k.b.3 on page E2-19, refers to the "Limiting Condition of Operation (LCO) 3.4.6.2." The staff notes that LCO 3.4.6.2 is actually called "Limiting Condition for Operation," which is the terminology established in 10 CFR 50.36. Please discuss your plans to correct this typographical error.

b. On page E2-20 (proposed TS 6.8.4.k.c.1), "'plugging limit" should be replaced with "repair criteria" given the new terms used in TSTF-449.

c. On page E2-21 (proposed TS 6.8.4.k.c.2) the first sentence is not needed since the repair criteria is in the next sentence, and "below the top of the tubesheet (TTS)" is not needed in the second sentence since the W* distance is defined below. (Please note if "TTS" is deleted, it should be redefined in proposed TS 6.8.4.k.c.2.a.)

d. In the second sentence of the last full paragraph on page E3-12, the word "indications" seems unnecessary.

e. In the second paragraph on page E3-13, the term "'orrepaired" should be removed since no repair methods are authorized for Sequoyah Unit 2.

TVA Response TVA incorporated each of the suggested editorial comments.

E1-6

NRC Question 8 In Question #22 of the November 7, 2006, RAI, the staff indicated that the wording was not consistent with TSTF-449. As a result, you modified the wording; however, it is still inconsistent with TSTF-449 since it does not reflect that leakage may increase as a result of accident conditions and it refers to "maximum normal operational leakage" (rather than primary-to-secondary leakage). Lastly, it is still not clear whether your accident analysis assumes 1 gpm leakage from all SGs or 0.4 gpm from all SGs (see #22 in the previous RAI and

3 above). If your normal operational leakage limit is equal to your accident-induced leakage limit, please confirm that controls are in place to ensure that the accident-induced leakage limit is not exceeded as a result of possible increases in the normal operating leakage rate from higher loadings during postulated accident conditions. That is, the leak rate observed during normal operation may increase under design basis accident loading conditions. As a result, it may be necessary to keep the normal operating leakage rate significantly below the normal operating leakage rate limit to avoid exceeding the accident-induced leakage limit in the event a postulated accident were to occur.

TVA response TVA revised the TS Bases (see page E3-18 of Enclosure 3) to read as follows:

"assume that primary to secondary leakage from all steam generators (SGs) is 0.4 gallons per minute (gpm) or increases to 0.4 gpm as a result of accident induced conditions (0.1 gpm per SG is equivalent to 150 gallons per day per SG)."

It may be noted that TVA administratively limits operational primary to secondary leakage to values significantly less than those values assumed in the accident analyses. In the event of a postulated accident, these administrative limits provide margin and are intended to prevent primary to secondary leakage from exceeding the accident induced leakage limit.

NRC Question 9 On page E3-17 of your November 30, 2006, response, you refer to ARC SLB leakage. The meaning of these statements is not clear since the accident analysis simply assumes a leakage rate irrespective of the source of the leakage. (The staff notes that the TSTF-449 accident induced leakage performance criteria imposes restrictions on how much leakage can come from specific sources when satisfying the various aspects of the performance criteria.) Please discuss your plans to clarify these statements.

TVA Response TVA revised the TS Bases (see page E3-19 of Enclosure 3) to change "ARC SLB accident" to "SLB accident."

E1-7

ENCLOSURE 2 TENNESSEE VALLEY AUTHORITY SEQUOYAH NUCLEAR PLANT (SQN)

UNIT 2 New TS Page Markups for TS Change 05-09 E2-1

d. Failure to complete any tests included in the described program (planned or scheduled) for power levels up to the authorized power level.

(4) Monitoring Settlement Markers (SER/SSER Section 2.6.3)

TVA shall continue to monitor the settlement markers along the ERCW conduit for the new ERCW intake structure for a period not less than three years from the date of this license. Any settlement greater than 0.5 inches that occurs during this period will be evaluated by TVA and a report on this matter will be submitted to the NRC.

(5) Tornado Missiles (Section 3.5)

Prior to startup after the first refueling of the facility, TVA shall reconfirm to the satisfaction of the NRC that adequate tornado protection is provided for the 480 V transformer ventilation systems.

(6) Desigqn of Seismic Category Structures (Section 3.8)

Prior to startup following the first refueling, TVA shall evaluate all seismic Category I masonry walls to final NRC criteria and implement NRC required modifications that are indicated by that evaluation.

(7) Low Temperature Overpressure Protection (Section 5.2.2)

Prior to startup after the first refueling, TVA shall install an overpressure mitigation system which meets NRC requirements.

(8) Steam Generator Inspection (Section 5.3.1)

(a) Prior to start-up after the first refueling, TVA shall install inspection ports in each steam generator or have an alternative for inspection that is acceptable to the NRC.

(b) By May WA..shall establish a steam genera ronprogram that is in accordance wE it in Enclosure 2 to the TVA letter to the Commils . s subject a 12, 1997, as modified by WV edMarchl17,1997.

(9) Containment Isolation Systems (Section 6.2.4)

Prior to startup after the first refueling, TVA shall modify to the satisfaction of the NRC the one-inch chemical feed lines to the main and auxiliary feedwater lines for compliance with GDC 57.

(10) Environmental Qualification (Section 7.2.2)

a. No later than June 30, 1982, TVA shall be in compliance with the requirements of NUREG-0588, "Interim Staff Position on Environmental Qualification of Safety-Related Electrical Equipment," for safety-related equipment exposed to a harsh environment.

April 9, 1997 Amendment No. 2, 213 E2-2

DEFINITIONS IDENTIFIED LEAKAGE 1.16 IDENTIFIED LEAKAGE shall be:

a. Leakage, such as that from pump seals or valve packing (except reactor coolant pump seal injection or leakoff) that is captured and conducted to collection systems or 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 system.

MEMBER(S) OF THE PUBLIC /

(primary to secondary leakage) 1.17 DELETED OFFSITE DOSE CALCULATION MANUAL 1.18 The OFFSITE DOSE CALCULATION MANUAL (ODCM) shall contain the methodology and parameters used in the calculation of offsite doses resulting from radioactive gaseous and liquid effluents, in the calculation of gaseous and liquid effluent monitoring alarm/trip setpoints, and in the conduct of the Radiological Environmental Monitoring Program. The ODCM shall also contain (1) the Radioactive Effluent Controls and Radiological Environmental Monitoring Programs required by Section 6.8.4 and (2) descriptions of the information that should be included in the Annual Radiological Environmental Operating and Annual Radioactive Effluent Release Reports required by Specifications 6.9.1.6 and 6.9.1.8.

OPERABLE - OPERABILITY 1.19 A system, subsystem, train, or 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, a normal and an emergency electrical power source, 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).

February 11, 2003 SEQUOYAH - UNIT 2 1-4 Amendment Nos. 63, 134, 146,159, 165, 169,250, 272 E2-3

DEFINITIONS OPERATIONAL MODE - MODE 1.20 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 1.1.

PHYSICS TESTS 1.21 PHYSICS TESTS shall be those tests performed to measure the fundamental nuclear characteristics of the reactor core and related instrumentation and 1) described in Chapter 14.0 of the FSAR, 2) authorized under the provisions of 10 CFR 50.59, or 3) otherwise approved by the Commission.

__rmarttosecondary LEAKAGE PRESSURE BOUNDARY 1.22 PRESSURE BOUNDARY LEAKAGE shall be leakage (except steam generator tube leakage) through a non-isolable fault in a Reactor Coolant System component body, pipe wall or vessel wall.

PRESSURE AND TEMPERATURE LIMITS REPORT (PTLR) 1.23 The PTLR is the unit specific document that provides the reactor vessel pressure and temperature limits, including heatup and cooldown rates and the LTOP arming temperature, for the current reactor vessel fiuence period. These pressure and temperature limits shall be determined for each fluence period in accordance with Specification 6.9.1.15.

PROCESS CONTROL PROGRAM (PCP) 1.24 DELETED PURGE - PURGING 1.25 PURGE or PURGING is the 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.

QUADRANT POWER TILT RATIO 1.26 QUADRANT POWER TILT RATIO shall be the ratio of the maximum upper excore detector calibrated output to the average of the upper excore detector calibrated outputs, or the ratio of the maximum lower excore detector calibrated output to the average of the lower excore detector calibrated outputs, which-ever is greater.

September 15, 2004 SEQUOYAH - UNIT 2 1-5 Amendment No. 63, 134, 146, 191, 223, 284 E2-4

7~Remove Pages 3/4 4-10 through -16 and replace with INSERT A.

REACTOR COOLANT SYSTEM 345STEAM GENERATORS LIMITIRI CONDITION FOR OPERATION 3.4.5 Each earn generator shall be OPERABLE.

APPLICABILI . MODES 1, 2, 3 and 4.

ACTION:

With one r e enera ors inoperable, restore the inoperable generator(s) t OPERABLE status prior to increasing Tavg abo e 200 0 F.

SURVEILLANCE REQUIREME S 4.4.5.0 Each steam generator shall demonstrated OPERABLE by p ormance of the following augmented inservice inspection progra and the requirements of Spe fication 4.0.5.

4.4.5.1 Steam Generator Sample Selectio and Inspection - Eac team generator shall be determined OPERABLE during shutdown by selecting an inspecting at lea /the minimum number of steam generators specified in Table 4.4-1.

4.4.5.2 Steam Generator Tube Sample Selection d Ins ction - The steam generator tube minimum sample size, inspection result classification, and the rr sponding action required shall be as specified in Table 4.4-2. The inservice inspection of steam gener r tubes shall be performed at the frequencies specified in Specification 4.4.5.3 and the inspected s hall be verified acceptable per the acceptance criteria of Specification 4.4.5.4. The tubes selecte for eac inservice inspection shall include at least 3%

of the total number of tubes in all steam generat s; the tube selected for these inspections shall be selected on a random basis except:

a. Where experience in similar ants with similar water emistry indicates critical areas to be inspected, then at least 5000 of the tubes inspected sha be from these critical areas.

b. The first sample of tub selected for each inservice inspec on (subsequent to the preservice inspectio of each steam generator shall include:

QUOYAH - UNIT 2 3/4 4-10 E2-5

RECTRCOLNT SYSTEM/

RVEILLANCE REQUIREMENTS (Continued) 1 All nonplugged tubes that previously had detectable wall penetrations (greater than 20%).

2. ubes in those areas where experience has indicated potential problems.

3. A tu e inspection (pursuant to Specification 4.4.5.4.a.8) shall be performed on eac selected tube. any selected tube does not permit the passage of the eddy current probe r a tube inspecti , this shall be recorded and an adjacent tube shall be selected and s jected to a tube in sp eCctio n,

4. Indications le fn service as a result of application of the tube support pla voltage-based repair criteria shall be spected by bobbin coil probe during all future refuelin outages.

c. The tubes selected as the econd and third samples (if required by Table .4-2) during each inservice inspection may be subjecte o a partial tube inspection provided:

1. The tubes selected for the samples include the tubes from ose areas of the tube sheet array where tubes with imperfecti s were previously found.

