ML20216D529

Requests That Encl Copy of Draft GL-97-XX, SG Tube Integrity & DG-1074, SG Tube Integrity Be Placed in PDR

ML20216D529
Person / Time
Issue date:	09/05/1997
From:	Tim Reed NRC (Affiliation Not Assigned)
To:	NRC OFFICE OF INFORMATION RESOURCES MANAGEMENT (IRM)
References
RTR-REGGD-XX.XXX, TASK-*****, TASK-RE NUDOCS 9709090348
Download: ML20216D529 (93)

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NUCLEAR REGULATORY COMMISSION

%, *****,~g WASHINGTON, D.c. 30ptW1001 September 5,1997 MEMORANDUM TO: Document Control sk FROM:

Timothy A. Reed Materials and Chemical Engineering Branch Division of Engineering

SUBJECT:

DRAFT GL 97-xx

• STEAM GENERATOR TUBE INTEGRITY " AND SUPPORTING DRAFT REGULATORY GUIDE DG 1074 Attached is a copy of draft GL 97 xx " Steam Generator Tube integnty" and DG-1074

• Steam l

Generator Tube Integrity" which are being made publicly available to facilitate interaction with industry representatives. Please place the report in the public document room.

Attachment:

As Stated 1

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Draft (9/5/97)

UNITED STATES NUCLEAR REGULATORY COMMISSION OFFICE OF NUCLEAR REACTOR REGULATION WASHINGTON D.C. 20555-0001

[Date]

NRC GENERIC LETTER 97 XX:

STEAM GENERATOR TUBE INTEGRITY Addresten All holders of operating licenses and construction permits for pressurized water reactors (PWRs).

Puroose The U.S. Nuclear Regulatory Commission (NRC) is issuing this generic letter to (1) inform l

addressees that actions beyond current technical specification requirements may be necessary to ensure steam generator (SG) tube integrity, (2) to request that addressees implement the I

actions described herein to ensure that SG tube integrity is monitored and maintained consistent with regulatory requirements and the plant licensing bases, and (3) to require that addressees submit to the NRC a written response to this generic letter regarding implementation of the requested actions. In addition, this letter is intended to provide guidance I

to licensees who may wish to amend their technical specifications to permit the use of rsew alternate repair criteria (ARC) as part of " defect specific management (DSM)" methodologies for monitoring and maintaining SG tube integrity.

Discussion Steam generator tubes function as an integral part of the reactor coolant pressure boundary (RCPB) and, in addition, serve to isolate radiological fission products in the primary coolant from the secondary coolant and the environment. For purposes of this generic letter, tube integrity means that the tubes are capable of performing these functions such that the tubes are in accordance with the plant licensing basis, including applicable regulatory requirements. Title 10 of the Code of Federal Regulations (10 CFR) establishes the fundamental regulatry requirements with respect to the integrity of the SG tubing. Specifically, the General Design Criteria (GDC) guidance described in Appendix A to 10 CFR Part 50 state that the RCPB shall have an extremely low probability of abnormalleakage...and gross rupture"(GDC 14), "shall be designed with sufficient margin" (GDCs 15 and 31), shall be of "the highest quality standards possible"(GDC 30), and shall be designed to permit " periodic inspection and testing...to assess... structural and leak tight integrity"(GDC 32). To this end,10 CFR 50.55a specifies that components which are part of the RCPB must meet the requirements for Class 1 components in Section 111 of the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code. As part of the plant licensing basis, applicants for PWR licenses are required to analyze the consequences of postulated design basis accidents involving degradation of the SG

2 tubes. Typical accidents analyzed include the steam generator tube rupture (SGTR), the locked rotor, control rod ejection, and a main steam line break (MSLB). These analyses consider the primary to hecondary leakage through the tubing which may occur during these events and must show that the offsite radiological doses do not exceed 10 CFR Part 100 guidelines or a small fraction thereof and GDC 19 of Appendix A to 10 CFR 50.

