ML062500211

Supplement to Technical Specification Change 05-09 - Application for Technical Specification Improvement Regarding Steam Generator Tube Integrity and Deletion of License Condition

ML062500211
Person / Time
Site:	Sequoyah
Issue date:	08/30/2006
From:	Pace P Tennessee Valley Authority
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
TAC MD0145, TVA-SQN-TS-05-09
Download: ML062500211 (52)

Text

Tennessee Valley Authority, Post Office Box 2000, Soddy-Daisy, Tennessee 37384-2000 August 30, 2006 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 -~SUPPLEMENT TO TECHNICAL SPECIFICATION (TS) CHANGE 05 APPLICATION FOR TECHNICAL SPECIFICATION IMPROVEMENT REGARDING STEAM GENERATOR TUBE INTEGRITY AND DELETION OF LICENSE CONDITION

References:

1. NRC letter to TVA dated June 06, 2006, "Sequoyah Nuclear Plant, Unit 2 - Request for Additional Information Regarding Steam Generator Tube Integrity (TSTF-449) (TAC No. MD0145)"

2. TVA letter to NRC dated August 7, 2006, "Sequoyah Nuclear Plant (SQN) - Response to Request for Additional Information (RAI) Regarding Steam Tube Integrity (TSTF-449) (TAC No. MD0145)"

By Reference 1, NRC staff requested additional information to support staff review of SQN TS Change 05-09. TVA submitted the requested information by Reference 2 and has enclosed new TS and TS Bases markups to supplement the information provided by Reference 2. The Reference 1 letter suggested several changes to TVA's TS Change 05-09 that were discussed during a telephone conference on June 6, 2006. To provide for ease of staff review, the enclosed markups replace, in their entirety, the markups previously provided by TVA's February 15, 2006, submittal.

]xC) 30 Printed on r'ycled paper

U.S. Nuclear Regulatory Commission Page 2 August 30, 2006 provides a summary of the changes. Enclosure 2 provides a new set of TS markups. Enclosure 3 provides a new set of TS Bases markups.

TVA's schedule for implementing TS Change 05-09 continues to be during the Unit 2 Cycle 14 refueling outage (outage scheduled to begin in November 2006). Accordingly, TVA requests NRC approval by mid-October to allow for TS implementation during the Unit 2 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 CFR 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 Jim Smith at 843-6672.

I declare under penalty of perjury that the foregoing is true and correct. Executed on this 30th day of August, 2006.

Sincerely, P.L. Pace Manager, Site Licensing and Industry Affairs

Enclosures:

1. Summary of Changes

2. New Technical Specification Page Markups

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

• _I-U.S. Nuclear Regulatory Commission Page 3 August 30, 2006 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. Douglas V. Pickett, 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 (TVA)

SEQUOYAH NUCLEAR PLANT (SQN)

SUPPLEMENT TO SQN UNIT 2 TECHNICAL SPECIFICATION (TS) CHANGE 05-09

SUMMARY

By letter dated February 15, 2006, TVA submitted TS Change 05-09 that proposed changes to SQN Unit 2 TSs related to steam generator .(SG) tube integrity. TS Change 05-09 is based on Technical Specification Task Force (TSTF) Standard Technical Specification Change Traveler, TSTF-449, "Steam Generator Tube Integrity," Revision 4, and is approved for use by NRC's Consolidated Line Item Improvement Process (CLIIP).

By letter dated June 6, 2006, NRC requested additional information to support ongoing staff review of TS Change 05-09.

By letter dated August 7, 2006, TVA provided responses to the staff's request for additional information. The additional information supports NRC technical staff's suggestions for several refinements to TS Change 05-09. The enclosed TS change markups for TS Change 05-09 are the result of discussions with the staff during a telephone conference on June 6, 2006. Note that for ease of staff review, TVA is submitting new TS and Bases markups, in their entirety, to replace the markups previously provided in TVA's TS Change 05-09 submittal dated February 15, 2006. provides the new TS markups for SQN TS Change 05-09.

The TS markups reflect changes that are within the Administrative Section of SQN Unit 2 TSs. The most notable change is the addition of a 90-day reporting requirement that is described in NRC Generic Letter (GL) 95-05 for application of voltage-based alternate tube plugging criteria. Because NRC GL 95-05 voltage based criteria is applicable to SQN Unit 2 and the Unit 2 SG tube inspection program, it is necessary to include this in the TSs (i.e., SG program) for Unit 2. Other refinements to the TS SG program for Unit 2 are for clarification and format and do not affect the associated TS limiting condition for operation (LCO).

In addition, Enclosure 3 provides new TS Bases markups that correspond to changes made within the Administrative Section.

These Bases changes also reflect the staff's recommendations stemming from their RAI letter dated June 06, 2006.

El-I

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) Design 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.

May , TVA shall establish a steam generatoo-rga that is in accordance wi it in Enclosure 2 to the TVA

( etter to the Commis s subject a (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 1.17 DELETED I

II (primary to secondary) I II I

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.

