ML20078A725

Proposed Tech Specs Incorporating New Requirements Associated W/Sg Tube Insp & Repair,Establishing Alternate SG Tube Plugging Criteria at Tube Support Plate Intersections

ML20078A725
Person / Time
Site:	Sequoyah
Issue date:	06/28/1994
From:	TENNESSEE VALLEY AUTHORITY
To:
Shared Package
ML19304C313	List: ML20078A721 ML20078A725 ML20078A729 ML20078A730
References
NUDOCS 9407010088
Download: ML20078A725 (30)

Text

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ENCLOSURE 1 PROPOSED TECHNICAL SPECIFICATION (TS) CHANGE SEQUOYAH NUCLEAR PLANT (SON) UNIT 2 DOCKET NO. 50-328 (TVA-SON-TS-94-09)

LIST OF AFFECTED PAGES UNIT 2 3/4 4-11 3/4 4-12 3/4 4-13 3/4 4-14 3/4 4-18 B 3/4 4-3 B 3/4 4-4 9407020088 940628 PDR P

ADOCK 05000328 PDR

r-REACTCR CCOLANT SYSTEM SURVEILLANCE REDUIREMENTS (Continued)

1. All nonolugged tubes that previously had detectable wall pene-trations (greater tnan 20%).

2. Tubes in those areas where experience has indicateo potential problems. i

3. A tube inspection (pursuant to Specification 4.4.5.4.a.8) shall

, be performed on each selected t'ube. If any selected tube does i not permit the passage of the eddy current probe for a tube inspection, this shall be recorded and an adjacent tube snall be selected and subjected to a tube inspection.

c. The tubes selected.as the second and third samples (if recuired by Table 4.4-2) during each inservice inspection may be subjected to a  :

partial tube inspection provided:  !

1. The tubes selected for these samples include the tuces from I those areas of the tube sheet artt.y where tubes with imperfections were previously fovnd.

INSES*I. .

b 2. The inspections include those partions of the tubes where ER{ imperfections.were previously found.

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The results of each sample inspection shall be classified into one of the following three categories:

Ca tego ry. Inspection Results C-1 Less than 5% of'the total tubes inspected are

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degraded tubes and none of the inspected tubes i are defective.

C-2 One or more tubes, but not more tnan 1% of the total tubes inspected are defectiee, or between 5% and 10% of the total tubes inspected are degraded tubes, C-3 More than 10% of the total tubes inspected are degreced tubes or more than 1% of the inspected 4 1

tubes are defective.

Note: In all inspections, previously degraded tubes must exhibit significant (greater than 10%) further wall penetrations to be included in the above percentage calculations.

V SEQUOYAti - UNIT 2 3/4 4-11

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REACTOR COOLANT SYSTEM A

SURVEILLANCE REQUIREMENT 5 (Continued)

4. 4. 5. 3 :nspection Feecuencies - The above required inservice inspections of steam generator tuces snall De performed at the following frequencies:

a. The first inservice inspection shall be performed af ter 6 Ef fective Full Power Months out within 24 calendar months of initial criti-cality. Subsequent inservice .irispections'shall be performed at intervals of not less than 12 nor more than 24 calendar months after the previous inspection. If two consecutive inspections following service under AVT conditions, not including the preservice inspection, result in all inspection results falling into the C-1 category or if two consecutive inspections demonstrate that previously observed degradation has not continued and no additional degradation has occurred, the inspection interval may be extended to a maximum of once per 40 montns.

b. If the resalti of the inservice insoection of a steam generator-conducted in sccordance with Table 4.4-2 at 40 month intervals fall in Category C-3. the inspection frequency shall be increased to at

' east once per 20 months. The increase in inspection frequency shall apply until the subsequent inspections satisfy the criteria of Specification 4.4.5.3.a; the interval may then-be extended to a maximum of once per 40 months.

c. Additional, unscheouleo inservice inspections shall be performed on each steam generator in accordance with the first sample inspection specified in Table 4.4-2 during the shutdown subsequent to any of the following Conoitions:

1. Primary-to-secondary tubes leaks (not including leaks originating from tube-to-tube sheet welds) in excess of the limits of Specification 3.4.6.2.

2. A seismie occurrence greater than the Operating Basis Earthquake.

3. - A loss of-coolant accident requiring actuation of the engineered safeguards.

4 A main steam line or feecwater line break'.

INSERT B

HERE SEQUOYAH - UNIT 2 3/4 4-12

REACTOR COOLANT SYSTEM SURVEILLANCE REOUIREMENTS (Continued) 4.4.5.4 Acceotance Criteria '

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a. As used in tnis Specification;

1. Imoerfection means an exception to the dimensions, finish or

• contour of a tube from that required by fabrication drawings or specifications. Eddy-current testing indications below 20% of the nominal tubu wall thickness, if detectable, may be con-sidered as imperfections.  ;

2. Degradation means a service-induced cracking, wastage, wear or general corrosion occurring on either inside or outside af a tube.

3. Decraded Tube means a tube containing imperfections greater than or equal to 20% of trie nominal wall thickness caused by degradation.

4.  % Oegradation means the percentage of the tube wall thickness affected or removed by degradation.

5. Defect means an imperfection of such sever'ity that it exceecs  ;

tne plugging limit. A tube containing a defect is defective.

6. Pluccino Limit means the imperfection depth at or beyond which M$EA tne tuce snall be removed from service and is equal to 40%

f th' " *i"'I C -

t'D' **l l thick"'553 ,

Ekd[ ' 7. Unserviceable describes the condition of a tube if it leaks or ,

contains a defect large enough to affect its structural integ- '

rity in the event of an Operating Basis Earthquake, a loss-of-coolant accident, or a steam line or feedwater line break as specified in 4.4.5.3.c, above.

. 8. Tube Inspection means an inspection of the steam generator tube from the point of entry (hot leg side) completely around the U-band to the top support of the cold leg. ,

SEQUOYAH - UNIT 2 3/4 4-13

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l INSERT A Implementation of the steam generator tube / tube support plate interim plugging criteria for one fuel cycle (Cycle 7) requires a 100% bobbin probe inspection for all hot leg tube support plate intersections and all cold leg intersections down to the lowest cold leg tube support plate with outer diameter stress corrosion cracking (ODSCC) indications.