As also part of the plant licensing basis, licensees are required to monitor and maintain the condition of the SG tubing once the plant is in operation with the objective of ensuring the l

continued integrity of the SG tubing. Specifically, licensees are required by the plant technical specifications to perform periodic inservice inspections and to repair (e.g., sleeving) or remove from service (by installing plugs in the tube ends) all tubes found to contain flaws exceeding the plugging limit (i.e., tube repair criteria), in addition, operationalleakage limits are included in the technical specifications so that if significant leakage develops, the plant will be shutdown before rupture occurs. Licensees are also required by the technical specifications to have a program for controlling secondary water chemistry with the objective of minimizing corrosion-induced degradation of the SG tubing.

The plugging limits in the technical specifications were developed with the intent of ensuring that degraded tubes (1) maintain factors of safety against gross rupture consistent with the plant design basis (Le., consistent with the stress limits of the ASME Code, Section lil) and (2) maintain leakage integrity consistent with the plant licensing basis while, at the same time, allowing for potential flaw size measurement error and flaw growth between insenrice inspections. However, the inservice inspection requirements, repair requirements, and operationalleakage limits in the technical specifications are prescriptive and strict adherence to these requirements do not alone ensure that these objectives are being met. This problem is aggravated by the fact that these prescriptive requirements are out of date, reflecting neither the current dominant forms of degradation or current inservice inspection technology. These shortcomings have led to numerous occurrences in the U.S. where individual tubes were found to be vulnerable to rupture under postulated accident conditions such as MSLB and includes seven occurrences where tubes degraded to the point where they ruptured under normal operating conditions. A tube rupture under postulated MSLB conditions is outside the plant design basis and is not analyzed as part of the plant licensing basis.

Despite the shortcomings of current technical specification requirements, licensees are required by 10 CFR 50, Appendix B, to take action as necessary to ensure that SG tube integrity is being maintained. Licensee's have frequently found it necessary to implement measures beyond minimum Code and technical specification requirements to ensure adequate tube integrity when significant degradation problems are encountered. These measures are typically ad hoc, and are frequently accompanied by interaction with the staff in an oversight capacity to ensure that adequate tube integrity is being maintained. In addition, the staff has issued information notices, bulletins, and generic letters relating to problems occurring in the field.

Paradoxically, these requirements can result in some instances of unnecessary plugging or repair of degraded tubes since the current standard technical specification repair criteria (i.e.,

plugging limit),40% of the initial tube wall thickness, is conservative for many of the kinds of flaws currently being observed. Industry development and NRC staff review and approval of more appropriate, attemative repair criteria for specific degradation mechanisms has proven a

3 difficult and time consuming since such changes frequently involve issues not addressed in current regulatory guidance. Examples of such issues include repair criteria which are length-based or voltage based rather than depth based; potential accident induced leakage implications when through wall or near through wall cracks are accepted for continued service; treatment of uncertainties associated with structural and leakage models, growth rates, and NDE performance; the use of probabilistic assessments of tube integrity in lieu of traditional determ5istic assessments, and potential risk implications associated with alterative repair criteria.

The staff has concluded that actions beyond existing technical specification requirements are needed to ensure tube integrity is monitored and maintained consistant with the current licensing basis. The staff believes that the most appropriate remedy to this situation is that plant technical specifications be upgraded as necessary to ensure tube integrity. Accordingly, this generic letter requests that all addressees upgrade their technical specifications as necessary to meet this objective. Model technical tpecifications to this effect are provided as Attachment A to this generic letter Regulatory Guide DG-1074, ' Steam Generator Tube integrity," provides additional guidance for implementing acceptable technical specification proposals.