2. The inspections include those p ions of the tubes wh e imperfections were previously found.

Note: Tube degradation identified in th portion of th ube that is not a reactor coolant pressure boundary (tube end up to the sta f the tub to-tubesheet weld) is excluded from the Result and Action Required in Table 4.4-2.

d Implementation of the steam generator tube/tube port plate repair criteria requires a 100 percent bobbin coil inspection for hot-leg and cold-leg t e s port plate intersections down to the lowest cold-leg tube support plate with known outside di, eter str s corrosion cracking (03CC) indications.

The determination of the lowest cold-leg tu esupport pI intersections having 003CC indications shall be based on the performance of at ast a 20 percen andom sampling of tubes inspected over their full length.

e Implementation of the steam gener tor WEXTEX expanded regi inspection methodology (W*)

requires a 100 percent rotating c I probe inspection of the hot leg besheet W* distance.

The results of each sample in ection shall be classified into one of the follo ing three categories:

Category Inspection Results C-1 Less than 5% of the total tubes inspected are degr ed tubes and none of the inspected tubes are defective.

EQUOYAH - Unit 2 3/4 4-11 Amendment No. 181, 211, 213, 243, 291 E2-6

S VILNERQUIREMENTS (Continued) . .. .. p C-2 Onedefective, are or more tubes, but not5%

or between more and than 10%1% of the of the total total tubes tubes ins inspee eare degraded tubes.

More than 10% of the total tubes inspected are degrade ubes or more than 1% of the inspected tubes are defective.

Not In all inspections, previously degraded tubes must exhibit ignificant (greater than 10%) further wall penetrations to be included in th above percentage calculations.

April 3, 1996 S QUOYAH - UNIT 2 3/4 4-11a Amendment No. 181, 11 E2-7

\tEACTOR COOLANT SYSTEM /

SR LAC REQUIREMENTS (Continued) 4.4.*5.3 In.skection Feunis- The above required inservice, inspections of steam generator tub s shall be perform at the following frequencies:/

a. The fir inservice inspection shall be performed after 6 Effective Full Power Month ut within 24 calen ar months of initial criticality. Subsequent inservice inspections shall b erformed at intervals o not less than 12 nor more than 24 calendar months after the previo inspection. If two consec uve inspections following service under AVT conditions, not inclu ng the preservice inspection, re It in all inspection results falling into the C-1 category or if consecutive inspections dem nstrate that previously observed degradation has not co inued and no additional degrad ion has occurred, the inspection interval may be ext ded to a maximum of once per 40 months.

b. If the results of the inse ice inspection of a steam generator cond cted in accordance with Table 4.4-2 at 40 month i ervals fall in Category C-3, the inspe ion frequency shall be increased to at least once p r 20 months. The increase in ins ction frequency shall apply until the subsequent inspections s isfy the criteria of Specificatio 4.4.5.3.a; the interval may then be extended to a maximum of onc er 40 months.

c. Additional, unscheduled inservice i pections shall be erformed on each steam generator in accordance with the first sample insp ction specified n Table 4.4-2 during the shutdown subsequent to any of the following con tions:

1. Primary-to-secondary tubes leaks (n t i luding leaks originating from tube-to-tube sheet welds) in excess of the limits of Speci tion 3.4.6.2.

2. A seismic occurrence greater than e Op rating Basis Earthquake.

3. A loss-of-coolant accident req iring actuation f the engineered safeguards.

4. Amain steam line orfeed terlinebreak.

S UNT UOAH 23/4 4-12 E2-8

\,* ACTOR COOLANT SYSTEM SUR\EILLANCE REQUIREMENTS (Continued) 4.4.5.4 cce tance Criteria

a. A used in this Specification:

1. Imperfection means an exception to the dimensions, finish or contour of o ,abe from that hquired by fabrication drawings or specifications. Eddy-current testing i dications below 2 of the nominal tube wall thickness, if detectable, may be consider d as imp ections.

2. De rad ion means a service-induced cracking, wastage, wear o general corrosion occurring n either inside or outside of a tube.

3. Deqraded Tu means a tube containing imperfections gre er than or equal to 20% of the nominal wall thi ness caused by degradation.

4. % Degradation me s the percentage of the tube wal ickness affected or removed by degradation.

5. Defect means an imperfe tion of such severity t t it exceeds the plugging limit. A tube containing a defect is defe *ve.

6. Plugging Limit means the impe ection dep at or beyond which the tube shall be removed from service and is eq I to 401 of the nominal tube wall thickness. Plugging limit does not apply to that portion t tube that is not within the pressure boundary of the reactor coolant system (tube en p to the start of the tube-to-tubesheet weld). This definition does not apply to tube su plate intersections if the voltage-based repair criteria are being applied. Refer 4.4. . .a.10 for the repair limit applicable to these intersections. This definiition d s not app to service induced degradation identified in the W* distance. Service ird ed degradati identified in the W* distance below the top-of-tube sheet (TTS), tshallb plugged on dete ion.

7. Unserviceable describe the condition of a tube i 'leaks or contains a defect large enough to affect its str ctural integrity in the event an Operating Basis Earthquake, a loss-of-coolant acci nt, or a steam i ne or feedwater *ne break as specified in 4.4.5.3. c, above.

8. Tube Ins ecti means an inspection of the steam generat tube from the point of entry (hot leg side Ompletely around the U-bend to the top suppo of the cold leg excluding e portion of the tube within the tubesheet below th distance, the tube to tubeshe weld and the tube end extension.

9. Pres ice In cinmeans an inspection of the full length of each be in each steam ge rator performed by eddy current techniques prior to service to est lish abaseline dition of the tubing. This inspection shall be performed prior to initial OWER PERATION using the equipment and techniques expected to be used d 'ng subsequent inservice, inspections.

May 3, 2 5 SE OYAH - UNIT 2 3/4 4-13 Amendment No. 181, 211, 213, 243, 266, 2 E2-9

\ REACTOR COOLANT SYSTEM /

SRVEILLANCE REQUIREMENTS (Continued) z

0. Tube Support Plate Plugging Limit is used for the disposition of an alloy 600 steam generator tube for continued service that is experiencing predominately axially ori ted outside diameter stress corrosion cracking confined within the thickness of the t e support plates. At tube support plate intersections, the plugging (repair) limit is based n aintaining steam generator tube serviceability as described below:

a. Steam generator tubes, whose degradation is attributed to outsid iameter stress corrosion cracking within the bounds of the tube support plate w' bobbin voltages I s than or equal to the lower voltage repair limit (Note 1), wil e allowed to remain in rvice.

b. Steam enerator tubes, whose degradation is attributed outside diameter stress corrosio cracking within the bounds of the tube suppo plate with a bobbin voltage greater th the lower voltage repair limit (Note 1), w e repaired or plugged, exceptasn ed in 4.4.5.4.a.10.c below.

c. Steam generat tubes, with indications of pote ial degradation attributed to outside diameter stress c rosion-cracking within the ounds of the tube support plate with a bobbin voltage gre er than the lower volta repair limit (Note 1), but less than or equal to upper voltag repair limit (Note 2 , may remain in service if a rotating pancake coil inspection oes not detect egradation. Steam generator tubes, with indications of outside dia eter stress rrosion-cracking degradation with a bobbin coil voltage greater than th upper tage repair limit (Note 2) will be plugged or repaired.

d. Not applicable to SQN.

e. If an unscheduled mid-cyc inspecti n is performed, the following mid-cycle repair limits apply instead of th imits identifi din 4.4.5.4.a.10.a, 4.4.5.4.a.10.b, and 4.4.5.4.a.10.c.

The mid-cycle repair limits are determi d from the following eq tions:

VMURL

=VSL (CL -At) 1.0 +NDE +Gr-CL VMLJ,= VUR _(VtRL - VLRL) (CL-_ At)

/ __9'9CL April 9, 997 QUOYAH - UNIT 2 3/4 4-14 Amendment No. 28, 211, 13 E2-10

r ATO COOLANT SYSTEM S VL pevleREQUIREMENTS (Continued)

VuRL = upper voltage repair limit VLRL = lower voltage repair limit VMURL mid-cycle upper voltage repair limit based on time into cycle VMLRL = mid-cycle lower voltage repair limit based on VMURL and ti into cycle At = ngth of time since last scheduled inspection during ich VURL and VLRL were ilemented CL = cycle ngth (the time between two scheduled st m generator inspections)

VSL = structural mit voltage Gr = average gro rate per cycle length NDE 95-percent cumu tive probability allo ance for nondestructive examination uncertainty (i.e., a lue of 20-perc t has been approved by NRC)

Implementation of these mid-cycle repair limits s uld foll the same approach as in TS 4.4.5.4.a.10.a, 4.4.5.4.a.10.b, and 4.4.5.4.a.10.c.

Note 1: The lower voltage repair limit is 1.0 vol 3/4-inch diameter tubing or 2.0 volts for 7/8-inch diameter tubing.

Note 2: The upper voltage repair limit is Iculated ac rding to the methodology in GL 95-05 as supplemented. VURL may diffe t the TSPs and ow distribution baffle.

11. a) Bottom of WEXTEX ransition (BWT) is the h hest point of contact between the tube and tubeshe at, or below the top-of-tube eet, as determined by eddy current testing.

b) The W* dist ce is the larger of the following two dis nces as measured from the top-of-the- besheet (US): (a) 8 inches below the TT or (b) 7 inches below the bottom o he WEXTEX transition plus the uncertainty as ciated with determining the dis nce below the bottom of the WEXTEX transition a defined by c) Length is the length of tubing below the bottom of the WE transition WT), which must be demonstrated to be non-degraded in order r the tube to maintain structural and leakage integrity. For the hot leg, the W* len th is 7.0 inches which represents the most conservative hot-leg length defined in WC -14797, Revision 2.

b. The steam generator shall be determined OPERABLE after completing the corres nding actions (plug all tubes exceeding the plugging limit and all tubes containing through- all cracks) required by Table 4.4-2.

May 3, 2 5 QUOYAH - UNIT 2 3/4 4-14a Amendment No. 28, 211, 213, 243, 2 E2-11

\REACTOR COOLANT SYSTEM /

SUVEILLANCE REQUIREMENTS (Continued) 4.4.5.5 Reports

a. Following each inservice inspection of steam generator tubes, the number of tube plugged each steam generator shall be reported to the Commission within 15 days.

b. Th complete results of the steam generator tube inservice inspection shall e submitted to the mmission in a Special Report pursuant to Specification 6.9.2 within 2 months followin the completion of the inspection. This Special Report shall inc de:

1. Numb r and extent of tubes inspected.

2. Location d percent of wall-thickness penetration for eac ndication of an imperfectio

3. Identification of bes plugged.

c. Results of steam genera r tube inspections which fal nto Category C-3 shall be reported as a degraded condition purs nt to 10 CFR 50.73 pri to resumption of plant operation. The written followup of this repo shall provide a descr tion of investigations conducted to determine cause of the tube d radation and co. ective measures taken to prevent recurrence.

d. For implementation of the voltage-b ed r air criteria to tube support plate intersections, notify the staff prior to returning the st generators to service should any of the following conditions arise:

1. Leakage is estimated based the pr *cted end-of-cycle (or if not practical using the actual measured end-of-cy e) voltage tribution. This leakage shall be combined with the postulated leakage r ulting from the i plementation of the W* criteria to tubesheet inspection depth. If th otal projected end- -ycle accident induced leakage from all sources exceeds the akage limit (determine from the licensing basis dose calculation for the postulated in steam line break) for the ext operating cycle, the staff shall be notified.