INSERT B

d. Tubes left in service as a result of application of the tube support plate' interim plugging criteria shall be inspected by bobbin coil probe during all future refueling catages.

INSERT C .

This definition does not apply for tubes experiencing outer diameter stress corrosion cracking confirmed by bobbin probe inspection to be within the thickness of the tube support plates. See 4.4.5.4.a.10 for plugging limit for use within'the thickness of'the tube support plate.

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_ REACTOR COOLANT SYSTEM _

5URVEILLANCE REQUIREMENTS (Continued) 9.

Preservice Inspection means an inspection of the full length of each tube in each steam generator. performed by eddy current techniques the tubing. prior to service to establish a baseline condition of POWER OPERATION using the equipment and tech be used during subsequent inservice inspections. '

b.

gg The steam generator shall be detemined OPERABLE af ter completing D the corresponding actions (plug all tubes exceeding the plugging limit and Table all tubes containing through-wall cracks) required by 4.4-2.

HEAE 4.4.5.5 Reports a.

Following each inservice inspection of steam generator tubes,.the number the of tubeswithin Comission plugged in each steam generator shall be reported to 15 days.

b.

The complete results of the s' team generator tube inservice inspection shall be submitted to the Commission in a Special Report pursuant to Specification inspection. 6.9.2 within 12 months following the completion of the This Special Report shall include:

1.

Ntaber and extent of tubes inspected.

2.

Location and percent of wall-thickness penetration for each i indication of an imperfection, i t

3.

Identification of' tubes plugged.

c.

Results of steam generator tube inspections which fall .into Category '

C-3 tion of shall be operation.

plant reported pursuant to Specification 6.6.1 prior to resump-The written followup of this report shall R2B provide a description of investigations conducted to determine cause of the tube degradation and corrective measures taken to prevent recurrence.

INS 1 E  ? i HME  ;

SEQUOYAH - UNIT 2 November 23, 1984 3/4 4-14 Amendment No. 28

1 INSERT D j l

10. The Tube Support Plate Interim Pluerine Criteria is used for disposition of a steam generator tube for continued service that is l

experiencing outer diameter initiated stress corrosion cracking confined within the thickness of the tube support plates. For  !

application of the tube support plate interim plugging limit, the I tube's disposition for continued service will be based upon standard bobbin probe signal amplitude. The plant-specific guidelines used for allinspections shall be amended as appropriate to accommodate the additionalinformation needed to evcinate tube support plate signals with respect to the voltage / depth parameters. Pending incorporation

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of the voltage verification requirement in AShE standard verifications, an AShE standard calibrated against the laboratory (see WCAP-139904)1 standard.will be utilized in the Sequoyah Nuclear Plant Unit 2 steam generator inspections for consistent voltage normalization.

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1. A tube can remain in service if the signal amplitude of a cracle indication is less than or equal to 2.0 volts, regardless of the depth of tube wall penetration,if, as a result, the projected ,

end-of-cycle distribution of crack indications is verified to result i in primary-to-secondary leakage less than 4.3 gpm in the faulted loop during a postulated steam line break event. The ,

methodology for calculating expected leak rates from the I projected crack distribution must be consistent with WCAP-13990, Rev. 0, and as prescribed in Draft NUREG-1477.

2. A tube should be plugged or repaired if the signal amplitude is greater than 2.0 voltsercept as noted in Specification 4.4.5.4.a.10.3 below.

3. A tube can remain in service with a bobbin coil signal amplitude greater than 2.0 voltsbut less than or equal to 3.6 volts if a rotating pancake probe inspection does not detect i degradation. Indications of degradation with a bobbin coil I signal amplitude greater than 3.6 volts will be plugged or repaired.

. INSERT E

d. The results ofinspections performed under 4.4.5.2 for all tubes in which the tube support plate elevations interim plugging limit has been applied and where not plugged shall be reported to the Commission within 15 days following the inspection. The report shallinclude:

1. Listing of applicable tubes.

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2. Location (applicable intersections per tube) and extent of degradation (voltage).

e. The result of steam line break leakage analysis performed under T/S 4.4.5.4.a.10 will be reported to the Commission prior to restart for Cycle 7.

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l REACTOR COOLANT SYSTEM OPERATIONAL LEAKAGE * -;

I LIMITING CONDITION FOR OPERATION

.4.5.2 Reactor Coolant System leakage shall be limited to:

a. No PRESSURE BOUNDARY LEAKAGE, i

b. 1 GPM UNIDENTIFIED LEAKAGE, l D M--6fultotal primary-to-secondary leakage through all steant generators 400epJ and tis 5B gallons per day througn any one steam generator,  ;

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

/50 '

e. 40 GPM CONTROLLED LEAKAGE at a Reactor Coolant System pressure of 1

2235 20 psig. ,

f. 1 GPM leakage at a Reactor Coolant System pressure of 2235 20 psig frem any Reactor Coolant System Pressure Isolation Valve specified in t Tcble 3.4-1.

l APPLICABILITY: H0 DES 1, 2, 3 and 4 t ACTION:

{

a. With any PRESSURE BOUNDARY LEAKAGE, he 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 w] thin 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 f above limits, excluding PRESSURE BOUNDARY LEAKAGE, and leakage from Reactor Coolant System Pressure Isolation Valves, reduce the leakage rate to within limits within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> or be in at least HOT STANDBY.

within 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 />.

.)

c. With any Reactor Coolant System Pressure Isciation Valve leakage greater than the above limit, isolate the high pressure portion of 1 the affected system from the low pressure portion within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> by use of at least two closed manual or deactivated automatic valves, 4 '

or be in at least HOT STANDBY within 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 1 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 SURVEILLANCE REQUIREMENTS 4.4.6.2.1 Reactor Coolant System leakages shall be demonstrated to be within each of the above limits by:

SEQUOYAH - UNIT 2 3/4 4-18 l

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REACTOR COOLANT SYSTEM i

- BASES -

3/4.4.5 STEAM GENERATORS The Surveillance Requirements for inspection of the steam generator tubes.