__im tseondae PRESSURE BOUNDARY LEAKAGE pI 1.22 PRESSURE BOUNDARY LEAKAGE shall be leakage (except atoam gonorntor 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 fluence 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

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

REACTOR COOLANT SYSTEM 3 4.5 STEAM GENERATORS LIMITI CONDITION FOR OPERATION 3.4.5 Each earn generator shall be OPERABLE.

APPLICABILI . MODES 1, 2, 3 and 4.

ACTION:

With one or more steam enerators inoperable, restore the inoperable generator(s) t OPERABLE status prior to increasing Tavg abo e 2001F.

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 fication4.0.5.

4.4.5.1 Steam Generator Sam ple Selectio and Inspection - Eac team generator shall be determined OPERABLE during shutdown by selecting an inspetingatlea 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 tes 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 ion (subsequent to the preservice inspectio of each steam generator shall include:

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

RECO OLN SYSTEM/

8JRVEILLANCE 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 or a tube inspecti , this shall be recorded and an adjacent tube shall be selected and s jected to a tube inspection.

4. Indications le *n 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 tube 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 (ODSCC) indications.

The determination of the lowest cold-leg tu esupport pi intersections having 005CC indications shall be based on the performance of at ast a 20 percent 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 rotatin 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 2 314 4-11 Amendment No. 181, 211, 213, 243, 291 E2-6

\REACTOR COOLANT SYSTEM /

SRVEILLANCE REQUIREMENTS (Continued)

C-2 One or more tubes, but not more than 1% of the total tubes insp cted are defective, or between 5% and 10% of the total tubes inspe ed are degraded tubes.

C-3 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, 996 S UOYAH - UNIT 2 3/4 4-11a Amendment No. 181, 11 E2-7

EACTOR COOLANT SYSTEM UR ILLANCE REQUIREMENTS (Continued) 4.4.5.3 In oection Frequencies - 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 be erformed at intervals o not less than 12 nor more than 24 calendar months after the previo inspection. If two consec *veinspections 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 de 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 specifiedZn Table 4.4 4.4-2 during the shutdown con *s:

subsequent to any of the following

1. Prima ry-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 ifing actuation f the engineered safeguards.

4. Amain steam line orfeed terlinebreak.

S UOYAH - UNIT 2 3/4 4-12 E2-8

\iZACTOR COOLANT SYSTEM

/

SU EILLANCE REQUIREMENTS (Continued) 4.4.5.4 cce tance Criteria

a. A used in this Specification:

1. Im erfection means an exception to the dimensions, finish or contour a tube from that quired by fabrication drawings or specifications. Eddy-current testi g indications below 2 6 of the nominal tube wall thickness, ifdetectable, may be con *dered as imp ections.

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

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

4.  % Degradation me s the percentage of the tube al thickness affected or removed by degradation.

5. Defect means an imperf tion of such seve that it exceeds the plugging limit. A tube containing a defect is defe *ve.

6. Plugqqing Limit means the impe ectio epth at or beyond which the tube shall be removed from service and is eq I t 40% of the nominal tube wall thickness. Plugging limit does not apply to that portion the tube that is not within the pressure boundary of the reactor coolant system (tube n up to the start of the tube-to-tubesheet weld). This definition does not apply to tub supp plate intersections if the voltage-based repair criteria are being applied. R erto 4.4. .a.10 for the repair limit applicable to these intersections. This definiti does not app to service induced degradation identified in the W* distance. Servic nduced degradati n identified in the W* distance below the top-of-tube sheet (TTS), s I be plugged on dete ion.

7. Unserviceable des ibes the condition of a tube i 'leaks or contains a defect large enough to affect i structural integrity in the event o an Operating Basis Earthquake, a loss-of-coolant ccident, or a steam line or feedwater ine break as specified in 4.4.5.3.c, above.

8. Tube Ins ction means an inspection of the steam generat tube from the point of entry (hot leg ,de) completely around the U-bend to the top suppo of the cold leg exclu gthe portion of the tube within the tubesheet below thW* distance, the tube to tub eet weld and the tube end extension.

9. reservice Inspection means an inspection of the full length of each bein each steam generator performed by eddy current techniques prior to service to:est lish a baseline condition of the tubing. This inspection shall be performed prior to initial OWER OPERATION using the equipment and techniques expected to be used du 'ng subsequent inservice inspections.