The model technical specifications in Attachment A involve an approach which is conceptually similar to the approach currently being implemented on an ad-hoc basis, in whole or in part, as necessary to ensure tube integrity. It is performance-based in that it is focused on ensuring that the tubing satisfies performance criteria that are commensurate with tube integrity consistent with the current licensing basis. This approach can be readily adapted to new or unexpected degradation mechanisms and NDE technology changes. This approach includes programmatic elements to ensure that tubes are being adequately monitored and maintained relative to the performance enteria. In addition, this approach includes certain prescriptive elements consistent with the current licensing basis (i.e., performance criteria, tube repair criteria) to maintain the current level of risk and changes to these elements will need to include appropriate consideration of risk impacts.

The key programmatic elements of this approach are summarized and discussed below:

oerformance criteria which are commensurate with adequate tube integrity. These e

criteria are the benchmark against which the effectiveness of licensee actions for ensuring tube integrity are evaluated. Licensees must adjust their programs as necessary to ensure that these criteria are met. The performance criteria in Attachment A are consistent with the current ddgn and licensing basis for PWRs. These criteria include (1) structural integrity criteria for maintaining deterministic safety factors consistent with the current licensing basis, (2) operational leakage integrity criteria consistent with LCO leakage limit requirements, and (3) accident induce leakage integrity criteria consistent with the current licensing basis, inservice insoection - of the tubing relative to the tube repair criteria. NDE techniques and e

personnel must undergo a performance-based qualification to ensure that the tubing can be reliably inspected relative to the tube repair criteria and that the condition of the tubing can be reliably monitored relative to the performance criteria. The frequency and scope of I

l

4 inspection must be such as to ensure that the performance criteria will be met, monitorina - operational primary-to-secondary leakage and implementing leakage limits e

such that the performance criteria are not exceeded. Experience has demonstiated effective operationalleakage monitoring as an important complement to inservice inspection for ensuring tube integrity. This generic letter requests that licensees submit a proposed change to the technical specification LCO limits on operational leakage if and as necessary to make these limits consistent with the performance criteria.

monitQting - the "as-found" condition of the tubing during each inservice inspection with e

respect to the performance criteria (i.e., condition monitoring). This is a " backward looking" assessment to confirm that the ove,all program has been successful in ensuring that the performance criteria are in fact being raet. Failure to demonstrate that the performance goals have been met may be indicative of deficiencies in licensee programs.

Such failures must be promptly reported to the NRC. Corrective actions, as necessary, must be implemented prior to restart.

monitorino - the projected condition of the tubing calcul#ed to exist prior to the next e

scheduled inservice inspection with respect to the applicable performance criteria (i.e.,

operational assessment). This is a " forward looking" ascessment to ensure that the

, performance criteria will continue to be met.

tube reoair criteria consistent with the current technical specifications. These criteria are e

consistent with the design and licensing basis and with maintaining an acceptably low risk of tube failure.

oreventive measures - to minimize the potential for tube degradation and to mitigate active e

mechanisms as practical.

Ado:essees may, at their option, submit as part of the proposed changes to the technical specifications attemative, probabilistically-based structural performance criteria and new attemative repair criteria (ARN which may be implemented for specific defect mechanisms as part of a steam generator defeespecific management (SGDSM) program described or referenced in the technical specifications. These attematives would provide enhanced flexibility to addressees for managing SG tube degradation in a cost effective manner consistent with ensuring the tube integrity is monitored and maintained. SGDSM constitutes an integrated approach, for a given degradation mechanism, for ensuring that the performance criteria are being met and consists of specific methodologies for conducting inservice inspections, condition monitoring, operational assessment, and for determining the appropriate repair criteria to be implemented during each inservice inspection. Proposals for probabilistic structural performance and/or ARCS as part of an SGDSM program should be developed in accordance with the guidelines in DG-1074. In addition, such proposals are subject to demonstrating that an acceptable level of risk will continue to be maintained. Guidance to conduct a risk assessment to demonstrate that proposed attemative approaches will maintain acceptable levels of risk is provided in DG-1073 An Approach to Plant-Specific, Risk-Informed Decision Making: Induced Steam Generator Tube Rugture." DG 1073 is currently under development, but will offer guidance consistent with DG-1061, "An Approach for Using Probabilistic Risk