The program for inservice inspection of steam generator tubes is based o modification of Regulatory Guide 1.83, Revision 1. Inservice inspection of steam generator tubing is essential in order to maintain surveillance of the conditions of the tubes in the event that there is evidenc'e of mechanical +

damage or progressive degradation due to design, manufacturing errors, or '

inservice conditions that lead to corrosion. Inservice' inspection of steam generator tubing also provides a means of characterizing the nature and cause of any tube degradation so that corrective measures can be taken.

The plant is expected to be operated in a manner such that the secondary

• coolant will be maintained within those chemistry limits found to result in negligible corrosion of the steam generator tubes. If the secondary coolant chemistry is not maintained within tnese limits, localized corrosion may likely result in stress corrosion cracking. The extent of cracking during plant operation would be limited by the limitation of steam generator tuggr 150 1eaka e between the primary coolant system and the secondary coolant sysips <

(primary-to-secondary leakage 2 E gallons per day per steam generator)4 Cracks having a primary-to-secondary leakage less than this limit during '

operation will have an adequate margin of safety to withstand the loads i

'moosed durino normal operation and by postulated accidents. Operating plants ,

have demonstrated that primary-to-secondary leakage of 3991 gallons per day per steam generator can readily be detected.ry c: =:n nr:::r: :: :::= ::n: :te-' ,

!EowdowH Leakage in excess of this limit will require plant shutdown and an unscheduled inspection, during which the leaking tubes will be located and i plugged. i re 'rI;dd g .

• Wastage-type defects are unlikely with proper chemistry treatment of the secondary coolant. However, even if a defect should develop in service, it Yd"b.

4,4,5. 4.a will be found during scheduled inservice steam generator tube examinations.

4 g Plugging will be recuired for all tubes with imperfections exceeding the m ir 'fru :f m 25 W r M ! er!' LM crre! Steam generator -l

' ubFinspections of operating plants have demonstrated the capability to.

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reliably detect degradation that has penetrated 20% of the original tube wall gg thickness. J F whenever the results of any steam generator tubing inservice inspection M fall inta Category C-3, these results will be promptly reported to the Commission ,

pursuant to Specification 6.9.1 prior to resumption of plant operation. Such cases will be considered by the Commission on a case-by-case basis and may  ;

result in a requirement for analysis, laboratory examinations, tests, additional l eddy-current inspection, and revision of the Technical Specifications, if necessary.

v SEQUOYAH - UNIT 2 8 3'/4 4-3 l

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REACTOR COOLANT SYSTEM

-l BASES 3/4.4.6 REACTOR COOLANT SYSTEM LEAKAGE 3/4.4.6.1 t

LEAKAGE DETECTION SYSTEMS The RCS leakage detection systems required.by this specification are provided to monitor and detect leakage f. rom the Reactor Coolant Pressure Bounda ry. These detection systems are consistent with the recommendations of Regulatory Guide 1.45, " Reactor Coolant Pressure Boundary Leakage Detection Systems," May 1973.

3/4.4.6.2 OPERATIONAL LEAKAGE i

Industry experience has shown that while a limited amount of leakage is expected from the RCS, the unidentified portion of this leakage can be reduced to a threshold value of less than 1 GPM. This threshold value is sufficiently low to ensure early detection of additional leakage.

The surveillance requirements for RCS Pressure Isolation Valves provide  ;

added assurances of valve integrity thereby reducing the probability of gross '

valve failure and consequent intersystem LOCA. Leakage from the RCS isolation valves is IDENTIFIED LEAKAGE and will be considered as a portion of the allowed limit.

The 10 GPM IDENTIFIED LEAKAGE limitation provides allowance for a limited amount of leakage from known sources whose presence will not interfere with the detection of UNIDENTIFIED LEAKAGE by the leakage detection systems.

The CONTROLLED LEAKAGE limitation restricts operation when* the total flow supplied to the reactor coolant pump seals exceeds 40 GPM with the modulating valve in the supply line fully open at a nominal RCS pressure of 2235 psig.

This limitation ensures that in the event of a' LOCA, the safety injection flow will not be less than assumed in the accident analyses.

The otal ste generato tube lea ge Itait ' 1 GPM for 11 steam enerators ot isolat from th RCS ensu ts that th dosage con ribution rom t

tube lea (ge wi,ll b limited oasmalt\ fraction Part 100 imits ir, he 4 eve of eithe a steam nerator be ruptu or steam line break. The 1 G M limit s consist t with t assumpt ns used the ana sis of the e accide 5.

DP'E gy The 500 d leakag limit pe steam ge rator e ures that team gene tor tube inte ity is ma tained i the eve of a ma steam 11 e rupture r  !

Gk under LOCA nditions.

MEE PRESSURE BOUNDARY LEAKAGE of any magnitude is unacceptable since it may be indicative of an impending gross failure of the pressure boundary. Therefore, the presence of any PRESSURE BOUNDARY LEAKAGE requires the unit to be promptly placed in COLD SHUTDOWN.

SEQUOYAH - UNIT 2 B 3/4 4-4

l INSERT F Tubes experiencing outer diameter stress corrosion cracking within the thickness of the tube support plate are plugged or repaired by the criteria of 4.4.5.4.a.10.

INSERT G Maintaining an operating leakage limit of 150 gpd per steam generator (600 gpd total) for Cycle 7 will minimize the potential for a large leakage event during steam line break. 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 below 4.3 gpm in the faulted loop, which will limit the calculated offsite doses to within 10% of the 10 CFR

' 100 guidelines. Leakage in the intact loops is limited to 150 gpd. If the projected end of cycle distribution oIcrack' indications results in primary-to-secondary leakage greater than 4.3 gpm in the faulted loop during a postulated steam line break event, additional tubes must be removed from service in order to reduce the postulated primary-to-secondary steam line break leakage to below 4.3 gpm.