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

SRELANCE REQUIREME--NTSContinued) /

10 Tub~e pl Support Plate Plugg~ing Limit is used for the disposition of an alloy 600 steam,/

generator tube for continued service that is experiencing predominately axially ori lied 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 inrvce /

I s than orequal to the lower voltage repair limit (Note 1), wil e allowed to remain

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* be repaired or plugged, except as n 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 r 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 orrosion-cracking degradation with a bobbin coil voltage greater than th upper v 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 d in 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:

VM = VSL (cL-At) l.O+NDE+Gr L

=

= V L- (VL - V) CL (CL- At)

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

whe 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 i lemented CL = cycle ngth (the time between two scheduled st m generator inspections)

VSL structural 'mit voltage Gr = average gro rate per cycle length NIDE 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 acc 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 (TTS): (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 WCdis -477 nce below the bottom Revision 2. of the WEXTEX transition a defined by c) Length is the length of tubing below the bottom of the W X 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 /

S VEILLANCE 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 omplete 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 followi the completion of the inspection' This Special Report shall inc de:

1. Numb r*nd 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 prio to resumption of plant operation. The written followup of this repor shall provide a descr ition 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 'ected 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 ir plementation of the W* criteria to tubesheet inspection depth. Ifthe otal projected end -cycle 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 intersectio.

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

4. If 1 ications are identified at the tube support plate elevations at are attributable to pary water stress corrosion cracking.

5. If the 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.

May 3, 2 5 SEQUOYAH - UNIT 2 3/4 4-14b Amendment No. 28, 211, 213, 267, 2 E2-12

\kEACTOR COOLANT SYSTEM SUVILNEREQ.UIREMEN.TS (Coontinued) r eTcaclated steam line break leakage from the application of tube support plate altert repa*r 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 0 ). 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 orientat n (axial, circumferential, skewed, volumetric), the severity of each.,"dication (e.g.,

near through all or not through-wall), the side of the tube from which the in iction 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 E2-13

TABLE 4.4-1 /

MINIMUM NUMBER OF STEAM GENERATORS TO BE INSPECTED DURING INSERVICE INSPECTION I

Table Notation:

1. The inservice ins ction may be limited to one steam gen 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 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 ci 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 tins 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 sec hdand ird inspections. The fourth and subsequent inspections sharl follow the inst ctions des 'bed inl1above.

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

TABLE 4.4-2 STEAM GENERATOR TUBE INSPECTION PLE INSPECTION 2" SAMPLE INSPECTION 3" SAM E

_ _ _INSPEC ION Sample esult Action Required Result Action Required Result / Action Size ____Required A minimum C-I None N/A N/A N// N/A of S Tubes /

per S.G.

C-2 PI defective tubes C-1 None N/A and i pect additional Plug defective tubes C-1 None 2S tub in this S.G. C-2 and inspect additional 4S tubes in this S.G C-2 Plug defective tubes C-3 Perform action for C-3 result of first sample Performaction 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 e None N/A NIA defective tubes and C-1I%

inspect 2S tubes in each other Some Perform action for C-2 S.G. S/G -2 sult of second sample N/A NIA bu no ditional S.G. are C-3 Additional Inspect all bes in each S/G is C-3 S.G. and pluidefective NIA N/A tubes. 1_ _

S=3-% Where N is th umber of steam generators in the unit, and n i he number of steam n

generators j 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 <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and in COLD SHUTDOWN within the next 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />.

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, j ACTION:II

a. With any PRESSURE BOUNDARY LEAKAG-, be in at least HOT STANDBY within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and in COLD SHUTDOWN within the following 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />.

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 <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> or be in at least HOT STANDBY *ithin the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and in COLD SHUTDOWN within the following 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />. l. ~or.o.primary-to-secondary I ~is withinl is w SUR ILLANCE REQUIREMENTS 4.4.6.2. ,-ReactorCoolant System leakages .. ... . . limits by performance of a Reactor Coolant System water inventory balance at least once per 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.*

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

F+4.4.6.2.2iV9oify ,.om a ,,,r tubo intog.ity i6 !A,.,,,.,

,,atOr with the roguiFr,,, nt-,*,Of T-A-,hl A..-,

• Not required to be performed until 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> 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. Configuration Risk Management Program (DELETED)

j. Technical Specification (TS) Bases Control Program 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). INSE B 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 andlor plugged, to confirm that the performance criteria are being met. except as Dermitted through I

. . . r - - - I,r . . . . . . .. -

repair application of the alternate

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

1. Structural integrity performance criterion: All in-service SG tubes shall retair 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 ODSCC at the TSP transients included in the design specification) and design basis accidents (

elevations, (refer to This includes retaining a safety factor of 3.0 against burst under normal sfea 6.8.4.k.c.1) the state full power operation primary-to-secondary pressure differential ands probability of burst factor of 1.4 against burst applied to the DBA primary-to-secondary pressure (POB) of one or differentials. Apart from the above requirements, additional loading conditior more indications associated with the DBAs, or combination of accidents in accordance with th given a steam line design and licensing basis, shall also be evaluated to determine if the associated break shall be less loads contribute significantly to burst or collapse. In the assessment of tube than 1 x 10.-2 integrity, those loads that do significantly affect burst or collapse shall be determined and assessed in combination with the loads due to pressure with safety factor of 1.2 on the combined primary loads and 1.0 on axial seconda ry loads.