5 l

Assessment in Risk-informed Decisions on Plant Specific Changes to the Cunent Licensing Basis," which is currently available for public comment. This risk atsestoc would need to be submitted to the NRC for review as part of the proposed license amendh cm Finally, the performance criteria for accident induced leakage integrity given in the Attachment A model technical specifications, paragraph 5.5.9.b.3, is based on the leakage value assumed for postulated accidents (other than a steam generator tube rupture) in the current licensing basis. Any proposal to revise the current licensing basis to accommodate a larger leak rate during design basis accidents must be reviewed and approved by the NRC. Such a proposal should include a radiological assessment in accordance with Regulatory Guide DG-1074, Section C.9, to demonstrate that the consequen.:es of design basis accidents meet the 10 CFR 100 guideline limits for offsite doses, or some fraction thereof as appropriate to the accident, and GDC 19 criteria for control room operator doses. In addition, such a proposalis subject to demonstrating that it does not introduce and unacceptable impact on the risk of tube failure.

This must be demonstrated for each defect mechanism for which the revised performance criteria for accident-induced leakage integrity will be applied. Guidance for the evaluation of the risk impact can be found in DG 1061.

With respect to the radiological assessment, Regulatory Guide DG-1074 provides guidance on two methodologies, either of which may be used at the licensee's option. The first methodology involves the approach presented in the Standard Review Plan, Section 15.1.5, Steam System Piping Failures inside and Outside of Containment (PWR), 15.3.3-15.3.4, Reactor Coolant Pump Rotor Seizure and Reactor Coolant Pump Shaft Break,15.4.8, Spectrum on Rod Ejection Accidents (PWR), and Section 15.6.3, Radiological consequences of Steam Generator Tube Failure (PWR), for calculating doses resulting from an MSLB, locked rotor od ejection, and SGTR, respectively. This first method can be employed to support a specific value for allowable accident-induced leakage (i.e., the performance criterion). The second methodology, termed " flex", establishes the allowable accident-induced leakage as a function of the maximum instantaneous RCS activity level of dose equivalent l and the 48 hour5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> value of dose equivalent '2'l. These functions are based upon the limiting accident scenario. These functions provide licensees the flexibility to adjust the accident-induced leakage criterion up or down, as needed based on the results of the operational assessment by restricting tne maximum instantaneous RCS activity level of dose equivalent '2'l and the 48 hour5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> value of dose equivalent l to predetermined values. Implementation of the flex methodology will require a change to the technical specifications. Model technical specifications to this effect are provided in Attachment B.

Reauested Actions (1)

All addressees are requested to submit prgnsed changes to the technical specifications such as to ensure tube integrity is maintained consistent with the design and current licensing basis of the plant.

(2)

As a voluntary action, addressees may submit additional proposed changes to the technical specifications to permit the use of (1) alternative, probabilistically-based structural performance criteria and/or alternative repair criteria for application to specific degradation mechanisms as part of an SGDSM program to be documented or

6 referenced in the technical specifications and (2) the flex methodology for performing radiological assessments. As a voluntary action, addressees may also propose revisions to the licensing basis accident analyses to consider revised leak rates assumed to occur during DBAs. - Approval of these additional changes in the technical specifications and/or licensing basis evaluations is contingent upon on NRC acceptance of a risk evaluation demonstrating that an acceptable level of risk will be maintained, l

consistent with DG-1061.