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ENCLOSURE 2 PROPOSED TECHNICAL SPECIFICATION (TS) CHANGE  !

SEQUOYAH NUCLEAR PLANT (SON) UNIT 2 DOCKET NO. 50-328 i (TVA-SON-TS-94-09) l l

DESCRIPTION AND JUSTIFICATION FOR TS AMENDMENT i

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Description of Chanae TVA proposes to modify the SON Unit 2 technical specifications (TSs) to incorporate new requirements associated with steam generator (S/G) tube inspection and repair.

The new requirements establish alternate S/G tube plugging criteria at tube support plate (TSP) intersections. The proposed changes are as follows:

1. Add requirements to Surveillance Requirement (SR) 4.4.5.2.c.2

" Implementation of the steam generator tube / tube support plate interim plugging criteria for one fuel cycle (Cycle 7) requires a 100% bobbin probe inspection for all hot leg tube support plate intersections and all cold leg intersections down to the ,

lowest cold leg tube support plate with outer diameter stress corrosion cracking (ODSCC) indications."

2. Add SR 4.4.5.3.d.

" Tubes left in service as a result of application of the tube support plate interim plugging criteria shall be inspected by bobbin coil probe during all future refueling outages."

3. Add clarification statements to SR 4.4.5.4.a.6.

"This definition does not apply for tubes experiencing outer diameter stress corrosion cracking confirmed by bobbin probe inspection to be within the thickness of the tube support plates. See 4.4.5.4.a.10 for plugging limit for use within the thickness of the tube support plate."

4. Add SR 4.4.5.4.a.10.

"The Tube Sucoort Plate Interim Pluaaina Criteria is used for disposition of a steam generator tube for continued service that is experiencing outer diameter initiated  ;

stress corrosion cracking confined within the thickness of the tube support plates.

For application of the tube support plate interim plugging limit, the tube's disposition for continued service will be based upon standard bobbin probe signal amplitude. The plant-specific guidelines used for all inspections shall be amended as appropriate to accommodate the additionalinformation needed to evaluate tube support plate signals with respect to the voltage / depth parameters. Pending incorporation of the voltage verification requirement in ASME standard verifications, an ASME standard calibrated against the laboratory standard (see WCAP-13990, Rev. 0) will be utilized in the Sequoyah Nuclear Plant Unit 2 steam generator inspections for consistent voltage normalization."

"1. A tube can remain in service if the signal amplitude of a crack indication is less than or equal to 2.0 volts, regardless of the depth of tube wall penetration, if, as a result, the projected end-of-cycle distribution of crack l

k i

?m : 7 indications is verified to result in primary-to-secondary leakage less than 4.3 gpm in the f aulted loop during a postulated steam line break event. The methodology for calculating expected leak rates from the projected crack distribution must be consistent.with WCAP-13990, Rev. O, and as prescribed '

in Draft NUREG-1477.

"2. A tube should be plugged or repaired if the signal amplitude is greater than 2.0 volts except as noted in Specification 4.4.5.4.a.10.3 below.

"3. A tube can remain in service with a bobbin coil signal amplitude greater than 2.0 volts but less than or equal to 3.6 volts if a rotating pancake probe inspection does not detect degradation. Indications of degradation with a bobbin coil signal amplitude greater then 3.6 volts will be plugged or repaired."

5. Add SRs 4.4.5.5.d and 4.4.5.5.e.

"d. The results of inspections performed under 4.4.5.2 for all tubes in which the

• tube support plate elevations interim plugging limit has been applied and where not plegged shall be reported to the Commission within 15 deys following the inspection. The report shall include:

"1. Listing of applicable tubes.

"2. Location (applicable intersections per tube) and extent of degradation (voltage).

"e. The result of steam line break leakage analysis performed under T/S 4.4.5.4.a.10 will be reported to the Commission prior to restart for Cycle 7."

6. Change Limiting Condition for Operation (LCO) 3.4.6.2.c to state:

"600 gpd total primary-to-secondary leakage through all steam generators and 150 gallons per day through any one steam generator."

7. Change Bases 3/4.4.5, " Steam Generators," to reflect the new primary-to-secondary leakage limit (150 gallons per day per S/G) and include a reference to the tube repair limit as defined in Specification 4.4.5.4.a. In addition, Bases Section 3/4.4.6.2, " Operational Leakage," is revised to reflect the S/G operational leakage limits. ,

Reason for Channe TVA is proposing to change the SON Unit 2 TSs to reduce the need for repairing or >

plugging S/G tubes having indications that exceed the current TS depth-based plugging limit. TVA proposes to add alternate tube plugging criteria at tube support plate (TSP) intersections that are based on maintaining structural and leakage integrity of tubes with indications within the TSP regions. The alternate plugging criteria (APC) are an interim criteria that are applicable to Unit 2 Cycle 7 operation. Westinghouse Electric

Corporation has performed analyses to: (1) show that indications within the TSP region meet Regulatory Guide (RG) 1.121 criteria for tube structuralintegrity, and (2) leakage in a f aulted condition remains below that assumed in calculating the allowable offsite radiation dose limits.

The proposed change would preserve the reactor coolant flow margin and reduce the radiation exposure incurred in the process of plugging or repairing S/G tubes (approximately 0.060 man-rem per tube of exposure would be saved for a plugging operation). Oiher benefits of not plugging TSP indications that meet the interim l plugging criteria (IPC) would be a reduction in man-hours and potentialimpact to l critical path time during the Unit 2 Cycle 6 refueling outage.

TVA's goal is to prolong S/G life over the expected plant life of 40 years. This goal is best achieved by proactive measures that defer or eliminate the need to replace S/Gs.

S/G replacement results from the foss-of-tube plugging margin. Accordingly, the proposed TS change would prolong S/G life and reduce personnel exposure while maintaining the SON S/G plugging margin.

Justification for Channes The proposed IPC for SON Unit 2 can be summarized as follows:

Tube Plugging Criteria Tubes with bobbin flaw indications exceeding the 2.0-volt IPC voltage repair limit and less than or equal to 3.6 volts are plugged or repaired if confirmed as flaw indications by RPC inspection. Bobbin flaw indications greater than 3.6 volts attributable to ODSCC are repaired or plugged independent of RPC confirmation.