2. Accident induced leakage performance criterion: The accident induced leak;agez not to exceed 1.0 gpm for the faulted SG, except fo* outsido diamoter stress corroionarack (ODSCC) and W* indicationS that have an approvcd limito 3.7 gaIlGon por 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 of 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

1. The following alternate tube re pair criteria (ARC) may be applied as an alternative to the 4 ,0/0%

depth based criteria:

InLegnLy as described below:

GIL 95-05 Voltage-Based A voltage-based TSP plugging limit is used for the disposition C/ an alloy 600 SG tube for continued service that is experiencing predominately axial, oriented ODSCC confined within the thickness of the tube support plates (TSy'). At TSP intersections, the plugging (repair) limit is based on maintaining SG tube ev-coability as described a) SG tubes, whose degradation is attributed to DSCC within the bounds of the TSP with bobbin voltages less than or equa tcpl (Nete4 will be allowed to remain in servie.

b) SG tubes, whose degradation is attribu d to ODS within the bounds of the 6.8.4.k.c.l.c)

] TSP with a bobbin voltage greater than will be Fepaiei-e- plugged, except as noted in Item* elow.

" (No ,

c) SG tubes, with indications of potential degradation attrib ted to ODSCC within the bounds of the TSP with a bobbin voltage greater than

.. pair limit (Note 1), but less than or equal to upper voltage repair limit (Note 2),

may remain in service if a rotating pancake coil inspection does not detect degradation. SG tubes with indications of ODSCC degra dion with a bobbin coil voltage greater than the upper voltage repair limit (Note )will be plugged OFFepakEd___

Not abplicablo to SQN-. or comparable technology j If an unscheduled mid-cycle inspection is performed, the following mid-cycle repair limits apply instead of the limits identified in Items b, and G.

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

VMuLRL =SL I 6.8.4.k.c.1.a), .b), and .c). I At) 1.0 + NDE + Gr (CL-CL VML.RL = VMURL -(VURL - VLR) (CL)- At)

CL 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 cycle length (the time between two CL 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 III 6.8.4.k.c.1.a), .b), and .c). I of 20 percent has been approved by fMDt*D\

/~~E l

I V

%..J)

Implemen ation of these m i-ccle repair limits should follow the same approach as in TS items (Deleted) r Note i e lowerveltage t i- I .0volt for 3*, inch d,-,Amtc.r tu bihng Or lepiami 2.0 'olts for 718 inch diameto tubing. ,

Note 2: The upper voltage repair limit is calculated according to the methodology in GL 95-05 as supplemented. VURL may differ at the TSPs and flow distribution baffle.

-~ 7 ,..,t!-~. .~,. ~  ;~ 4kv, f.z,,,I+~-~A Qc!

0I7V W* Methodology Implementation of the SG WEXTEX expanded region inspection methodology (W*)

requires a 100 percent rotating coil probe inspection of the hot-leg tubesheet W*

The inspection of distance. The implementation of W* does not apply to service induced degradation SG tubes is from identified in the W* distance. Service induced degradation identified in the W*

the point of entry distance below the top-of-tubesheet (TTS) shall be plugged on detection. *._,,e (hot-leg side) I[1~:r)[-iUI Ifl[I ni ~ IIJIJ[R: ii uri I ulu IJUII it ul ur I tr': ii lut iuu ~iuu LUfIH)flhiL~i'.' :irutir it] UU-i

-SnE)Gt'E)R GT " W1386 IS TFe tFIG DGIRI OT E)RIFU '01 #L,-iecl-4*-S*rie GURHG 4F4R_

completely -f 4"- -- 1A I- -T 4L,:- 491-around the tub-eshooet bolow~ the I..I distanco, the tube-to-ttubesheet Weld and the tube end U-bend to the cold leg tube outlet end, The following terms/definitions apply to the W*.

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

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

extension.

E2-21

INSERT B c) W* Length is the length of tubing below the bottom of the BWT which must be demonstrated to be non-degraded in order for the tube to maintain structural and leakage integrity. For the hot leg, the W* length is 7.0 inches which represents the most conservative hot leg length defined in WCAP-14797, Revision 2.

The postulated leakage reSUlting froM the implemnentationA of tho voltage based repair cdriteria to TSP-1 interSectlions rsha~ll be coGmbined with the postulated leakage reSUlting from the implementation Of W* criteria to tubosheet inSPection depth.

d. Provisions for SG Tube Inspections. and d.4 Periodic SG tube inspections shall be perform . The number and portions of the tubes inspected and methods of inspection shall be erformed with the objective of detecting flaws of any type (e.g., volumetric flaws, axi I and circumferential cracks) that may be 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 o let, and that may satisfy the applicable tube repair criteria. The tube-to-tubesheet ld is not part of the tube. In addition to meeting the requirements of d.1, d.2, aait d.3, /elow, the inspection scope, inspection methods, and inspection intervals shall be such as to ensure that SG tube integrity is maintained until the next SG inspection. An assessment of degradation shall be performed to determine the type and location of flaws to which the tubes may be susceptible and, based on this assessment, to determine which inspection methods need to be employed and at what locations.