2. If circumfere al crack-like indications are detected a he tube support plate

3. If indii ons are identified that extend beyond the confines f the tube support plate.

4. If i ications are identified at the tube support plate elevations at are attributable to p ary water stress corrosion cracking.

5. Ifthe calculated conditional burst probability based on the projected d-of-cycle (or~if not practical, using the actual measured end-of-cycle) voltage distributi n exceeds 1 X 10-2 , notify the NRC and provide an assessment of the safety significanc of the occurrence.

SEQUOYAH - UNIT 2 3/4 4-14b Amendment No. 28, 211, 213, 267, 2 E2-12

SUR(ELLANCE REQUIREMENTS (Continued)

'ECOCOLANT SYSTEMer

e. T~t calculated steam line break leakage from the application of tube support plate altert rep

criteria and W* inspection methodology shall be submitted in a Special Report i accor nce with 10 CFR 50.4 within 90 days following return of the steam generator to service (MOD-). The report will include the number of indications within the tubesheet r ion,the location the indications (relative to the bottom of the WEXTEX transition (BWT and TTS),

the orienta n (axial, circumferential, skewed, volumetric), the severity of each'i dication (e.g.,

near throughl, all or not through-wall), the side of the tube from which the in ation initiated (inside or outsi e diameter), and an assessment of whether the results wer consistent with expectations wit respect to the number of flaws and flaw severity (and if ot consistent, a description of the oposed corrective action).

QUOYAH - UNIT 2 3/4 4-14c Amendment No. 243,1 E2-1 3

"I TABLE 4.4-1 MINIMUM NUMBER OF STEAM GENERATORS TO BE INSPECTED DURING INSERVICE INSPECTION

) Inspection No Yes on I

.L Table Notation:

1. The inservice ins ction may be limited to one steam ge rator on a rotating schedule encompassing 3 N of the tubes (where N is the num r of steam generators in the plant) if the results of the fir or previous inspections indica that all steam generators are performing in a like ma er. Note that under some i cumstances, the operating conditions in one or more steam ge rators may be found to e more severe than those in other steam generators. Under such cir umstances the sam e sequence shall be modified to inspect the most severe conditions.

2. The other steam generator not i ected ring the first inservice inspection shall be inspected. The third and subseque t ins ctions should follow the instructions described in 1 above.

3. Each of the other two steam gener ors ot inspected during the first inservice inspections shall be inspected during the se d and ird inspections. The fourth and subsequent inspections shall follow the inst ctions des bed in 1 above.

S UOYAH - UNIT 2 3/4 4-15 E2-14

TABLE 4.4-2 STEAM GENERATOR TUBE INSPECTION T SAMPLE INSPECTION 2 ND SAMPLE INSPECTION 3 RD SAMP E

____ INSPEC ION Sample esult Action Required Result Action Required Result Action Size _.__ Required A minimum C-1 None N/A N/A N// N/A of S Tubes _ . /

per S.G.

C-2 PIl defective tubes C-1 None N/A N/A and i pect additional Plug defective tubes C-1 None 2S tub in this S.G. C-2 and inspect additional 4S 4 tubes in this S.G _ _

C-2 Plug defective tubes C-3 Perform action for C-3 result

___of first sample Perforrn ction for C-3 C-3 resutf first sample N/A N/A C-3 Inspect all tubes in All ýher this S.G. plug S.G None N/A N/A defective tubes and C-1 inspect 2S ___

tubes in each other Some Perform action for C-2 S.G. S/G -2 sult of second sample N/A N/A buy o \

ditional S-3O. are

Additional Inspect alltbes in each S/G is C-3 S.G. and plu!defective N/A N/A S = 3N% Where N is th umber of steam generators in the unit, and n i he number of steam generators' spected during an inspection.

May 24,2 2 SEQUOYAH - UNIT 2 3/4 4-16 Amendment No. 28, 26 E2-15

INSERT A 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 Steam Generator Program.

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

ACTIONS*:

a. With one or more SG tubes satisfying the tube repair criteria and not plugged in accordance with the Steam Generator Program, within 7 days verify tube integrity of the affected tube(s) is maintained until the next refueling outage or SG tube inspection, or 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 .

AND

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

SURVEILLANCE REQUIREMENTS 4.4.5.0 Verify steam generator tube integrity in accordance with the Steam Generator Program.

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

Separate Action entry is allowed for each SG tube.

SEQUOYAH - UNIT 2 3/4 4-10 E2-16

REACTOR COOLANT SYSTEM OPERATIONAL LEAKAGE LIMITING CONDITION FOR OPERATION 3.4.6.2 Reactor Coolant System leakage shall be limited to:

a. No PRESSURE BOUNDARY LEAKAGE,

b. 1 GPM UNIDENTIFIED LEAKAGE,

c. 150 gallons per day of primary-to-secondary leakage through any one steam generator, and

d. 10 GPM IDENTIFIED LEAKAGE from the Reactor Coolant System.

APPLICABILITY: MODES 1, 2, 3 and 4 or with primary-to-secondary leakage not within limits, ACTION:

a. With anv PRESSURE BOUNDARY LEAKAG . 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 leakage greater than any one of the above limits, excluding PRESSURE BOUNDARY LEAKAGE reduce the leakage rate to within limits Verify within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months or be in at least HOT STANDBY 'ithin 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 . - .

or primary-to-seondary leakage SUNR GILlANEREQUIREMENTS lthi I 4.4.6.2.ý Reactor Coolant System leakageshall hbA erified to be 'within each of th* above limits b y

performance of a Reactor Coolant System water inventory balance at least once per 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months .*

The provision of Specification 4.0.4 are not applicable for entry into MODE 3 or 4.

4.4.6.2.2 Verify steam gnA.... tor..tube i R acco,÷,,rd,.A.n..

, with the requirements of Technical IG~;aTR345 "ta 8~;tr; Verify primary-to-secondary leakage is *150 gallons per day through any one steam Venerator at least once per 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months .*

I The above surveillance requirement is not applicable to I primary-to-secondary leakage. I

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

August 4, 2000 SEQUOYAH - UNIT 2 3/4 4-18 Amendment No. 211,213,250 E2-17

ADMINISTRATIVE CONTROLS

b. Air lock testing acceptance criteria are:

1) Overall air lock leakage rate is _ 0.05 La when tested at _>Pa.

2) For each door, leakage rate is _ 0.01 La when pressurized to > 6 psig for at least two minutes.

The provisions of SR 4.0.2 do not apply to the test frequencies specified in the Containment Leakage Rate Testing Program.

The provisions of SR 4.0.3 are applicable to the Containment Leakage Rate Testing Program.

i. Confi-quration Risk Management Pro-gram (DELETED)

j. Technical Specification (TS) Bases Control Progqram This program provides a means for processing changes to the Bases of these TSs.

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

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

1. A change in the TS incorporated in the license or

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

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

d. Proposed changes that meet the criteria of Specification 6.8.4.j.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). INSERT 6.9 REPORTING REQUIREMENTS ROUTINE REPORTS 6.9.1 In addition to the applicable reporting requirements of Title 10, Code of Federal Regulations, the following reports shall be submitted in accordance with 10 CFR 50.4.

STARTUP REPORT 6.9.1.1 DELETED 6.9.1.2 DELETED 6.9.1.3 DELETED February 11, 2003 SEQUOYAH - UNIT 2 6-10 Amendment No. 28, 50, 64, 66, 134, 207,223,231,271,272 E2-18

INSERT B from all sources, excluding the leakage attributed to the

k. Steam Generator (SG) Program degradation described in 6.8.4.k.c.1 and .2, 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 aidor plugged, to confirm that the performance criteria are being met. except for flaws addressed through

b. Provisions for Performance Criteria for SG Tube Integrity. application of the alternate repair criteria discussed in TS 6.8.4.k.c.1, SG tiube integrity shall be maintained by meeting the performance criteria for tube struc tural integrity, accident induced leakage, and operational leakage.

Structural integrity performance criterion: All in-service SG tubes shall retain For predominantly structural integrity over the full range of normal operating conditions (includir axially oriented startup, operation in the power range, hot standby, cooldown, and all antici ated outside diameter transients included in the design specification) and design basis accidents (DBAs).

stress corrosion This includes retaining a safety factor of 3.0 against burst under normal s eady cracking (ODSCC) state full power operation primary-to-secondary pressure differential and safety at the tube support factor of 1.4 against burst applied to the DBA primary-to-secondary pressure plate elevations, differentials. Apart from the above requirements, additional loading conditions (refer to 6.8.4.k.c.1) associated with the DBAs, or combination of accidents in accordance with the the probability of design and licensing basis, shall also be evaluated to determine if the associated burst (POB) of one loads contribute significantly to burst or collapse. In the assessment of tube or more indications integrity, those loads that do significantly affect burst or collapse shall be given a steam line determined and assessed in combination with the loads due to pressure with a break shall be less safety factor of 1.2 on the combined primary loads and 1.0 on axial secondary than 1 x 102. lo a d s . I __ n I f- . .. k ,,f kh -.. f. 1_f*,, ,, I z

~4II I J 'J . I

JI ll IIu J I I I l I LI IUI IJ I -II%

UIL U . .JI 0J'

2. Accident induced leakage performance crite '." The accident induced leakage not to exceed 1.0 gpm for the faulted Scý*xcept for oti diam.t.r trs 3.7 gallons p.. minUte (gpm). The primary-to-secondary accident induced leakage rate for any DBA, other than a SG tube rupture, shall not exceed the leakage rate assumed in the accident analysis in terms of total leakage rate for all SGs and leakage rate for an individual SG.

3. The operational leakage performance criterion is specified in Limiting Condition for Operation (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.

E2-19

INSERT B 1The following alternate tube repair criteria (ARC) may be applied as an alternative to the 40% depth based criteria: r . .. .ri NRC Generic Letter (GL) 95-05 Voltaqcl4eWs eRC (Tube Support Plate [TSPI)

A voltage-based TSP pugg-ng li, *fsed for the disposition of an alloy 600 SG tube for continued service that is exo encing predominately axially oriented ODSCC confined within the thickn of the tube support plates (TSPs). At TSP intersections, the §l~gi~g (.pa*F)--Ih4 is based on mnainta5inig SC, tube seFViGeabiliy-a& described below:

a) SG tubes, whose degradation is attributed to DSCC within the bounds of the TSP with bobbin voltages less than or equa t F (Netes-)will be allowed to remain in servi e.

b) SG tubes, whose degradation is attribu d to ODS within the bounds of the TSP with a bobbin voltage greater than F lm " ,

will be F ah ed-9F plugged, except as noted in Item elow.