Operating Leakage Limits Plant shutdown will be implemented if normal operating leakage exceeds 150 gallons per day per S/G.

Steam Line Break (SLB) Leakage Criterion Projected end-of-cycle SLB leak rate from tubes left in service, including a probability of detection (POD) adjustment and allowances for nondestructive examination (NDE) uncertainties and ODSCC growth rates, must be less than 4.3 gallons per minute (gpm) for the S/G in the faulted loop. If necessary to satisfy the allowable leakage limit, additional indications less than the repair limit shall be plugged or repaired.

Tube Burst Probability The projected end-of-cycle SLB tube burst probability shall be calculated and compared with the value of 2.5 x 102 found acceptable in NUREG-0844.

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i Exclusions from Tube Plugging Criteria ,

1 Indications excluded from application of the IPC repair limits include:

1. indications found by inspection (bobbin or RPC) to extend outside the TSP,

2. indications not attributable to ODSCC, and

3. circumferentialindications.

These indications shall be evaluated to the TS limit at 40 percent depth.

Inspection requirements to be fulfilled if the proposed IPC is implemented at SQN are as follows:

Eddy current analysis guidelines and voltage normalization must be consistent with that of Westinghouse Commercial Atomic Power (WCAP) 13990 Appendix A.

Eddy current analysts shall be trained specifically to voltage sizing in accordance with the WCAP-13990 Appendix A analysis guidelines, and at least lead analysts shall be qualified to the industry standard Qualified Data Analysis program of the Electric Power Research Institute (EPRI) Pressurized Water Reactor S/G Examination Guidelines.

Use of American Society of Mechanical Engineers (ASME) standards cross-calibrated to the reference laboratory standard and use of a probe wear standard requiring probe replacement at a voltage change of 15 percent from that found for the new probe shall be implemented in accordance with WCAP-13990 Appendix A.

100 percent bobbin coil examination of all hot leg TSPs and all cold leg TSPs at which ODSCC has been detected will be primarily performed with a 0.740-inch-diameter bobbin probe (0.720 bobbin coil probes may also be utilized).

RPC inspection of all bobbin indications greater than the 1.5 volts shall be inspected to confirm axial ODSCC as the dominant mechanism for indications at the TSPs.

RPC sample inspection of at least 100 TSP intersections with dents or artifact / residual signals that could potentially mask a 2.0-volt bobbin coil signal.

The RPC sample shall emphasize dented TSP intersections, but include artif act signals that the analysts judge could mask a repairable indication. Any RPC detected flaw indication in this sample will be plugged or repaired.

The projected end-of-cycle SLB tube burst probability shall be calculated and compared with the value of 2.5 x 10-2 found acceptable in NUREG-0844.

NRC will be informed before plant restart from the Unit 2 Cycle 6 refueling outage of any unexpected inspection findings relative to the assumed characteristics of the flaws at the TSP intersections. This includes any detectable circumferential indications or detected ODSCC indications extending outside the thickness of the TSP.

SON's current TS plugging limit of 40 percent throughwall applies throughout the tube length and is based on the tube structuralintegrity for general area wallloss such as pitting or wear. The proposed IPC for SON Unit 2 applies the criteria approved for Farley Unit 1 and D. C. Cr ok Unit 1 nuclear plants. This IPC includes inspection requirements and the 2.0-volt repair criteria. SLB analyses utilize methods and data described in the Farley Unit 1 and D.C. Cook Unit 1 safety evaluation reports.

Tube plugging criteria are based upon the conservative assumptions that the tube to TSP crevices are open (negligible crevice deposits or TSP corrosion) and that the TSPs are displaced under accident conditions. The ODSCC existing within the TSPs is thus assumed to be free-span degradation under accident conditions and the principal requirement for tube plugging considerations is to provide margins against tube burst in accordance with RG 1.121. The open crevice assumption leads to maximum leak rates compared with packed crevices and also maximizes the potential for TSP displacements under accident conditions.

Two pulled TSPs from SON Unit 1 support ODSCC as the dominant corrosion mechanism consistent with the EPRI database of pulled tubes. The EPRI database, which includes the SON pulled tube data, is more conservative for SLB leak rate analyses using draf t NUREG-1477 methodology than the data obtained from the SON pulled tubes. Therefore, the more conservative EPRI database is used for all SLB analyses.

RG 1.121 guidelines establish the structurallimit as the more limiting of three times normal operating pressure differential (3 APyo) or 1.43 times the SLB pressure differential (1.43APsta) at accident conditions. At normal operating conditions, the tube constraint provided by the TSP assures that 3APuo burst capability is satisfied.

At SLB conditions, the EPHI alternate repair criteria (ARC) are based on free-span indications under the conservative assumption that SLB TSP displacements uncover the ODSCC indications formed within 9e TSPs at normal operation. From Figure 6-1 of WCAP-13990 (Enclosure 4), the b abin voltage corresponding to 1.43APst o (3,657 pounds per square inch { psi is 8.82 volts. The structurallimit must be reduced by allowances for NDE uncertainties and crack growth during the Cycle 7 fuel cycle. The EPRI ARC apply the NDE uncertainty (WCAP-13990 Section 7.3) at 95 percent uncertainty to obtain an allowance of 20.5 percent of the repair limit. For Sequoyah, there is insufficient prior ODSCC data to define the voltage growth rates. In EPRI Report TR-100407, Draf t Revision 1, "PWR Steam Generator Tube Repair Limit - Technical Support Document for Outside Diameter Stress Corrosion Crack at Tube Support Plates," the EPRI criteria provide a growth allowance of 35 percent per effective full power years (EFPY) when plant specific growth data is not available. For SON, the near-term cycle lengths are bounded by 1.23 EFPY. The growth allowance for SON is then 43.1 percent. The full alternate plugging criteria repair limit is obtained by dividing the structurallimit of 8.82 volts by 1 plus 64 percent (20.5 percent for NDE uncertainties and 43 percent for crack voltage growth). Thus, the full EPRI APC defined repair limit is obtained as 5.4 volts. The Farley Unit 1 and D.C. Cook Unit 1 IPC conservatively applied 3.6 volts for the full repair limit. Since the proposed SON IPC follows this precedence, the 3.6-volt limit is also applied for the SON IPC repair limit. This repair limit