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

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

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

4N GL 95-05 Voltage-Based ARC for TSP Indications left in service as a result of application of the TSP voltage-based repair criteria shall be inspected by bobbin coil probe during all future refueling outages.

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 the performance of at least a 20 percent random sampling of tubes inspected over their full length.

E2-22

INSERT B

• Methodolo~qy

. I ~W* METHODOLOGY REPAIR IS MOVED CRITERIA SECTION TOI (c) ABOVE ./I /

Iml.entation of the SG WEXTEX expanded region inspection methodo,* yV'**)

require 100 percent rotating coil probe inspection of the hot-leg tube sleet W*

distance. ,e implemerntation of W* does not apply', ooservice inducp 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 rt 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 an d tub eet or below the TTS, as determined by eddy current testing.

e) W* Distance is t arger of the following tdistances 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 B which must be demonstrated to be non-degraded in order for the tube to m tamn structural and leakage integrity. For the hot leg, the W* length is .ice which represents the most conservative hot leg length defined in WCAP-1 4797, Revision 2.

e. Provisions for Monitoring Operational Prima ry-to-S econd ary 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, F Proprietary)

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

7. WCAP-1 0266-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-1 0227P-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 ýnethods 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-14040-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

INSERT C 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

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

6.9.1.16.2 A report shall be submitted within 90 days after the initial entry into MODE 4 following completion of an inspection performed in accordance with the steam generator program (6.8.4.k) and voltage based alternate repair criteria is applied. The report shll 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."

L For implementation of the voltage-based repair criteria for tube support plate (TSP) intersections, notify the staff prior to returning the SGs to service should any of the following conditions arise:

'1'JN t ,A ;L. oc~~o k-mcard nn +k,5 praiarr io,.r nrjr .-e-f- Ap~i ;fo H-,~ np practical usin~g the actual measured end of cycle) voltage distribution. This leakage shall be combined w.,ith the postulated leakage resulting from the 0mnlementation of the~ WA*citeria to tubehr'e*et iRE~nrcti9R denth if the teta! I rarr;n,4rd rsrdrl f -"irip ~,A'kuinp lorm frrnm ml!I caurno or,ynoo.vdrc, 11 1:  : A t A ýrý t, i: ~t4l~J~Afl..4LI~J5 I II..JILI I~

LI I~ I~ **tA~.JL. SI hIlL 1~LAtLI *I**I t~'.A *S L.~Ill L*I I*~~* *L.flI nnizhtl:b4tr mnin szttzpm lina hrpnk' fnr thp npmd rnnprnincin -r, - ý-* o crwn

-i -,

thp czt~ff rhnUl If circumferential crack-like indications are detected at the TSP intersections.

E2-25

INSERT C E ly 3) If indications are identified that extend beyond the confines of the TSP.

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

6.9.1.16.4

5) if the calculated conditional burst prebabilit,' based on the projcctcd end of cycle (or if not practical, using the actual measuredi end-of cycic) voltage distribution excceds 4 An-2, ntfy h; R and provide an assessment of the safety significance of the occurrence.

j.-For implementation of W*, the calculated steam line break leakage from the application of TSP alternate repair criteria and W* inspection methodology shall be submitted in a Special Report in accordance w..ith 10 CFR 50.4 within 90 days following return of the SGs to service (MODE 4). The report will include the number of indications within the tubesheet region, the location of the indications (relative to the bottom of the WEXTEX transition [BW11 and TTS), the orientation (axial, circumferential, skewed, volumetric), the severity of each indication (e.g., near through-wall or not through-wall), the side of the tube from which the indication initiated (inside or outside diameter), and an assessment of whether the results were consistent with expectations with respect to the number of flaws and flaw severity (and if not consistent, a 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

SINSERT D SYSTEM REACTOR COOLANT 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 s m generator tubes is based on a modification of Regulatory Guide 1.83, Revision 1. In rvice inspecd in of steam generator tubing is essential in order to maintain surveillance of the co itions of the tube *nthe event that there is evidence of mechanical damage or progressive degra tion due to design, nufacturing errors, or inservice conditions that lead to corrosion. Inservic inspection of steam genera r tubing also provides a means of characterizing the nature and caus of any tube degradation so at corrective 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 those hemistry limits found to result in negligible corrosi of the steam generator tubes.. If the secondary lant chemistry is not maintained within these *its, localized corrosion may likely result in stress co osion cracking. The extent of cracking d ing plant operation would be limited by the limitation of stea generator tube leakage between th primary coolant system and the secondary coolant system (prim -to-secondary leakage = 150 g ons per day per steam generator). Cracks having a prima -to-secondary leakage less an this limit during operation will have an adequate margin of safety to ithstand the loads im sed during normal operation and by postulated accidents. Sequoyah has de onstrated that pri ary-to-secondary leakage of 150 gallons per day per steam generator can readily b detected by r diation monitors of steam generator blowdown or condenser off-gas. Leakage in xcess o is limit will require plant shutdown and an unscheduled inspection, during which the leaki tu s 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 Westinghou se-desig ned st m genatr(SG)whousddimertes corrosion cracking (ODSCC) located at the be-to-tube pport plate intersections. The voltage-based repair limits are not applicable to er forms of S/G be degradation nor are they applicable to ODSCC that occurs at other locatio within the SIG. Addi nally, the repair criteria apply only to indications where the degradation chanism is dominantly axi ODSCC with no significant cracks extending outside the thickness o e support plate. Refer to GL-05 for additional description of the degradation morphology.