Reauested Information (1)

All addressees are requested to submit:

proposed changes to the technical specifications in accordance with Requested o

Actions (1), and the safety basis by which the addressee finds these proposed changes to be sufficient to ensure tube integrity consistent with the design and current licensing basis of the plant, if these changes differ from the model technical specifications in Attachment A to this generic letter.

the safety basis by which the addressee finds the existing or proposed technical specification LCO limit regarding primary-to-secondary leakage for any one steam generator to be sufficient to ensure the integrity of leaking tubes consistent with the design and current licensing basis of the plant, if not satisfying the guidelines in Regulatory Guide DG-1074, Section C.8.2, conceming the establishment of this limit.

(2)

Addressees electing to implement Requested Actions (2) are requested to submit:

proposed changes to the tecnnical specifications and/or licensing basis accident analyses in accordance with Requested Actions (2),

technicaljustification for differences between the proposed changes to the e

technical specifications and the model technical specifications attached to this generic letter, and documentation of a risk assessment [ documentation guidance is included in DG-e 1061).

(?)

Addressees are requested to identify and to provide technical justification for any differences between implementing procedures to be developed for the proposed technical specifications and Regulatory Guide DG-1074.

Reauired Resoonse Pursuant to Section 182a of the Atomic Energy Act of 1954, as amended, and 10 CFR 50.54(f),

addressees shall submit, unde oath or affirmation, a written response to this generic letter at

_O

7

'least 6 months prior to the next scheduled steam generator inspection occurring after one year.

following the date of this generic letter._ The written response shall include the following:

(1)

Requested Information (1) and (3), if the addressee has implemented Requested Actions (1).

(2).

. If the addressee has not completed or chooses not to implement Requested Actions (1),-

submit a description of any proposed attemative course of action for monitoring and -

maintaining SG tube integrity, the schedule for impicmentation, and the safety basis for i

the proposed attemative course of action as being sufficient to ensure that tube integrity is being adequately monitored and maintained.

The NRC will review the responses to this generic letter, and if concerns are identified during the review, those licensees will be notified of the NRC staff concerns.

Address the required written reports to the U.S. Nuclear Regulatory Commission, ATTN:

Document Control Desk, Washington D.C. 20555-0001, under oath or affirmation under the provisions of Section 182a, Atomic Energy Act of 1954, as amended, and 10 CFR 50.54(f).

. Related Generic Communications-Fed'bral Reaister Notification Pacerwork Reduction Act Statement l

Attachment A page 1 of 11 Model Administrative Control Technical Specification for Maintaining Steam Generator Tube Integrity The following model adninistrative control technical specification section is intended to replace section 5.5.9 of the WOG STS. Revision 1. 04/07/95 in its entirety.

Programs and Manuals 1

l 5.5 l

5.0 ADMINISTRATIVE CONTROLS l

5.5 Programs and Manuals 5.5.9 Steam Generator Tube Intearity Proaram This program provides for demonstrating that each steam generator is OPERABLE through monitoring and maintaining the steam gererator tubes consistent with tube integrity performance criteria.

This program shall include the following elements:

t a.

Steam Generator Preservice and Inservice Inspections 1.

Preservice inspection shall be conducted on 100% of the tubing over their full length using a general purpose eddy current probe (e.g., bobbin probe). This inspection shall be performed -after the field hydrostatic test, but prior to-initial power operation.

2.

Inservice inspections shall be scheduled as follows:

Inservice inspection of each steam generator shall be e

performed at the first refueling outage (a duration not less than 6 EFPM and not more than 24 EFPM).

Subsequent inservice inspections of each steam generator shall be performed according to a schedule such that operational assessment'in accordance with 5.5.9.c demonstrates that the performance criteria in 5.5.9.b will be met immediately prior to each scheduled inservice inspection.

No steam generator shall operate more than two-fuel cycles between inservice inspections.

3.