6-conservatively bounds the IPC limit obtained by applying either the EPRI database, as described above, or the NRC database additions described in WCAP-13990, l Section 5.1. l EnvironmentalImpact Evaluation The proposed change does not involve an unreviewed environmental question because operation of SON Unit 2 in accordance with this change would not:

1. Result in a significant increase in any adverse environmentalimpact previously evaluated in the Final Environmental Statement (FES) as modified by NRC's testimony to the Atomic Safety and Licensing Board, supplements to the FES, environmentalimpact appraisals, or decisions of the Atomic Safety and Licensing Board.

2. Result in a significant change in effluent or power levels.

3. Result in matters not previously reviewed in the licensing basis for SON that may have a significant environmentalimpact.

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ENCLOSURE 3 PROPOSED TECHNICAL SPECIFICATION (TS) CHANGE SEQUOYAH NUCLEAR PLANT (SON) UNIT 2 DOCKET NO. 50-328 (TVA-SON-TS-94-09) DETERMINATION OF NO SIGNIFICANT HAZARDS CONSIDERATION l l 4

l Significant Hazards Evaluation l TVA has evaluated the proposed TS change and has determined that it does not i represent a significant hazards consideration based on criteria established in 10 CFR 50.92(c). Operation of Sequoyah Nuclear Plant (SON) in accordance with the proposed amendment will not:

1. Involve a significant increase in the probability or consequences of an accident previously evaluated.

Testing of model boiler specimens for free-span tubing (no tube support plate restraint) at room temperature conditions shows burst pressures in excess of ' 500 pounds per square inch (psi) for indications of outer-diameter stress corrosion . cracking with voltage measurements as high as 19 volts. Burst testing performed on intersections pulled from SON with up to a 1.9-volt indication shows measured burst pressure in excess of 6,600 psi at room temperature. Burst testing  ; performed on pulled tubes from other plants with up to 7.5-volt indications shows burst pressures in excess of 6,300 psi at room temperatures. Correcting for the effects of temperature on material properties and minimum strength levels (as the burst testing was done at room temperature), tube burst capability significantly , exceeds the safety-factor requirements of NRC Regulatory Guide (RG) 1.121. , Tube burst criteria are inherently satisfied during normal operating conditions  : because of the proximity of the tube support plate (TSP). Tcst data indicates that tube burst cannot occur within the TSP, even for tubes that have 100 percent throughwall electrodischarge machining notches,0.75-inch long, provided that the TSP is adjacent to the notched area. Since tube-to-tube support plate proximity

• precludes tube burst during normal operating conditions, use of the criteria must retain tube integrity characteristics that maintain a margin of safety of 1.43 times  ;

the bounding faulted condition steam line break (SLB) pressure differential. During a postulated SLB, the TSP has the potential to deflect during blowdown following a main SLB, thereby uncovering the TSP intersections. , I Based on the existing database, the RG 1.121 criterion requ; ring maintenance of a safety factor of 1.43 times the SLB pressure differential on tube burst is satisfied by 7/8-inch-diameter tubing with bobbin coil indications with signal amplitudes  ; less than 8.82 volts, regardless of the indicated depth measurement. A 2.0 volt ' p!ugging criterion (resulting in a projected end-of-cycle {EOC} voltage) compares , favorably with the 8.82-volt structurallimit considering the extremely slow  ; apparent voltage growth rates and few numbers of indications at SON. Using the established methodology of RG 1.121, the structurallimit is reduced by allowances for uncertainty and growth to develop a beginning of cycle (BOC) repair limit that would preclude indications at EOC conditions that exceed the structurallimit. The nondestructive examination (NDE) uncertainty component is 20.5 percent, and is based on the Electric Power Research Institute (EPRI)  ;

                                                                                                 ~

alternate repair criteria (ARC).

l Because of the few number of indications at SON, the EPRI methodology of applying a growth component of 35 percent per effective full power year (EFPY) will be used. Near-term operating cycles at SON are expected to be bounded by  ; 1.23 years, therefore, a 43 percent growth component is appropriate. When  ; these allowances are added to the BOC interim plugging criteria of 2.0 volts in a deterministic bounding EOC voltage of approximately 3.26 volts for Cycle 7, operation can be established. A 5.56-volt deterministic safety margin exists  ! (8.82 structural limit - 3.26-volt EOC equal 5.56-volt margin). l l For the voltage / burst correlation, the EOC structurallimit is supported by a voltage of 8.82 volts. Using this structurallimit of 8.82 volts, a BOC maximum allowable > repair limit can be established using the guidance of RG 1.121. The BOC maximum allowable repair limit should not permit the existence of EOC indications , that exceed the 8.82-volt structurallimit. By adding NDE uncertainty allowances i and an allowance for crack growth to the repair lirait, the structurallimit can be validated. Therefore, the maximum allowable BOC repair limit (RL) based on the  ! structurallimit of 8.82 volts can be represented by the expressions: l RL + (0.205 x RL) + (0.43 x RL) = 8.82 volts, or, j the maximum allowable BOC repair limit can be expressed as,  ! i RL = 8.82-volt structurallimit/1.64 = 5.4 volts. It is reasonable that this RL (5.4 volts) could be applied for interim plugging j criteria (IPC) implementation to repair bobbin indications greater than 2.0 volts independent of rotating pancake coil (RPC) confirmation of the indication. Conservatively, an upper limit of 3.6 volts will be used to assess tube integrity for those bobbin indications that are above 2.0 volts but do not have confirming RPC , calls. This 3.6-volt upper limit for nonconfirmed RPC calls is consistent with other  ! recently approved IPC programs. The conservatism of the growth allowance used to develop the repair limit is  ; shown by the most recent SON eddy current data. Two tubes plugged in Unit 1 during the last outage had less than one volt of growth over the past five operating cycles. Only one tube in Unit 2 required repair because of outer-diameter stress corrosion cracking (ODSCC) at the TSP intersections.