6.8.4.k.c.1.c) c) SG tubes, with indications of potential degradation attrib ted to ODSCC wi in I3~i the bounds of the TSP with a bobbin voltage greater than repair imit (Note !}- but less than or equal to+ pper voltage repair Hi may remain in service if a rotating pancake coil inspectiog does n tdetect deraaion.I SG tubes with indications of ODSCC defadatior ith a bobbin coil voltage greater than the upper voltage repair!Wi I 4984ee-*will be plugged, d) G Fe or comparable technology e) If an unscheduled mid-cycle inspection is performed, the following mid-cycle repair limits apply instead of the limits identified in Items -

The mid-cycle repair limits are determined from the followin equations:

VMu*= VSL (CL- 6.8.4.k.c.1.a), b), c), and .d).

!.O+NDE+Gr_

CL (calculated according to the SVLR) (CL-At) methodology in GL 95-05 as VMLRL = VMURL CL supplemented) where:

VURL = upper voltage repair limit VLRL - lower voltage repair limit VMURL = mid-cycle upper voltage repair limit based on time into cycle VMLRL = mid-cycle lower voltage repair limit based on VMURL and time into cycle E2-20

INSERT B At length of time since last scheduled inspection during which VURL and VLRL were implemented CL cycle length (the time between two scheduled SG inspections)

VSL structural limit voltage Gr average growth rate per cycle length NDE 95 percent cumulative probability allowance for nondestructive examination uncertainty (i.e., a value of 20 percent has been approved by 1 6.8.4.k.c.1 .a), .b), .c) and .d). I MIPCI Implemeniation of these mid-cycle repair limits should follow the same approach as in TS items4 hIn1tR I - ThR IA~rF V,.*lt I0.; ; 1~*;( v t1 fo*r 214A ;nc-h diamete*÷r flh; .b*n 2.0 VoVlts ll 7 diameter bIng.

Infor,8i lNote 2:. The u, or Vol*tAe rorpiar inmit is calculated accordi;ng to the methodolog,

'I-.JR may diffor at tho TSPs And flow I I in Uas suppIe-mnten.

distributionR baffle.

nhe accIGoni loa~ago Wmit approved for - "_A.14M ane ;-; tor A.WPW cA_;uai4 ioaHao ; IsN4 1.7 -7 ii ; + ; +k -F R A C fý_

V W* Methodolovqy flaws

' . ." ... ..th

. e... . . ... . .. w , ". . . . - . . .

444~*~44-I44~4~-- I [11-I IrTlIlIf]IfI[JIII:J[ItlrI iii utiut I IUL :iUL1I'~ iu I;RUIiL IIULCQ UIUIII ietidithe I..

distance. Service induced iidentified in the W*

distance belo t..he to.p oftubohet9.(,*- shall be plugged on detection. Th4 Flaws located inspctin of h 21 tube...s. is from the point of entr' (hot log side) completely ar.ou.nd the below the W* U,bond- tote top supr f the coAld leg exclu1ding the portion of the tub wihAI thin the8 distance may remain in 8XtG1-10.1-service regardless of The following terms/definitions apply to the W*.

size.

a) Bottom of WEXTEX Transition (BWT) is the highest point of contact between the tube and tubesheet at, or below the top of tubesheet (TTS), as determined by eddy current testing.

b) W* Distance is the larger of the following two distances as measured from the TTS: (a) 8 inches below the l-S or (b) 7 inches below the bottom of the WEXTEX transition plus the uncertainty associated with determining the distance below the bottom of the WEXTEX transition as defined by WCAP-14797, Revision 2.

E2-21

INSERT B G) iW*

-/

-lenopthis the lonath of tubingpt- be~lowý the- boftoAm of the BWA.T w~hich mAust

J i i I J f II I I i be demonstrpated to be non degraaed in ord-er To r* hle tu-e to m.a.nta'n Ft,,r, ,- -,,-+- .

-'t A- 97^r +Hý- hM. Iý +k,ý %A!* 1ý,-,h ,,7 Q *A which reo-rosonts the moSt conRser.ative hot lea length define i l1*,1l "I*L.I "111 lid/ I../*,11*'1/'*1"1 "*t The postulated leakage resultiRg from the implementation of the vltage-based repair critAr to TS intersections shall hb combined With the postulated leakage resul-ting from tho imni....n÷-ition of W* critorin to t,-jhosht ins~nction donth

d. Provisions for SG Tube Inspections. d.4 and d.5 Periodic SG tube inspections shall be perform . The number and portions of the tubes inspected and methods of inspection shall b erformed with the objective of detecting flaws of any type (e.g., volumetric flaws, axi I and circumferential cracks) that may be W* Inspectio n present along the length of the tube, from e tube-to-tubesheet weld at the tube inlet to the tube-to-tubesheet weld at the tube o0 let, and that may satisfy the applicable tube When the W repair criteria. The tube-to-tubesheet Id is not part of the tube. In addition to meeting methodology the requirements of d.1, d.2, aRd d.3, elow, the inspection scope, inspection methods, has been and inspection intervals shall be such as to ensure that SG tube integrity is maintained implemented until the next SG inspection. An assessment of degradation shall be performed to inspect 100 determine the type and location of flaws to which the tubes may be susceptible and, percent of th e based on this assessment, to determine which inspection methods need to be employed inservice and at what locations.

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

region with 2. Inspect 100% of the tubes at sequential periods of 60 effective full power the objective months. The first sequential period shall be considered to begin after the first of detecting inservice inspection of the SGs. No SGs shall operate for more than 24 flaws that effective full power months or one refueling outage (whichever is less) without may satisfy being inspected.

the applicabl e 3. If crack indications are found in any SG tube, then the next inspection for each tube repair SG for the degradation mechanism that caused the crack indication shall not criteria of TS exceed 24 effective full power months or one refueling outage (whichever is 6.8.4.k.c.2. 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 E4V not be treated as a crack.

every 24 effective full power months or GL 95-05 Voltage-Based ARC for TSP every refueling outage, whichever is less.

Indications left in service as a result of application o the TSP voltage-based repair criteria shall be inspected by bobbin coil probe ur, all future refueliq Implementation of the SG tube/TSP repair criteria requires a 100 percent bobbin coil inspection for hot-leg and cold-leg TSP intersections down to the lowest cold-leg TSP with known ODSCC indications. The determination of the lowest cold-leg TSP intersections having ODSCC indications shall be based on DElK the performance of at least a 20 percent random sampling of tubes inspected over their full length.

E2-22

.INSERT B N ~W* METHODOLOGY IS MOVED TO

"**Methodolo~qg REPAIR CRITERIA SECTION (c) ABOVE]

Imletton ote S ETXexpanded region inspect ion methodo, y(*

requires 100 percent rotating coil probe inspection of the hot-leg tube feet W*

distance. Tbe implementation of W* does not apply to service induc, d degradation identified in th W* distance. Service induced degradation identif' in the W*

distance below t top-of-tubesheet (TTS) shall be plugged on etection. The inspection of SG tu s is from the point of entry (hot-leg sid completely around the U-bend to the top sup of the cold leg excluding the p ion of the tube within the tubesheet below the W* 'tance, the tube-to-tubeshe weld and the tube outlet end extension.

The following terms/definitions ap to the d) Bottom of WEXTEX Transiti WT) is the highest point of contact between the tube and tub eet or below the TTS, as determined by eddy current testing.

e) W* Distance is t larger of the following distances as measured from the TTS: (a) 8 ches below the TTS or (b) 7 1 hes below the bottom of the WEXTEX tr sition plus the uncertainty associa with determining the distance elow the bottom of the WEXTEX transitio as defined by WCA -14797, Revision 2.

f)

Length is the length of tubing below the bottom of the BT which must be demonstrated to be non-degraded in order for the tube to m tain structural and leakage integrity. For the hot leg, the W* length is . inches which represents the most conservative hot leg length defined in WCAP-1 4797, Revision 2.

e. Provisions for Monitoring Operational Primary-to-Secondary Leakage.

E2-23

ADMINISTRATIVE CONTROLS CORE OPERATING LIMITS REPORT (continued)

6. WCAP-10054-P-A, Westinghouse Small Break ECCS Evaluation Model Using the NOTRUMP Code, August 1985, & Proprietary)

(Methodology for Specification 3/4.2.2 - Heat Flux Hot Channel Factor)

7. WCAP-10266-P-A, Rev. 2, "THE 1981 REVISION OF WESTINGHOUSE EVALUATION MODEL USING BASH CODE", March 1987, (W Proprietary).

(Methodology for Specification 3.2.2 - Heat Flux Hot Channel Factor).

8. BAW-10227P-A, "Evaluation of Advance Cladding and Structural Material (M5) in PWR Reactor Fuel," February 2000, (FCF Proprietary)

(Methodology for Specification 3/4.2.2 - Heat Flux Hot Channel Factor) 6.9.1.14.b The core operating limits shall be determined so that all applicable limits (e.g., fuel thermal-mechanical limits, core thermal-hydraulic limits, ECCS limits, nuclear limits such as shutdown margin, and transient and accident analysis limits) of the safety analysis are met.

6.9.1.14.c THE CORE OPERATING LIMITS REPORT shall be provided within 30 days after cycle start-up (Mode 2) for each reload cycle or within 30 days of issuance of any midcycle revision of the NRC Document Control Desk with copies to the Regional Administrator and Resident Inspector.

REACTOR COOLANT SYSTEM (RCS) PRESSURE AND TEMPERATURE LIMITS (PTLR)

REPORT 6.9.1.15 RCS pressure and temperature limits for heatup, cooldown, low temperature operation, criticality, and hydrostatic testing, LTOP arming, and PORV lift settings as well as heatup and cooldown rates shall be established and documented in the PTLR for the following:

Specification 3.4.9.1, "RCS Pressure and Temperature (P/T) Limits" Specification 3.4.12, "Low Temperature Over Pressure Protection (LTOP) System" 6.9.1.15.a The analytical methods used to determine the RCS pressure and temperature limits shall be those previously reviewed and approved by the NRC, specifically those described in the following documents:

1. Westinghouse Topical Report WCAP-1 4040-NP-A, "Methodology used to Develop Cold Overpressure Mitigating System Setpoints and RCS Heatup and Cooldown Limit Curves."

2. Westinghouse Topical Report WCAP-1 5321, "Sequoyah Unit 2 Heatup and Cooldown Limit Curves for Normal Operation and PTLR Support Documentation."

3. Westinghouse Topical Report WCAP-1 5984, "Reactor Vessel Closure HeadNessel Flange Requirements Evaluation for Sequoyah Units 1 and 2."