Unscheduled-inservice inspections shall be performed during plant shutdown subsequent to any of the following

=

--(Continued)-

Attachment A Page 2 of 11 Programs and Manuals 5.5 5.5 Programs and Manuals i

5,9.9 Steam Generator Tube Intearity Proaram (continued) conditions:

~

primary to-secondary leakage leading to plant shutdown e

for repair of the leaking tube (s); applicable only to leaks involving tube, plug, or sleeve flaws or sleeve-to tube welds seismic occurrence greater than the Operating Basis e

l Earthquake l

I loss-of-coolant accident requiring actuation of the e

engineered safeguards e

main steam line or feedwater line break 4.

The initial tube sample for inservice inspection, scheduled and unscheduled, shall include:

a minimum 20% random sample of the total number of e

steam generator tubes which remain in service (i.e.,

tubes which have not been plugged).

This sample shall be divided equally among all steam generators being inspected during a given plant outage.

Each tube in the sample shall be inspected over its full length, including any portions of the tube which have been repaired in accordance with 5.5.9.f.

additional tubes (in the steam generators being e

inspectep) found in previous inspections to be degraded and which were left in service (i.e., not plugged) without repair.

The number and identity of such tubes should be 100% or as necessary to demonstrate by operational assessment in accordance with 5.5.9.c that the performance criteria in 5.5.9.b will continue to be met prior to the next scheduled inspection of the steam generator.

Inspection of these tubes may be limited to the aortion of the tube length containing the previously o] served degradation Words in bold face type are defined in 5.5.9.i.

(Continued)

-__N

i Attachment A Page 3 of 11 Programs and Manuals 5.5 5.5 Programs and Manuals 5.9.9 Steam Generator Tube Inteoritv Proaram (continued) provided the subject degradation mechanism can be shown to be limited to that portion of the tubes, alternatively, for unscheduled inspections caused by e

primary-to-secondary leakage involving plugs.

inspections may be limited to plugs as appropriate to diagnose the cause of the leak.

Corrective actions shall be taken as necessary to prevent recurrence of the problem.

For unscheduled inspections caused by primary-to-secondary leakage through the tubing and not involving plugs, the initial inspection sample may be 20% of the number of tubes in the affected steam generator or a 20% sample within a defined region of the affected steam generator if the degradation i

mechanism associated with the leak has been j

established to be confined to within this region.

r I

Indications found during the initial inspection sample shall be evaluated to determine the active degradation mechanisms present in the steam generators.

5.

For each active degradation mechanism identified during the initial sample inspection, an expanded inspection sample shall be performed.

(For unscheduled inspections caused by primary-to-secondary leakage, an expanded inspection samale is only performed if non-leaking indications involving tie subject degradation mechanism are found during the initial sample.) The expanded sample shall apply to the entire tube bundle of the affected steam generator unless the degradation mechanism can be demonstrated to be confined to a defined region in which case the expanded inspections for the subject degradation mechanism may be lirrited to this defined region.

The size of the expanded sample (within the tube bundle or defined region, whichever is applicable) shall be 100% or, alternatively, as necessary to demonstrate by operational assessment in accordance with 5.5.9.c that the tube integrity performance criteria in 5.5.b will continue to be met prior to the next scheduled inspection of that steam generator. The inspection shall also be expanded into any (Continued)

Attachment A Page 4 of 11 Programs and Manuals 5.5 5.5 Programs and Manuals 5.9.9 Steam Generator Tube Intearity Proaram (continued) uninspected steam generators, starting with a initial sample inspection in accordance with 5.5.9.a.4.

However, for each active degradation mechanism, this initial sample may be initially limited to defined regions which have been identified for the subject degradation mechanism.

6.

Inservice ins)ections shall utilize non-destructive examination (4DE) systems (NDE techniques, procedures, and personnel) which. as a minimum, have been qualified for detection of flaws associated with each potential degradation mechanism affecting the tubing.

b.

Tube Integrity Performance Criteria Condition monitoring in accordance with 5.5.9.c and operational assessment in accordance with 5.5.9.d shall be performed relative e

to the following criteria:

I 1.