Relative to the expected leakage during accident condition loadings, it has been previous;y established that a postulated main SLB outside of containment, but l upstream of the main steam isolation valve (MSIV), represents the most limiting [

radiological condition relative to the IPC. In support of implementation of the IPC, it will determine whether the distribution of cracking indications at the TSP intersections at the end of Cycle 7 for Unit 2 is projected to be such that , primary-to-secondary leakage would result in site boundary doses within a small l fraction of the 10 CFR 100 guidelines. A separate analysis has determined this , l l l l i

allowable SLB leakage limit to be 4.3 gallons per minute (gpm) in the faulted loop. This limit uses the TS reactor coolant system (RCS) lodine-131 activity level of 1.0 microcuries per gram dose equivalent lodine-131 and the recommended lodine-131 transient spiking values consistent with NUREG-0800. The projected SLB leakage rate calculation methodology prescribed in Section 3.3 of draft NUREG-1477 is used to calculate EOC leakage. Because of the relatively low number of indications at SON, it is expected that the actualleakage values will be far less than this limit. Additionally, the current lodine-131 levels at SON range from about 25 to 100 times less than the TS limit of 1.0. Application of the criteria requires the projection of postulated SLB leakage, based on the projected EOC voltage distribution for Cycle 7. Projected EOC voltage distribution is developed using the most recent EOC eddy current results and a voltage measurement uncertainty. Data indicates that a threshold voltage of 2.8 volts would result in throughwall cracks long enough to leak at SLB condition. Draft NUREG-1477 requires that all indications to which the IPC are applicd must be included in the leakage projection. Tube pull results from another plant with 7/8-inch tubing with a substantial voltage growth database have shown that tube wall degradation of greater than 40 percent throughwall was readily detectable either by the bobbin or RPC probe. The tube with maximum throughwall penetration of 56 percent (42 average) had a voltage of 2.02 volts. This indication also was the largest recorded bobbin voltage from the EOC eddy current data. Based on the SON pulled tube and industry pulled tube data supporting a tower threshold for SLB leakage of 2.8 volts, inclusion of all IPC intersections in the leakage model is quite conservative. The ODSCC occurring at SON is in its earliest stages of development. The conservative bounding growth estimations to be applied to the expected small number of indications for the upcoming inspection should result in very smalllevels of predicted SLB leakage. Historically, SON has not identified ODSCC as a contributor to operationalleakage. The current leakage level at SON is less than 1.0 gallon per day (gpd). In order to assess the sensitivity of an indication's BOC voltage to EOC leakage potential, a Monte Carlo simulation was performed for a 2.0-volt BOC indication. The maximum EOC voltage (at 99.8 percent cumulative probability) was found to be 4.8 volts. Using NUREG-1477 and EPRIleakage models, the leakage component from an indication of this magnitude is 0.12 and 0.028 gpm, respectively. Therefore, as implementation of the 2.0-volt IPC criterion during Cycle 7 in Unit 2 - does not adversely affect steam generator (S/G) tube integrity and implementation will be shown to result in acceptable dose consequences, the proposed amendment does not result in any increase in the probability or consequences of an accident previously evaluated.

2. Create the possibility of a new or different kind of accident from any previously analyzed, implementation of the proposed S/G tube IPC criteria does not introduce any significant changes to the plant design basis. Use of the criteria does not provide ';

a mechanism that could result in an accident outside of the region of the TSP elevations; no ODSCC is occurring outside the thickness of the TSP. Neither a single or multiple tube rupture event would be expected in a S/G in which the plugging criteria have been applied (during all plant conditions). TVA willimplement a maximum leakage rate limit of 150 gpd per S/G to help preclude the potential for excessive leakage during all plant conditions. The SON TS limits on primary-to-secondary leakage at operating conditions are to be a maximum of 0.42 gpm (600 gpd) for all S/Gs, or, a maximum of 150 gpd for any one S/G. The RG 1.121 criterion for establishing operationalleakage rate limits that require plant shutdown is based upon leak-before-break considerations to detect a free-span crack before potential tube rupture during f aulted plant conditions. The 150-gpd limit should provide for leakage detection and plant shutdown in the event of the occurrence of an unexpected single crack resulting in leakage that is associated with the longest permissible crack length. FIG 1.121 acceptance criteria for establishing operating leakage limits are based on leak-before-break considerations such that plant shutdown is initiated if the leakage associated with the longest permissible crack is exceeded. The longest  : permissible crack is the length that provides a factor of safety of 1.43 against bursting at faulted conditions maximum pressure differential. A voltage amplitude of 8.82 volts for typical ODSCC corresponds to meeting this tube burst requirement at a lower 95 percent prediction limit on the burst correlation coupled with 95/95 lower tolerance limit material properties. Alternate crack morphologies. can correspond to 8.82 volts so that a unique crack length is not defined by the j burst pressure versus voltage correlation. Consequently, typical burst pressure , versus through-wall crack length correlations are used below to define the l

                " longest permissible crack" for evaluating operating leakage limits,                     j The single through-wall crack lengths that result in tube burst at 1.43 times the SLB pressure differential and the SLB pressure differential alone are approximately 0.57 inch and 0.84 inch, respectively. A leak rate of 150 gpd will provide for detection of 0.4-incn-long cracks at nominalleak rates and 0.6-inch-long cracks at the lower 95 percent confidence level leak rates. Since tube burst is precluded during normal operation because of the proximity of the TSP to the tube and the potential exists for the crevice to become uncovered during SLB conditions, the leakage from the maximum permissible crack must preclude tube burst at SLB conditions. Thus, the 150-gpd limit provides for plant shutdown before reaching critical crack lengths for SLB conditions. Additionally, this leak-before-break evaluation assumes that the entire crevice area is uncovered during blowdown.

Partial uncover will provide benefit to the burst capacity of the intersection.