6.9.1.15.b The PTLR shall be provided to the NRC within 30 days of issuance of any revision or supplement thereto.

SPECIAL REPORTS 6.9.2.1 Special reports shall be submitted within the time period specified for each report, in accordance with 10 CFR 50.4.

6.9.2.2 This specification has been deleted.

September 15, 2004 SEQUOYAH - UNIT 2 6-14 Amendment Nos. 44, 50, 64, 66, 107, 134, 146, 206, 214, 231, 249, 284 E2-24

initial entry into MODE 4 following INSERT C completion of an inspection performed in accordance with Specification 6.8.4.k, "Steam Generator (SG) Program."

STEAM GENERATOR (SG) TUBE INSPECTION REPORT 6.9.1.16.1 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.k, "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 when havebeen

h. The effective p3u1 ng percentage for all plugg'*hgin each SG.

6.9.1.16.2 A report shall be bmitted within 90 days after the in'tial entry into MODE 4 following completion otfi inspection performed in accordancg with the steam generator program (6.8.4.k) a,4l-voltage based alternate repair criteria ij applied. The report shall include information described in Section 6.b of Attachment 1 to NRC Generic Letter 95-05, "Voltage-Based Repair Criteria for Westinghouse Steam Generator Tubes Affected by Outside Diameter Stress Corrosion Cracking."

i.. For implementation of the voltage-based repair criteria for tube support plate (TSP) intersections, notify the staff prior to .etu1.in..the-...to *.. e-F.. Ge should any of the following conditions arise:

I*I '~ I k~ire i" e~timitnd h~wed on the projected end

-. . .-.------ of cycle (orif not 11 Leakane 06 e4mated ba6ed 9R leakage shall be combined l.lith the postulated leakage reulting fFrom the i f t,4L* IA*I* ;.*i ; ~ L - 4- A - . 4 I I S VI 44-'SL* S L 4 1 prP 11 U~t.Pt_

A PIIU A 1 G. GVGIe ~aGIE19IIL .4 i1_IGPtU A

leava

- I 11 II~UL~ 6LL1~1 II I I IQ II f I

I

I I I i* f II inc iicen~~ino n~i~ r1o~~c c~icumon ~or inc liearI iimir nothe iem~oc inc ýdeiem lneG irom 1m-1t rncicrminen ------..----.---. ~---------------...

Trei frn thicne re~naitin9496e the swtien mhr v*, ./

k +fi A EL k 2- If circumferential crack-like indications are detected at the TSP intersections.

E2-25

INSERT C

' 3,-4 If indications are identified that extend beyond the confines of the TSP.

4-)- If indications are identified at the TSP elevations that are attributable to primary water stress corrosion cracking.

6.9.1.16.41

5) if the calculated cnioalburst probability based On the projected end-of cycle (Or if not practical, using the actual measured end of cycle) voltage distribution exceeds 1 X 104, notif,' the NRC and provide an assessment of the safety significance of the occurrence.-

ý-For implementation of W*, the calculated steam line break leakage from the after the initial application of TSP alternate repair criteria and W* inspection methodology entry into MODE shall be submitted in a Special Report in accordance with 10G GFIR 50.4 within 4 following 90 day folov.ing return of the SGs to ser'ice (MOIDE-4). The report will completion of an inc e the number of indications within the tubesheet region, the location of inspection eindications (relative to the bottom of the WEXTEX transition [BWT] and performed in TTS), the orientation (axial, circumferential, skewed, volumetric), the severity accordance with of each indication (e.g., near through-wall or not through-wall), the side of the Specification tube from which the indication initiated (inside or outside diameter), and an 6.8.4.k, "Steam assessment of whether the results were consistent with expectations with Generator (SG) respect to the number of flaws and flaw severity (and if not consistent, a Program." description of the proposed corrective action).

E2-26

ENCLOSURE 3 TENNESSEE VALLEY AUTHORITY SEQUOYAH NUCLEAR PLANT (SQN)

UNIT 2 New TS Bases Page Markups for TS Change 05-09 E3-1

REACTOR COOLANT SYSTEM I BASES 3/4.4.5 STEAM GENERATORS The Surveillance Requirements for inspection of the steam generator tubes ensure that the s ctural integrity of this portion of the RCS will be maintained. The program for inservice inspe ion of stea generator tubes is based on a modification of Regulatory Guide 1.83, Revision 1. Inse ice inspec n of steam generator tubing is essential in order to maintain surveillance of the co itions of the tubes in e event that there is evidence of mechanical damage or progressive degradati due to design, manufactur errors, or inservice conditions that lead to corrosion. Inservice inspectio of steam generator tub also provides a means of characterizing the nature and cause of an tube degradation so that correctiv measures can be taken.

The plant is e ected to be operated in a manner such that the secon ry coolant will be maintained within thos hemistry limits found to result in negligible corrosi of the steam generator tubes. If the secondary cant chemistry is not maintained within these inits, localized corrosion may likely result in stress corrosi cracking. The extent of cracking during ant operation would be limited by the limitation of steam generat tube leakage between the primary olant system and the secondary coolant system (primary-to-seco ary leakage = 150 gallons per y per steam generator). Cracks having a primary-to-secondary lea e less than this limit dunn operation will have an adequate margin of safety to withstand the loads impos d during normal opera' n and by postulated accidents. Sequoyah has demonstrated that primary-to-secon ary leakage of 15 gallons per day per steam generator can readily be detected by radiation monitors osteam gener or blowdown or condenser off-gas. Leakage in excess of this limit will require plant shutdow and an scheduled inspection, during which the leaking tubes will be located and plugged.

The voltage-based repair limits of SR 4. . i lement the guidance in GL 95-05 and are applicable only to Westing house-desig ned st m gen ators (SIGs) with outside diameter stress corrosion cracking (ODSCC) located at the be-to-tube pport plate intersections. The voltage-based repair limits are not applicable to other fo s of S/G tube d radation nor are they applicable to ODSCC that occurs at other locations within th /G. Additionally, the epair criteria apply only to indications where the degradation mechanism i dominantly axial ODSCC 'th no significant cracks extending outside the thickness of the supp plate. Refer to GL 95-05 for a ditional description of the degradation morphology.

Implementatiion of '4.4.5 requires a derivation of the voltage str cural limit from the burst versus voltage empirical orrelation and then the subsequent derivation of t voltage repair limit from the structural limit (which i then implemented by this surveillance).

The volta structural limit is the voltage from the burst pressure/bobbin vo ge correlation, at the 9 5 perc-ent pre tion interval curve reduced to account for the lower 95/95 percent to rance bound for tubin mater properties at 650'F (i.e., the 95 percent LTL curve). The voltage structu I limit must be adjusted d nward to account for potential flaw growth during an operating interval and to ccount for NDE un rtainty. The upper voltage repair limit; VURL, is determined from the structural volta limit by applyi gthe following equation:

VURL = VSL - VGR - VNDE April 9, 1997 SEQUOYAH - UNIT 2 B 3/4 4-3 Amendment No. 181, 211, 213 E3-2

REACTOR COOLANT SYSTEM BASES ere VGR represents the allowance for flaw growth between inspections and VNDE represents the allowance for po ntial sources of error in the measurement of the bobbin coil voltage. Further discussion of the assumptio nece ary to determine the voltage repair limit are discussed in GL 95-05.

mid-cycle equation of SR 4.4.5.4.a.10.e should only be used during unplanned inspection i which edd current datasacquired for indications at the tube support plates.

SR 4.4. 5 implements several reporting requirements recommended by GL 95-05 for si ations which NRC wants to be notifie prior to returning the S/Gs to service. For SR 4.4.5.5.d., Items 3 and 4, in i*tions are applicable only wher alternate plugging criteria is being applied. For the purposes of this re orting requirement, leakage and condition burst probability can be calculated based on the as-found voltage istribution rather than the projected end-of-cycl] voltage distribution (refer to GL 95-05 for more information) w en it is not practical to complete these calculation sing the projected EOC voltage distributions prior to ret ing the S/Gs to service.

Note that if leakage and con donal burst probability were calculated using the mea red EOC voltage distribution for the purposes of addressing Sections 6.a.1 and 6.a.3 reporting criteria, the he results of the projected EOC voltage distribution should be pro ed per GL Section 6.b(c) criteria.

Wastage-type defects are unli ly with proper chemistry treatment f the secondary coolant. However, even if a defect should develop in servic it will be found during schedul inservice steam generator tube examinations. Plugging will be required fo 11tubes with imperfection exceeding the repair limit defined in Surveillance Requirement 4.4.5.4.a. The po on of the tube that the lugginglimit does not apply to is the portion the tube that is not within the RCS pressure bo dary (tube end u to the start of the tube-to-tubesheet weld). The tube end to tube-to-tubesheet weld portion of the be does not ect structural integrity of the steam generator tubes and therefore indications found in this portion f the tub will be excluded from the Result and Action Require for tube inspections. It is expected that any indication that xtend from this region will be detected during the scheduled tube inspections. Steam generator tube insp ions of operating plants have demonstrated the capabilit to reliably detect degradation that has penetrated 20% original tube wall thickness.

Tubes experiencing outside diameter stre corrosion acking within the thickness of the tube support plat are plugged or repaired by the criteria of 4.4.5.4 .10.

The W* criteria incorporate the guid ce provided in WCAP- 797, Revision 2, "Generic W* Tube Plugging Criteria for 51 Series Steam Generator T esheet Region WEXTEX Ex nsions." W* length is the length of tubing into the tubesheet below the bottom of e WE)(TEX transition (BWT) tha recludes tube pullout in the event of a complete circumferential separation the -tube below the W* length. W* dii nce is the distance from the top of thE tubesheet to the bottom of the W* I gth including the distance from the top o he tubesheet to the BWT and measurement uncertainties.

Indications detected ithin the W* distance below the top-of-tube sheet (TT will be plugged upon detection. Tubes to which CAP-14797 is applied can experience through-wall degra tion up to the limits definec in Revision 2 withou i asing the probability of a tube rupture or large leakage eventa edgaaino n type or extent below distance, including a complete circumferential separation f the tu is acceptable. As applied at Sequoya uclear Plant Unit 2, the W* methodology is used to define the required be inspection depth into the hot-leg tu esheet, and is not used to permit degradation in the W* distance to remain iniN ervice. Thus whil(

pri mary to seco dary leakage in the W* distance need not be postulated, primary to secondary le7 age from potential deg, dation below the W* distance will be assumed for every inservice, tube in the bound in steam g /enerator.Ma SE OYAH - UNIT 2 B 3/4 4-3a Amendment No. 181, 211, 213, 243, 291 3,20 E3-3

REACTOR COOLANT SYSTEM BASES he postulated leakage during a steam line break shall be equal to the following equation:

Postulated SLB Leakage = ARC GL 95-05 + Assumed Leakage o.-8, <TTs + Assumed Leaka 8'-12' <TTS

+ Assum Leakage ,12- <TTS Where: C GL 95-05 is the normal SLB leakage derived from alternate repair crit a methods and the steam generat tube inspections.