Implementation of 4.4.5 requires a derivation of the voltage str ctural limit.from the burst versus voltage empirical orrelation and then the subsequent derivation of t voltage repair limit from the structural limi which is then implemented by this surveillance).

The volta structural limit is the voltage from the burst pressure/bobbin vo ge correlation, at the 95 percent ediction interval curve reduced to account for the lower 95195 perce tolerance bound for tu g material properties at 6501F (i.e., the 95 percent LTL curve). The volta structural Ilimit must adjusted downward to account for potential flaw growth during an operating i erval and to accoi for NDE uncertainty. The upper voltage repair limit; VURL, is determined from the ctural volta limit by applying the following equation:

VURL = VSL - VGR - VNDE April 9, 1997 SEQUOYAH - UNIT 2 B 3/44-3 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 otential sources of error in the measurement of the bobbin coil voltage. Further discussion of the assu tions necessary 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 eddy curren data is acquired 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 tified prior to returning the S/Gs to service. For SR 4.4.5.5.d., Items 3 and , indications are applicable only ere alternate plugging criteria is being applied. For the purposes of th' reporting requirement, leakage d conditional burst probability can be calculated based on the as-f und voltage distribution rather than th projected end-of-cycle voltage distribution (refer to GL 95-05 r more information) when it is not practical to c plete these calculations using the projected EOC voltag distributions prior to returning the S/Gs to service. ote that if leakage and conditional burst probability ere calculated using the measured EOC voltage distribu i n for the purposes of addressing GL Sections 6 .1 and 6.a.3 reporting criteria, then the results of the pro cted EOC voltage distribution should be pro ded per GL Section 6.b(c) criteria.

Wastage-type defects are unlike with proper chemistry treatme of the secondary coolant. However, even if a defect should develop in service, will 'be found during sche ed inservice steam generator tube examinations. Plugging will be required for a tubes with imperfecti s exceeding the repair limit defined in Surveillance Requirement 4.4.5.4.a. The porti of the tube that t plugging limit does not apply to is the portion of the tube that is not within the RCS pres re boundary/ube end up to the start of the tube-to-I tubesheet weld). The tube end to tube-to-tubeshee weld po

• n of the tube does not affect structural integrity of the steam generator tubes and therefore indication oun in this portion of the tube will be excluded from the Result and Action Required for tube inspections. It is e cted that any indications that extend from this region will be detected during the scheduled tube inspections, am generator tube inspections of operating plants have demonstrated the capability to reliably detect d radati that has penetrated 20% of the original tube wall thickness.

Tubes experiencing outside diameter ress corrosion crac *ng within the thickness of the tube support plate are plugged or repaired by the criteria 4.4.5.4.a.10.

The W* criteria incorporate the uidance provided in WCAP-1479 Revision 2, "Generic W* Tube Plugging Criteria for 51 Series Steam enerator Tubesheet Region WEXT Expansions." W* length is the length of tubing into the tubeheet low the bottom of the WEXTEX transition BWT) that precludes tube pullout in the event of a complet ircumferential separation of the tube below th W* length. W* distance is the distance from the top of th ubesheet to the bottom of the W* length including e distance from the top of the tubesheet to the BWT a measurement uncertainties.

Indications dete ed within the W* distan ce below the top-of-tube sheet (UTS), wi be plugged upon detection. Tubes to w ich WCAP-14797 is applied can experience through-wall degradatio up to the limits defined in Revision without increasing the probability of a tube rupture or large leakage eve Tube degradation Of an type or extent below W* distance, including a complete circumferential sepa tion of the tube, is acceptale. As applied at Sequoyah Nuclear Plant Unit 2, the W* methodology is use~d to efine the required tube nispection depth into the hot-leg tubesheet, and is not used to permit degradation in th W*

distance to emain in service. Thus while primary to secondary leakage in the W* distance need not b postulat ,primary to secondary leakage from potential degradation below the W*' distance will be assu dfor every i service tube in the bounding steam generator.

May 3, 2005 QUOYAH - UNIT 2 B 3/4 4-3a Amendment No. 181, 211, 213, 243, 291 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 GL95-05 + Assumed Leakage 0--8-<TTs+ Assumed Leakag 8_ <TTS + As med Leakage 112- <TTs Where: CGL95-05 is the normal SLB leakage derived from alternate repair crit a methods and the steam gen ator tube inspections.

Assumed Leakag -.8-<TTS is the postulated leakage for undetected i ications in steam generator tubes left in servic etween 0 and 8 inches below the top of t tubesheet.