As S/G tube integrity upon implementation of the 2.0-volt IPC continues to be maintained through in-service inspection and primary-to-secondary leakage monitoring, the possibility of a new or different kind of accident from any accident previously evaluated is not created.

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

The use of the voltage based bobbin probe interim TSP elevation plugging criteria at SON is demonstrated to maintain S/G tube integrity commensurate with the criteria of RG 1.121. RG 1.121 describes a method acceptable to the NRC staff for meeting General Design Criteria (GDC) 14,15,31, and 32 by reducing the probability or the consequences of S/G tube rupture. This is accomplished by determining the limiting conditions of degradation of S/G tubing, as established by in-service inspection, for which tubes with unacceptable cracking should be removed from service. Upon implementation of the criteria, even under the worst-case conditions, the occurrence of ODSCC at the TSP elevations is not expected to lead to a S/G tube rupture event during normal or faulted plant conditions. The EOC distribution of crack indications at the TSP elevations will be confirmed to result in acceptable primary-to-secondary leakage during all plant conditions and that radiological consequences are not adversely impacted. In addressing the combined effects of loss-of-coolant accident (LOCA), plus safe shutdown earthquake (SSE) on the S/G component (as required by GDC 2), it has been determined that tube collapse may occur in the S/Gs at some plants. This is the case as the TSP may become deformed as a result of lateralloads at the wedge supports at the periphery of the plate because of tha combined effects of the LOCA rarefaction wave and SSE loadings. Then, the resulting pressure differential on the deformed tubes may cause some of the tubes to collapse. There are two issues associated with S/G tube collapse. First, the collapse of S/G tubing reduces the RCS flow area through the tubes. The reduction in flow area increases the resistance to flow of steam from the core during a LOCA, which in turn, may potentially increase peak clad temperature (PCT). Second, there is a potential that partial through-wall cracks in tubes could progress to through-wall cracks during tube deformation or collapse. Consequently, since the leak-before-break methodology is applicable to the SON reactor coolant loop piping, the probability of breaks in the primary loop piping is sufficiently low that they need not be considered in the structural design of the plant. The limiting LOCA event becomes either the accumulator line break or the pressurizer surge line break. LOCA loads for the primary pipe breaks were used to bound the conditions at SON for smaller breaks. The results of the analysis using the larger break inputs show that the LOCA loads were found to be of insufficient magnitude to result in S/G tube collapse or significant deformation. The LOCA, plus SSE tube collapse evaluation performed for another plant with Series 51 S/Gs using bounding input conditions (large-break loadings), is considered applicable to SON.

6- l l Addressing RG 1.83 considerations, implementation of the bobbin probe voltage based interim tube plugging criteria of 2.0 volt is supplemented by: (1) enhanced eddy current inspection guidelines to provid.9 consistency in voltage normalization, (2) a 100 percent eddy current inspection sample size at the TSP elevations, and  ! (3) RPC inspection requirements for the larger indications left in service to characterize the principal degradation as ODSCC. As noted previously, implementation of the TSP elevation plugging criteria will decrease the number of tubes that must be repaired. The installation of S/G tube plugs reduces the RCS flow margin. Thus, implementation of the alternate plugging criteria will maintain the margin of flow that would otherwise be reduced in the event of increased tube plugging. Based on the above, it is concluded that the proposed license amendment request does not result in a significant reduction in margin of safety. e 9 P i

ej w a y ug- - __.. 4 5 J ..a , a..E s .a ENCLOSURE 4 TVA COMMITMENTS i i { i

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6 s b I I I l l i i )

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COMMITMENTS

1. Eddy current analysts shall be trained specifically to voltage sizing in accordance with the WCAP-13990 Appendix A analysis guidelines, and at least lead analysts shall be qualified to the industry standard Qualified Data Analysis program of the Electric Power Research Institute (EPRI) Pressurized Water Reactor S/G Examination Guidelines. Training shall be completed prior to S/G inspection during the Unit 2 Cycle 6 refueling outage.

2. Use of ASME standards cross-calibrated to the reference laboratory standard and use of a probe wear standard requiring probe replacement at b voltage change of 15 percent from that found for the new probe shall be implemented per WCAP-13990 Appendix A. Implementation shall be completed prior to restart from the Unit 2 Cycle 6 refueling outage.

3. RPC inspection of all bobbin indications greater than the 1.5 volts shall be inspected to confirm axial ODSCC as the dominant mechanism for indications at the TSPs. Inspection, if needed, shall be completed prior to restart from the Unit 2 Cycle 6 refueling outage.

i

4. RPC sample inspection of at least 100 TSP intersections witn dents or artifact / residual signals that could potentially mask a 2.0-volt bobbin coil signal.

The RPC sample shall emphasize dented TSP intersections but include artifact signals that the analysts judge could mask a repairable indication. Any RPC detected flaw indication in this sample will be plugged or repaired. Repair or plugging shall be completed, as applicable, prior to restart from the Unit 2 Cycle f; refueling outage.

5. The projected end of cycle SLB tube burst probability shall be calculated and compared with the value of 2.5 x 102 found acceptable in NUREG-0844.

Calculations and comparisons shall be completed prior to restart from the Unit 2 Cycle 6 refueling outage.

6. NRC will be informed before plant restart from the Unit 2 Cycle 6 refueling outage of any unexpected inspection findings relative to the assumed characteristics of the flaws at the TSP intersections. This includes any detectable circumferential indications or detected ODSCC indications extending outside the thickness of the TSP.

ENCLOSURE 5 SEQUOYAH UNIT 2 WESTINGHOUSE COMMERCIAL ATOMIC POWER 13990 STEAM GENERATOR TUBE PLUGGING CRITERIA FOR INDICATIONS - AT TUBE SUPPORT PLATES (PROPRIETARY VERSION) 4 6

I ENCLOSURE 7 WESTINGHOUSE ELECTRIC CORPORATION AUTHORIZATION LETTER, CAW-94-641; ACCOMPANYING AFFIDAVIT; PROPRIETARY INFORMATION NOTICE; AND COPYRIGHT NOTICE F}}