Assumed Leakag *,8- <TrS is the postulated leakage for undetected i ications in steam generato tubes left in service between and 8 inches below the top of the tubesh Assumed Leakage 12" <TTS the conservatively assumed akage from the total of identified and postulated unidentified indications in s m generator tubes lef service between 8 and 12 inches belo%

the top of the tubesheet. This is 0.0045 g multiplied by t number of indications. Postulated unidentified indications will be conservatively sumed t e in one steam generator. The highest number of identified indications left in service be e and 12 inches below TTS in any one steam generator will be included in this term.

Assumed Leakage >12" <,TS is the co ervatively ass ed leakage for the bounding steam generator tubes left in service bellow 12 J ches below the top o he tubesheet. This is 0.00009 gpm multiplied by the number of tubes le service in the least plugg steam generator.

The aggregate calcula SLB leakage from the application of al ternate repair criteria and the above assumed leakage s I be reported to the NRC in accordance with a licable Technical Specifications. The co mned calculated leak rate from all alternate repair crite i must be less than the maximum allowable eamn line break leak rate limit in any one steam generator in der to maintain doses within 10 100 guideline values and within GDC-1 9 values during a postula dsteam line break event.

May 3, 2005 SEQUOYAH - UNIT 2 B 3/4 4-3b Amendment No. 213, 243, 267, 291 E3-4

INSERT D B 3.4 REACTOR COOLANT SYSTEM B 3/4.4.5 Steam Generator (SG) Tube Integrity BASES BACKGROUND Steam generator (SG) tubes are small diameter, thin walled tubes that carry primary coolant through the primary to secondary heat exchangers. The SG tubes have a number of important safety functions. Steam generator tubes are an integral part of the reactor coolant pressure boundary (RCPB) and, as such, are relied on to maintain the primary system's pressure and inventory. The SG tubes isolate the radioactive fission products in the primary coolant from the secondary system. In addition, as part of the RCPB, the SG tubes are unique in that they act as the heat transfer surface between the primary and secondary systems to remove heat from the primary system. This specification addresses only the RCPB integrity function of the SG. The SG heat removal function is addressed by Limiting Condition of Operation (LCO) 3.4.1.1, "Startup and Power Operation," LCO 3.4.1.2, "Hot Standby," LCO 3.4.1.3, "Shutdown," and LCO 3.4.1.4, "Cold Shutdown."

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

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

Specification 6.8.4.k, "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.k, 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.k. 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).

SEQUOYAH - UNIT 2 B 3/4 4-3 E3-5

INSERT D licensing

,or the NRC basis.

approved BASES APPLICABLE The steam generator tube rupture (SGTR) accident is the limiting design SAFETY basis event for SG tubes and avoiding an SGTR is the basis for this ANALYSES specification. The analysis of an SGTR event assumes a bounding primary to secondary leakage rate equal to the operational leakage rate limits in LCO 3.4.6.2 "Operational Leakage," plus the leakage rate associated with a double-ended rupture of a single tube. The accident analysis for a SGTR assumes the contaminated secondary fluid is released to the atmosphere via safety valves. The main condenser isolates based on an assumed concurrent loss of off-site power.

The analysis for design basis accidents and transients other than a SGTR assume the SG tubes retain their structural integrity (i.e., they are assumed not to rupture).

In these analyses, the steam discharge to the atmospher.is basod on a p"imar, to rG Ioaklnes andarv f 0h1 trgll naolted S(Th md 37 X_ 44, C- i 14,ý .4 C1 fl -r"' A -F th no more/

(A ne' %dA!* 10 cýIitoR o o R nlctsn

-- a-,

tho mcnidont I..- -

th 1.Og of !ARG! -... Z-.-a*-.........................-A ogr .L . . L- 4L--

the 3. mn *s F r accidents that do comi ot n e fuel damage, the primary coolant activity level of D SE EQUIVALENT non tem e I is assumed to be equal to the LCO 3.4.8, "Specific Activit " limits. For r air criteri ccidents that assume fuel damage, the primary coolant activity i a function of the/

amount of activity released from the damaged fuel. The dose con equences of these events are within the limits of GDC 19 (Ref. 2), 10 CFR 100 ef. 3),

I NET E I Steam generator tube integrity satisfies Criterion 2 of 10 CFR

"--,.0.36(c)(2)(ii).

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

During an SG inspection, any inspected tube that satisfies the Steam Gen rator 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 st I have tube integrity.

In the context of this specification, a SG tube is defined as the entire length of t e tube, including the tube wall, between the tube-to-tubesheet weld at the tube inl t and the tube-to-tubesheet weld at the tube outlet. The tube-to-tubesheet weld is not considered part of the tube.

depends on the accident and whether there are faulted SGs associated with the accident. For a steamline break (SLB), the maximum primary to secondary leakage under accident conditions is limited to 3.7 gpm from the faulted SG and 0.1 gpm from each of the non-faulted SGs. Of the 3.7 gpm primary-to-secondary leak rate assumed during the SLB, no more than 1.0 gpm can come from sources that have not been specifically exempted from the 1.0 gpm limit by the NRC. The leakage attributed to the flaws left in service as a result of implementing TS 6.8.4.k.c.1 and .2 have been exempted from the 1.0 gpm limit by the NRC staff. For other accidents that assume a faulted SG (e.g., feedwater line break), the maximum primary to secondary leakage under accident conditions is limited to 1.0 gpm from the faulted SG and 0.1 gpm from each of the non-faulted SGs. For accidents in which there are no faulted SGs, the primary to secondary leakage is limited to 0.1 gpm from each SG.

SEQUOYAH - UNIT 2 B 3/4 4-3a E3-6

INSERT D BASES LCO (continued)

A SG tube has tube integrity when it satisfies the SG performance criteria. The SG performance criteria are defined in Specification 6.8.4.k, "Steam Generator Program," and describe acceptable SG tube performance. The Steam Generator Program also provides the evaluation process for determining conformance with the SG performance criteria.

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

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

SEQUOYAH - UNIT 2 B 3/4 4-3b E3-7

INSERT D BASES I Analyses The accident section.

analyses assumptions are discussed in the Applicable Safety I LCO (continued)

The accident induced leakage p rformance criterion ensures that the primary to I secondary leakage caused by a sign basis accident, other than a SGTR, is within the accident analysis assumptions. In the main stoam lino broak (MSLB) analysis for. ARC, SG leakago iasue to be 3.7 gp. for the faulted G .d gpm for an, 0..1 thnn auted S G-. Limiting the allowable leakage in the faulted- SSG to 1.0 gpm

-tor nRo / "e catin e*nplurAs thAP hilb-anl Lu sis remansy conrsle

':,' d , he accident induced leakage rate includes any primary to

" h no more th secondary*akage existing prior to the accident in addition to primary to secondary 1.0 m of t h .7 leakagei duced during the accident. The 3.7 gpm is approed for use in ARC gpm co from appi titons Where the cracks are limited to lecations within the tubesheet or within non- ema . . )4 plate.

re ircciteria.

/ 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, "Operational Leakage," and limits primary to secondary leakage through any one SG to 150 gallons per day. This limit is based on the assumption that a single crack leaking this amount would not propagate to a SGTR under the stress conditions of a loss-of-coolant accident (LOCA) or a MSLB. If this amount of leakage is due to more than one crack, the cracks are very small, and the above assumption is conservative.

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

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

ACTIONS The ACTIONs are modified by a clarifying footnote that Action (a) may be entered independently for each SG tube. This is acceptable because the actions provide appropriate compensatory measures 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 of associated actions.

SEQUOYAH - UNIT 2 B 3/4 4-3c E3-8

INSERT D BASES ACTIONS (continued)

Actions (a) and (b)

Action (a) applies if it is discovered that one or more SG tubes examined in an inservice inspection satisfy the tube repair criteria but were not plugged in accordance with the Steam Generator Program as required by SR 4.4.5.1. An evaluation of SG tube integrity of the affected tube(s) must be made. Steam generator tube integrity is based on meeting the SG performance criteria described in the Steam Generator Program. The SG repair criteria define limits on SG tube degradation that allow for flaw growth between inspections while still providing assurance that the SG performance criteria will continue to be met. In order to determine if a SG tube that should have been plugged has tube integrity, an evaluation must be completed that demonstrates that the SG performance criteria will continue to be met until the next refueling outage or SG tube inspection. The tube integrity determination is based on the estimated condition of the tube at the the situation is discovered and the estimated growth of the degradation prior to I refueling outage or the nex inspection. If it is determined that tube integrity is not being maintained until the ne SG inspection, Action (a) requires unit shutdown and However, the Action (b) requires the affected tube(s) be plugged.

affected tube(s)

An allowed time of 7 days is sufficient to complete the evaluation while minimizing must be plugged the risk of plant operation with a SG tube that may not have tube integrity.

prior to startup following the next If the evaluation determines that the affected tube(s) have tube integrity, Action (a) refueling outage or allows plant operation to continue until the next refueling outage or SG inspection SG inspection. provided the inspection interval continues to be supported by an operational assessment that reflects the affected tubes.+This allowed time is acceptable since operation until the next inspection is supported by the operational assessment.

IG tube integrity is not being maintained he reactor-must be brought to HOT NDBY within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and COLD SHUTD)WN within the next 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months and the I evaluation at any time,determines affected tube(s) plugged prior to restart i *. i ~(Mode 4;:)_.

r-f 0Rg o1t .ge e

)d FA-f.

The action times are reasonable, based on operatin xperience, to reach the desired plant condition from full power in an orderly ma ner and without challenging plant systems.

(applies to any SG tube;o' ... . 'Wg....) I either inadvertently not plugged or left in service in accordance with the approved repair criteria.

SEQUOYAH - UNIT 2 E3-9

INSERT D BASES SURVEILLANCE SR 4.4.5.0 REQUIREMENTS During shutdown periods the SGs are inspected as required by this SR and the Steam Generator Program. NEI 97-06, Steam Generator Program Guidelines (Ref.

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, nondestructive examination (NDE) technique capabilities, and inspection locations.

The Steam Generator Program defines the frequency of SR 4.4.5.0. 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.k contains prescriptive requirements concerning inspection intervals to provide added assurance that the SG performance criteria will be met between scheduled inspections.

SEQUOYAH - UNIT 2 B 3/4 4-4 E3-10

INSERT D BASES SURVEILLANCE REQUIREMENTS (continued)

SR 4.4.5.1 During an SG inspection, any inspected tube that satisfies the Steam Generator Program repair criteria is removed from service by plugging. The tube repair criteria delineated in Specification 6.8.4.k 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 this surveillance 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.

r (i.e., prior to HOT SHUTDOWN following a SG tube inspection)

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

2. 10 CFR 50 Appendix A, GDC 19.

3. 10CFR100.