Assumed Leakage 12" <TTs the conservatively assumed akage from the total of identified and postulated unidentified indications steam generator tube eft in service between 8 and 12 inches below the top of the tubesheet. Th is 0.0045 gM Itiplied by the number of indications.

Postulated unidentified indications will be con rvativey* ssumed to be in one steam generator. The highest number of identified indications left in se 'e etween 8 and 12 inches below TTS in any one steam generator will be included in this term.

Assumed Leakage >12' <n-s is the co ervatively ass ed leakage for the bounding steam generator tubes left in service below 12 1ches below the top ohe tubesheet. This is 0.00009 gpm multiplied by the number of tubes lef service in the least plugg steam generator.

The aggregate calcula SLB leakage from the application of al ternate repair criteria and the above assumed leaka shall be reported to the NRC in accordance wi applicable Technical Specifications. The co mned calculated leak rate from all alternate repair crite *must be less than the maximum allow e steam line break leak rate limit in any one steam generato Iorder to maintain doses in 10 CFR 100 guideline values and within GDC-19 values during ostulated steam line br event.

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

- 1f `

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

,or the NRC approved licensing basis.

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 eve itassumes 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 atmosphere is based on a primary to secondary leakage of 0.1 gallons per minute (gpm) for the non-faulted SGs and 3.7 gpm for the faulted SG. This limit is approved for use for alternate repair criteria (ARC) and W* leakage calculations. For non-ARC applications, the accident induced leakage in the faulted SG is limited to 1.0 gpm, which is bounded by the maximum leakage established by the plant safety analysis. 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/f these events are within the limits of GDC 19 (Ref. 2), 10 CFR 100 (Ref. 3),

INSERT E 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 accordance with the Steam Generator Program.

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

In the context of this specification, a SG tube is defined as the entire length of the tube, including the tube wall, between the tube-to-tubesheet weld at the tube inlet and the tube-to-tubesheet weld at the tube outlet.

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

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

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

BASES LCO (continued)

The accident induced leakage performance criterion ensures that the primary to secondary leakag6e c`aused by a design basis'accident, other than a SGTR, is within the accident analysis assumptions. In the main steam line break (MSLB) analysis for ARC, SG leakage is assumed to be 3.7 gpm for the faulted SG and 0.1 gpm for the non-faulted SGs. Limiting the allowable leakage in the faulted SG to 1.0 gpm for non-ARC applications ensures that the MSLB analysis remains conservative and bounding. The accident induced leakage rate includes any primary to secondary leakage existing prior to the accident in addition to primary to secondary leakage induced during the accident. The 3.7 gpm is approved for use in ARC applications where the cracks are limited to locations within the tubesheet or within a drilled tube support plate.

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

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 Pthe nex inspection. If it is determined that tube integrity is not being maintained until the nee 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.

Ia*AG tube integrity is not being maintained, the reactor-must be brought to HOT at any time, evaluation TANDBY within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and COLD SHUTDOWN within the next 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br /> and the determines affected tube(s) plugged prior to restart f6olloing the next refuinP.g outage or SG iP, tem..(Mode sec, 4). -

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

SEQUOYAH - UNIT 2 B 3/4 4-3d E3-9

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

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.

(i0e., 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 Voltaqge-Based Alternate Repair Criteria (ARC) and W* Methodolocqy 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 6501F (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.

The mid-cycle equation of TS 6.8.4.k.c.1 .c 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.

Specification 4-.-446 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 6.9.4.46., Item%3-an44, indications are applicable only where alternate plugging criteria is being appli. For the purposes of this reporting requirement, leakage and conditional burst probap 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 when it is not practical to complete these calculations using the projected EOC voltage Iwdistributions 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-type defects are unlikely with proper chemistry treatment of the secondary coolant.

However, even if a defect should develop in service, it will be found during scheduled inservice SG tube examinations. Plugging will be required for all tubes with imperfections exceeding the E3-12

INSERT E (Continued) repair limit defined in Specification 6.8.4.k.c. The portion of the tube that the plugging limit does not apply to is the portion of the tube that is not within the RCS pressure boundary (tube end up to the start of the tube-to-tubesheet weld). The tube end tube-to-tubesheet weld portion of the tube does not affect structural integrity of the SG tubes and therefore indications found in this portion of the tube will be excluded from the "Result and Action Required" for tube inspections. It is expected that any indications that extend from this region will be detected during the scheduled tube inspections. SG tube inspections of operating plants have demonstrated the capability to reliably detect degradation that has penetrated 20% of the original tube wall thickness.

Tubes experiencing ODSCC within the thickness of the tube support plate are plugged or repaired by the criteria of 6.8.4.k.c.1.

b) W* Methodology 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-leg tubesheet, and is not used to permit degradation in the W* distance to remain in service.