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

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

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

SEQUOYAH - UNIT 2 B 3/4 4-4a E3-11

INSERT E Voltagqe-Based Alternate Repair Criteria (ARC) and W* Methodologqy a) Voltagqe-Based ARC The voltage-based repair limits implement the guidance in Generic Letter (GL) 95-05 and are applicable only to Westinghouse-designed steam generators (SGs) with outside diameter stress corrosion cracking (ODSCC) located at the tube-to-tube support plate intersections.

The voltage-based repair limits are not applicable to other forms of SG tube degradation nor are they applicable to ODSCC that occurs at other locations within the SG. Additionally, the repair criteria apply only to indications where the degradation mechanism is dominantly axial ODSCC with no significant cracks extending outside the thickness of the support plate. Refer to GL 95-05 for additional description of the degradation morphology.

Implementation of voltage-based repair limits require a derivation of the voltage structural limit from the burst versus voltage empirical correlation and then the subsequent derivation of the voltage repair limit from the structural limit (which is then implemented by this surveillance).

The voltage structural limit is the voltage from the burst pressure/bobbin voltage correlation, at the 95 percent prediction interval curve reduced to account for the lower 95/95 percent tolerance bound for tubing material properties at 650°F (i.e., the 95 percent lower tolerance limit curve). The voltage structural limit must be adjusted downward to account for potential flaw growth during an operating interval and to account for NDE uncertainty. The upper voltage repair limit; VURL, is determined from the structural voltage limit by applying the following equation:

VURL = VSL - VGR - VNDE where VGR represents the allowance for flaw growth between inspections and VNDE represents the allowance for potential sources of error in the measurement of the bobbin coil voltage.

Further discussion of the assumptions necessary to determine the voltage repair limit are discussed in GL 95-05. /e The mid-cycle equation of TS 6.8.4.k.c.1.G should only be used during unplanned inspection in 3.9.1.16.3 which eddy current data is acquired for indications at the tube support plates.

SSpecification 6 implements several reporting requirements recommended by GL 95-05 for situations which NRC wants to be notified prior to returning the SGs to service. For 6.79..!6., Item,-a-44, id~i~atieis are applicable only where alternate plugging criteria is being appli. For the purposes of this reporting requirement, leakage and conditional burst proba* can be calculated based on the as-found voltage distribution rather than the

, ected end-of-cycle (EOC) voltage distribution (refer to GL 95-05 for more information) 2 and 3 Iwhen it is not practical to complete these calculations using the projected EOC voltage distributions prior to returning the SGs to service. Note that if leakage and conditional burst probability were calculated using the measured EOC voltage distribution for the purposes of addressing GL Sections 6.a.1 and 6.a.3 reporting criteria, then the results of the projected EOC voltage distribution should be provided per GL Section 6.b(c) criteria.

Wastage typo defects are unlikely with proper chom~i6tr, treatmenAt o-f the secondary coolant.

HoWoVer, ov.8en if A-de9fect Should doVolop in SerFVOG, it will be foundlI during schoduled isr'c SG- tub1e exMamninationS. Plu1gging Will be8 required for all tbsWith xceeRding the Pmootin E3-12

INSERT E (Continued) t

' InirMit dRifioRi OR9198GificitienR R9 k G Thet nortion of the tiho that the M'610iiR'i limit UUU.~~~ IIUL- tl=1ly tH at. is AULII LUU At WL ON. AIi Lii s AIU . a 19Iets.t.UIJ UUUIUJA A !Y tlut 1

zarjr pen ie ihp e-rt;r f thR t4km n4,,rc~nf.uld!

tpthAhe we Then tub an,-

end ,hR-A in4. hRpkan+ .nA1 norlion r .................

mo fliho rinoR ot.----.--- ...................

not ittort

..---..-------- RtruntLJrii ... ..

intnoritv ot. mo

~...J-.-----.----'..-.

th- e "Re.

~

su tiiror.

inn Thorotorn IfldIflitIofl5~

VVh*

irtotps;

- t -ffs;-- - - - - -- - - - - - -tha--

- - - -tha-- - - - - - - - - - -tus--.... ell .e e dF.-

WWt I UtU tUIIItuLd:.

bt.n UU u U,. U~. I i-M-KL§UP p It_ UU lu a epo dII t H H iI t.

-- L----L-- J LL _

Tr*T* T* * .k;1i, +~ ,.im ; km l. J~a .Ain+; +h4, .1 + -m +-+A iO I~ -F+1 oigial tube wall thickness.

Tubes experiencing ODSCC within the thickness of the tube support plate are plugged of

-spa-ed by the criteria of 6.8.4.k.c.I.

b) W* Methodoloqy The W* criteria incorporates the guidance provided in WCAP-14797, Revision 2, "Generic W*

Tube Plugging Criteria for 51 Series Steam Generator Tubesheet Region WEXTEX Expansions." W* length is the length of tubing into the tubesheet below the bottom of the WEXTEX transition (BWT) that precludes tube pullout in the event of a complete circumferential separation of the tube below the W* length. W* distance is the distance from the top-of-tube sheet (TTS) to the bottom of the W* length including the distance from the TTS to the BWT and measurement uncertainties.

Indications detected within the W* distance below the TTS, will be plugged upon detection.

Tubes to which WCAP-14797 is applied can experience through-wall degradation up to the limits defined in Revision 2 without increasing the probability of a tube rupture or large leakage event. Tube degradation of any type or extent below W* distance, including a complete circumferential separation of the tube, is acceptable. As applied at Sequoyah Nuclear Plant Unit 2, the W* methodology is used to define the required tube inspection depth into the hot-Replace leg tubesheet, and is not used to permit degradation in the W* distance to remain in service.

This Block Thus while primary to secondary leakage in the W* distance need not be postulated, primary with THE to secondary leakage from potential degradation below the W* distance will be assumed for ATTACHED every inservice tube in the bounding SG. I . .W INSERT for Voltage-Based Alternate Repair Criteria c) ulation of Accident Leakai The postulated e during a steam line break (SLB) shall be equal to t ol1owing equation:

Postulated SLB Leakage = ARC GL9 - +Assumed Leak o--8-<TTS + Assumed Leakage 8"-12"

<TTS + Assumed Leakage >12-<UTTS Where: ARC GL 95-05 is the normal SLB Ie ge derive m ARC methods and the SG tube inspections.

Assumed Leakage 0"--W is the postulated leakage for undetected indi s in SG tubes left in service betwee and 8 inches below the TTS.

Assu eakage 12 <i-es is the conservatively assumed leakage from the total of identifi postulated unidentified indications in SG tubes left in service between 8 and 12 inches E3-13

INSERT E (Continued) below TS. This is 0.0045 gpm multiplied by the number of indications. Postula unidentified i tions will be conservatively assumed to be in one SG. The eJst number of identified indica i left in service between 8 and 12 inches below T any one SG will be included in this term.

Assumed Leakage >12" <TTS is the conse *vely ass leakage for the bounding SG tubes left in service below 12 inches below the TT. is is 0.00009 gpm multiplied by the number of tubes left in service in the least plug .

The aggregate calculated eakage from the application of a Cuand the above assumed leakage s e reported to the NRC in accordance with app le technical

6. .4.

E3-14

ATTACHED INSERT "c) Calculation of Operational Assessment (OA) Accident Induced Leakage The postulated leakage during a Steam Line Break (SLB) shall be equal to the following equation:

Postulated SLB OA Leakage = ARC GL 95-05 + Assumed Leakage o0-8" <TTS + Assumed Leakage 8' <TTS + Assumed Leakage >12- <TTS + All other sources of accident induced primary to secondary leakage Where: ARC GL 95-05 is the SLB OA for predominantly axially oriented outside diameter stress corrosion cracking indications as determined from the methodology described in GL 95-05.

Assumed Leakage 0..8. <TTs is the postulated OA leakage for undetected indications in SG tubes left in service between 0 and 8 inches below the TTS.

Assumed Leakage 8-_12 <TTS is the conservatively assumed OA leakage from the total of identified and postulated unidentified indications in SG tubes left in service between 8 and 12 inches below the TTS. This is 0.0045 gpm multiplied by the number of indications. Postulated unidentified indications will be conservatively assumed to be in one SG. The highest number of identified indications left in service between 8 and 12 inches below TTS in any one SG will be included in this term.

Assumed Leakage >12" <ms is the conservatively assumed OA leakage for the bounding SG tubes left in service below 12 inches below the TTS. This is 0.00009 gpm multiplied by the number of tubes left in service in the least plugged SG.

All other sources of accident induced primary to secondary leakage is the primary to secondary accident induced OA leakage from all other degradation mechanisms other than the voltage based axial ODSCC at tube support plates repair criteria and W* leakage calculations as determined by the Operational Assessment.

d) Calculation of Condition Monitoring (CM) Accident Induced Leakaqe The postulated leakage during a SLB shall be equal to the following equation and is performed for each steam generator:

Postulated SLB CM Leakage = ARC GL 9,-05 + Assumed Leakage 0- <TTs + Assumed Leakage 8W-12" <TTS + Assumed Leakage >12" <TTS + All other sources of accident induced primary to secondary leakage Where: ARC GL 95-05 is the normal SLB CM leakage for predominantly axially oriented ODSCC indications as determined from the methodology described in GL 95-05.

Assumed Leakage 0.-8 <TTS is the postulated CM leakage for indications detected in SG tubes between 0 and 8 inches below the TTS.

Assumed Leakage 8-_12" <TTS is the conservatively assumed CM leakage from the total of identified and postulated unidentified indications in SG tubes left in service between 8 and 12 inches below the TTS. This is 0.0045 gpm multiplied by the number of indications.

Assumed Leakage >12" <TTS is the conservatively assumed CM leakage for the bounding SG tubes in service 12 inches below the TTS. This is 0.00009 gpm multiplied by the number of tubes left in service in the SG.

All other sources of accident induced primary to secondary leakage is the primary to secondary accident induced CM leakage from all other degradation mechanisms other than the voltage based axial ODSCC at tube support plates repair criteria and W* leakage calculations as determined by Condition Monitoring.

E3-15

ATTACHED INSERT (continued)

The aggregate calculated accident induced primary to secondary SLB leakage from the application of all approved ARC (W* and voltage-based axial ODSCC at TSP) and the acciden,.t i*nduced,; l p.riay to

.. conda,',leakage fro.m all .our.o. shall be reported to the NRC in accordance with Technical Specification 6.9.1.16.4. The combined calculated leak rate from all ARC and all other sources of accident induced leakage must be less than the accident induced primary to secondary leakage rate assumed in the SLB accident analyses.

E3-16

INSERT F

7. NRC Generic Letter 95-05, Voltage Based Repair Criteria for Westinghouse Steam Generator Tubes Affected by Outside Diameter Stress Corrosion Cracking

8. NRC letter to TVA dated April 9, 1997, Issuance of Technical Specification Amendments for the Sequoyah Nuclear Plant, Units 1 and 2 (TAC Nos. M96998 and M96999) (TS 96-05)

9. NRC letter to TVA dated May 3, 2005, Sequoyah Nuclear Plant, Unit 2 - Issuance of Amendment Regarding Changes to the Inspection Scope for the Steam Generator Tubes (TAC No. MC5212) (TS-03-06)

E3-17

REACTOR COOLANT SYSTEM BASES 3/4.4.6.2 OPERATIONAL LEAKAGE 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 reactor coolant pressure boundary (RCPB) from degradation and the core from inadequate cooling, in addition to preventing the accident analyses radiation release assumptions from being exceeded. The consequences of violating this LCO include the possibility of a loss of coolant accident (LOCA).

I events in wnicn mere I aare no faulted SGs I APPLICABLE Except for primary-to-secondary leakage, the safety analyses SAFETY ANALYSES do not address operational leakage. However, other o leakage is related to the safety analyses for LOCA; the amount o age can affect the probability of such an event. The safety analysis for resulting in steam discharge to the atmosphere assumM a" 1 gpm primary to soconda.'- leakage as the initial codto.';*,,R "assume that primary to secondary leakage from all steam generators (SGs) is 0.4 gallons per minute (gpm) or increases to 0.4 gpm as a result of accident induced conditions (0.1 gpm per SG is quivalent to 150 gallons per day per SG)."

August 4, 2000 SEQUOYAH - UNIT 2 B 3/4 4-4e Amendment No. 211, 213, 227, 250 E3-18

REACTOR COOLANT SYSTEM steam generator tube rupture or a I BASES Primary to secondary leakag is a fa tor in the dose releases outside containment resulting from a team He break (SLB) accident. To a lesser extent, other accidents or transients volve secondary steam release to the atmosphere, such as a steam genorator tube 'uptur (SGT-R). The leakage rontaminates the secondary fluid. 0.4 gpm operational I safety analysis assumption he FSAR (Ref. 3) analysis f r SGTR assumes the contaminated s ondary fluid is released via safety valves for up to 30 minutes. Operator actii is taken,,-.

to isolate the affected steam cenerator within this time period. The with ARC applied leakage, J primary to secondary leakage ~throughis relatively inconsequential. the affectedI The SLB more limiting for site radiation releases. The safety analysis for the SLB accident assumes 1-,gpm primary to secondary leakage ageneratoras an initial condition. The dose consequences resulting from the SLB accident are well within the limits defined in 10 CFR 100 or the staff approved licensing basis (i.e., a small fraction of these limits). Based on the NDE uncertainties, bobbin coil voltage distribution and crack growth rate from the previous inspection, the expected leak rate following a steam line rupture is limited to beloly8721- gpm at atmospheric conditions and 70°F in the faulted loop, which will limit the c offsite doses to within 10 percent of the 10 CFR 100 guidelines. If the projected and cyc tion of crack indications results in primary-to-secondary leakage greater thanl- . gpm in the faulted loop during a postulated steam line break event, additional tubes must be removed from service in order to reduce the postulated primary-to-secondary steam line break leakage to below 87 2-gpm. Iand 0.3 gpm through the non-affected generators 1 The RCS operational leakage satisfies Criterion 2 of the NRC Policy Statement.

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. UNIDENTIFIED LEAKAGE One gpm of UNIDENTIFIED LEAKAGE is allowed as a reasonable minimum detectable amount that the containment air monitoring and containment pocket September 11, 2003 SEQUOYAH - UNIT 2 B 3/4 4-4f Amendment No. 211, 213, 227, 250 E3-19

REACTOR COOLANT SYSTEM BASES sump level monitoring equipment can collectively 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. Primary to Secondary Leakage through Any One Steam Generator (SG) 150 gallons per day limit on one SG is based on the assumption th single ck leaking this amount would not propagate to a SGTR u r the stress con ns of a LOCA or a main steam line rupture. If I ed through many cracks, the cks are very small, and the above mption is conservative. . . .

INETEV9 The 150-gallons per day limit in ra into Surveillance 4.4.6.2.1 is more restrictive than the standard er leakage limit and is intended to provide an additional margin accommoda crack which might grow at a greater than expected o unexpectedly exten tside the thickness of the tube support e. Hence, the reduced leakage lim, hen combined with an effe e leak rate monitoring program, provides addi' al assur that, should a significant leak be experienced, it will be cted, e plant shut down in a timely manner.

d. IDENTIFIED LEAKAGE Up to 10 gpm of IDENTIFIED LEAKAGE is considered allowable because leakage is from known sources that do not interfere with detection of UNIDENTIFIED LEAKAGE and is well within the capability of the RCS Makeup System. IDENTIFIED LEAKAGE includes leakage to the containment from specifically known and located sources, but does not include PRESSURE BOUNDARY LEAKAGE or controlled reactor coolant pump (RCP) seal leakoff (a normal function not considered leakage).

Violation of this LCO could result in continued degradation of a component or system.

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.

May 17, 2002 SEQUOYAH - UNIT 2 B 3/4 4-4g Amendment No. 211, 213, 227, 250 E3-20

REACTOR COOLANT SYSTEM BASES LCO 3/4.4.6.3, "RCS Pressure Isolation Valve (PIV) Leakage," measures leakage through each individual PIV and can impact this LCO. Of the two PlVs in series in each isolated line, leakage measured through one PIV does not result in RCS leakage when the other is leak tight. If both valves leak and result in a loss of mass from the RCS, the loss must be included in the allowable IDENTIFIED LEAKAGE.

ACTIONS Action a: or with primary to secondary leakage not within limits, If any PRESSURE BOUNDARY LEAKAGE existsthe reactor must be brought to lower pressure conditions to reduce the severity of the leakage and its potential consequences. It should be noted that leakage past seals and gaskets is not PRESSURE BOUNDARY LEAKAGE. The reactor must be brought to MODE 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and MODE 5 within the following 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months . This action reduces the leakage and also reduces the factors that tend to degrade the pressure boundary.

The allowed completion times are reasonable, based on operating experience, to reach the required 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.

Action b: 'I UNIDENTIFIED LEAKAG IDENTI D LEAKAGE, or prmar-y to second6Ry leakage in excess of the LCO limits mus e reduced to within limits within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months . This completion time allows time to vfy leakage rates and either identify UNIDENTIFIED LEAKAGE or reduce le ge to within limits before the reactor must be shut down. This action is necessa prevent further deterioration of the RCPB. If UNIDENTIFIED LEAKAG_, IDENTIFIED LEAKAGET r .. ;pF,*to s.eondary ea kage cannot be reduced to within limits within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months , the reactor must be brought to lower pressure conditions to reduce the severity of the leakage and its potential consequences. The reactor must be brought to MODE 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and MODE 5 within the following 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months . This action reduces the leakage and also reduces the factors that tend to degrade the pressure boundary.

The allowed completion times are reasonable, based on operating experience, to reach the required 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.

August 4, 2000 SEQUOYAH - UNIT 2 B 3/4 4-4h Amendment No. 211,213, 227, 250 E3-21

REACTOR COOLANT SYSTEM BASES SURVEILLANCE Surveillance 4.4.6.2.1 REQUIREMENTS Verifying RCS leakage to be within the LCO limits ensures the integrity of the RCPB is maintained. PRESSURE BOUNDARY LEAKAGE would at first appear as UNIDENTIFIED LEAKAGE and can only be positively identified by inspection. It should be noted that leakage past seals and gaskets is not PRESSURE BOUNDARY LEAKAGE. UNIDENTIFIED LEAKAGE and IDENTIFIED LEAKAGE are determined by performance of an RCS water inventory balance.

T~Pimar_' to Soc.nday,' l*akage is also. mo.asurod by p .erorman.e*of*n RCS ..ator ivtentr, balanco) in conjunc~tion With eAMUonR oioigwthntoscna, Steam aRnd foodwater systems.

The surveillance is Th',RCS water inventory balance must be met with the reactor at steady state modified by a operatg conditions (stable pressure, temperature, power level, pressurizer and footnote. *makeuplnk levels, makeup, letdown, and RCP seal injection and return flows).

/ J' &~footnote added allowing that this SR is not required to be performed until 12 ho s after establishing steady state operation. The 12-hour allowance provides suff i 'ent time to collect and process all necessary data after stable plant conditions are stablished. Performance of this surveillance within the 12-hour allowance is re ired to maintain compliance with the provisions of Specification 4.0.3. state Steady state operation is required to perform a proper inventory balance since calculations during maneuvering are not useful. For RCS operational leakage determination by water inventory balance, steady state is defined as stable RCS pressure, temperature, power level, pressurizer and makeup tank levels, makeup and letdown, and RCP seal injection and return flows.

An early warning of PRESSURE BOUNDARY LEAKAGE or UNIDENTIFIED LEAKAGE is provided by the automatic systems that monitor the containment atmosphere radioactivity and the containment pocket sump level. It should be noted that leakage past seals and gaskets is not PRESSURE BOUNDARY LEAKAGE. These leakage detection systems are specified in LCO 3/4.4.6.1, JNSERT H I"Leakage Detection Instrumentation."

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

Surveillance 4.4.6.2.2

-Tbsqeillnceproids the means necessary to determine SG 1i anoeainrVeETerqieet to demonstra integrity in JINSERT I 1 0 at normal o " niios August 4, 2000 SEQUOYAH - UNIT 2 B 3/4 4-4i Amendment No. 211, 213, 227, 250 E3-22

REACTOR COOLANT SYSTEM BASES REFERENCES 1. 10 CFR 50, Appendix A, GDC 30.

2. Regulatory Guide 1.45, May 1973.

3. FSAR, Section 15.4.3.

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

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

August 4, 2000 SEQUOYAH - UNIT 2 B 3/4 4-4j Amendment No. 211, 213, 227, 250 E3-23

INSERT G The limit of 150 gallons per day per SG is based on the operational leakage performance criterion in NEI 97-06, Steam Generator Program Guidelines (Ref. 4). The 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.

INSERT H Notation associated with this SR 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.

INSERT I This SR verifies that primary to secondary leakage is less than or equal to 150 gallons per day through any one SG. Satisfying the primary to secondary leakage limit ensures that the operational leakage performance criterion in the Steam Generator Program is met. If this SR is not met, compliance with LCO 3.4.5, "Steam Generator Tube Integrity," should be evaluated.

The 150 gallons per day limit is measured at 70 degrees Fahrenheit (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 surveillance is modified by a note which states that the surveillance is not required to be performed until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after establishment of steady state operation. For RCS primary-to-secondary leakage determination, steady state is defined as stable RCS pressure, temperature, power level, pressurizer and makeup tank levels, makeup and letdown, and RCP seal injection and return flows.

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

E3-24

v t e Letter Sequence Request
TAC:MD0110, Steam Generator Tube Integrity (Open)
Initiation Request Acceptance... Supplement Administration Questions Answers Results Approval... Other: ML071500010
MONTHYEAR2007-04-02 [Table View]

ML071010153

Text

Reference:

Enclosures:

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