Thus while primary to secondary leakage in the W* distance need not be postulated, primary to secondary leakage from potential degradation below the W* distance will be assumed for every inservice tube in the bounding SG.

c) Calculation of Accident Leakage The postulated leakage during a steam line break (SLB) shall be equal to the following equation:

Postulated SLB Leakage = ARC GL95-05 + Assumed Leakage o-.-<-r-rs+ Assumed Leakage 8"12

<'TS + Assumed Leakage >12- <'rTs Where: ARC GL95-05 is the normal SLB leakage derived from ARC methods and the SG tube inspections.

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

Assumed Leakage 12- <rS is the conservatively assumed leakage from the total of identified and postulated unidentified indications in SG tubes left in service between 8 and 12 inches E3-13

INSERT E (Continued) 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 112- <TTS is the conservatively assumed 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.

The aggregate calculated SLB leakage from the application of all ARC and the above assumed leakage shall be reported to the NRC in accordance with applicable technical specifications. The combined calculated leak rate from all ARC must be less than the maximum allowable SLB leak rate limit in any one SG in order to maintain doses within 10 CFR 100 guideline values and within GDC-19 values during a postulated SLB event.

E3-14

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)

E3-15

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).

Except for primary-to-secondary leakage, the safety analyses events APPLICABLE SAFETY ANALYSES do not address operational leakage. However, other o a leakage is related to the safety analyses for LOCA; the amount o ge can affect the probability of such an event. The safety analysis for resulting in steam discharge to the atmosphere ssumes a I ,,m pFimnrj to seRdarylakag as the Rtial Gon account for a maximum normal operational leakage of 0.4 gpm (0.1 gpm per steam generator or the equivalent of 150 gallons per day per steam generator).

August 4, 2000 SEQUOYAH - UNIT 2 B 3/4 4-4e Amendment No. 211,213,227,250 E3-16

REACTOR COOLANT SYSTEM steam generator tube rupture or a BASES I Primary to secondary leakag is a fa or in the dose releases outside containment resulting from a team H e break (SLB) accident. To a lesser extent, other accidents or transients volve secondary steam release to the atmosphere, such as a steam gen.rator tube rupture (SGTR). The leakage contaminates the secondary fluid. from all four SGs 110.4 gpm operational The FSAR (Ref. 3) analysis for S TR assumes the contaminated scondary jRC fluid is released via safety valve for up to 30 minutes. Operator actin is taken to isolate the affected steam g erator within this time period. The with ARC applied leakage, Sprimary to secondary leakage s relatively inconsequential.

' , *,, thro ug h the affected l The SLB is more limiting for site radiation releases. The safetyFanalysis for the SLB accident assumes 1-gpm primary to secondary leakage i ageneratorgs a maximum 3.7 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 beloN8&. 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 eye tV ion of crack indications results in primary-to-secondary leakage greater than 7-2. gpm in the faulted loop during a postulated steam line break event, additional tubes must be removed from service in order Sto reduce the postulated primary-to-secondary steam line break leakage to below

-&24-gpm. jand 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 E3-17

REACTOR COOLANT SYSTEM BASES sump level monitoring equipment can collectively detect within a I 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 Leakace throucah 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 conn Jons 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 INSERT G conservative.

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 or unexpectedly exten tside the thickness of the tube support e. Hence, the reduced leakage lim-t, hen combined with an effe e leak rate monitoring program, provides add* al assur that, should a significant leak be experienced, it will be ece 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 E3-18

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 PIVs 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: 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 <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and MODE 5 within the following 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />. 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:

UNIDENTIFIED LEAKAG IDENTI D LEAKAGE, or prima*y to secondary leakage in excess of the LCO limits mus e reduced to within limits within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. 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 pprevent further deterioration of the RCPB. If UNIDENTIFIED LEAKAGE, IDENTIFIED LEAKAGET or p.rimay to secondary leakage cannot be reduced to within limits within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />, 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 <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and MODE 5 within the following 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />. 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 E3-19

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 I C A V A 1 ',rn etir:t rm4 r4 hit rfrrm'nr- af DrI tar ;

1. in,', f Ih', nr-a ktrit 2 c;l U OLOIIIII IOU U)y ll1 UJ0I 11ll %I l J0 U i l l2, VV 'LOI IIIVuI

" u ILI y U CIC ImIuu.

The PIima.. to se...dar' leakage is. -a.lSo......a..ed by per.o.rmanc.e. of an R. S watc.

invenAtor balanco in conjunction *w ith Rffluent MAnitoring Within the 69eodar,'

steam and feod;;'ater systems.

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

I ootnote is added a;;'Iwig that this SR is not required to be performed until 12 ho s after establishing steady state operation. The 12-hour allowance provides suffi *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. states 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, INSERT H "Leakage Detection Instrumentation."

The 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> 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 7hi-ýellnceproids the means necessary to determine SG PWMT- i aoprto d0eU-herqieet to demonstra e integrity in JISET ZI J--

atnormal o " niios August 4, 2000 SEQUOYAH - UNIT 2 B 3/4 4-4i Amendment No. 211,213,227,250 E3-20

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."

5. 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 E3-21

... ,~

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 <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> 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 <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> 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).

E3-22