Structural Criteria: Satisfaction of this criteria means that all tubes tave been determined to retain a margin of 3.0 against grors failure or burst under normal plant operating conditions, including startup, operation in the power range, hot standby, and cooldown, and all anticipated transients that are included in the plant design specification.

In addition, all tubes have been determined to retain a margin of safety against gross failure or burst consistant with the margin of safety determined by the stress limits in NB-3225 of Section III of the ASME Code under postulated accidents concurrent with a safe shutdown earthquake.

2.

Operational leakage criterion: Satisfaction of this criterion means that operational primary-to-secondary leakage rate in each steam ger.erator does not exceed [the primary-to-secondary leakage LC0 limit for any one steam generator].

3.

Accident induced leakage criterion: Satisfaction of this criterion means that the calculated. )otential primary-to-secondary leakage rate associated wit 1 the most limiting postulated accident does not exceed [1 gallon per minute or.

(Continued)

Attachment A7 Page 5 of 11

' Programs and Manuals

- 5.5

-5.5~ Programs and Manuals.

5.9.9 Steam Generator Tube Intearity Procram (continued) l

alternatively, the value assumed in the current licensing basis).

c.

Condition Monitoring The condition of tubing shall be' monitored during each inservice inspection, whether scheduled or unscheduled. to confirm that the tubes meet the tube integrity performance criteria in 5.5.9.b.

The condition of the tubing shall be monitored against the structural aerformance criteria of 5.5.9.b.1 and the accident-induced leacage performance criteria in 5.5.9.b,3 either by analysis, based on the results of inservice NDE inspection, or by--

alternative means (e.g..-in-situ pressure testing) for each degradation mechanism.

Tube structural and accident-induced leakage integrity may be demonstrated by analysis for a given degradation mechanism provided the inservice inspection results e

are from NDE techniques and Jersonnel which are validated for sizing. These assessments s1all account for all significant uncertainties such as to provide a conservative assessment of the condition of the tubing relative to the performance criteria.

Operational leakage integrity of the tubing shall be monitored by assessing the maximum primary-to-secondary leak -rate during the previous operating interval against the operational-leakage-performance-criterion of 5.5.9 b 2.

Should these assessments. reveal that any of the performance criteria in 5.5.9.b are not met, this should be reported promatly' i

in accordance with 5.5.9.h (2). and corrective actions shall se-implemented prior to plant restart..

For an unscheduled inspection due to primary-to-secondary.

leakage, the condition monitoring assessment need only address the degradation mechanism which caused the leak provided the -

interval between scheduled-inspections is not lengthened (However, it will be necessary to include the estimate-of the

-contribution of accident induced leakage from the other active--

degradation mechanisms, as determined from the most recent-operational assessment for these mechanisms. to demonstrate that performance criteria.for accident induced leak rate is met.)

(Continued)

~

Attachment A Page 6 of 11 Programs and Manuals 5.5 5.5 Programs and Manuals i

j 5.9.9 Steam Generator Tube Intearity Proaram (continued) l d.

Operational Assessment An operational assessment shall be performed to provide reasonable assurance that the performance criteria for structural integrity in 5.5.9.b.1 and for accident-induced leakage integrity in 5.5.9.b.3 will continue to be met until the next scheduled steam generator inservice inspection.

(The operational assessment need not be performed relative to the performance criteria in 5.5.9.b.2 for operational leakage integrity.) The length of the operating cycle prior to the next scheduled inspection shall be adjusted as necessary to meet this objective.

Additional corrective actions shall also be performed as necessary to meet this objective. A preliminary operational assessment and im)lementation of corrective actions, as necessary, shall se completed prior to plant restart demonstrating that the performance goals will continue to be met for at least 90 days following plant restart. The final operational assessment and additional corrective actions, as necessary, shall be completed within 90 days of plant restart demonstrating that the performance criteria will continue to be met prior to the rext schedulc; inspection.

Operational assessments should account for all significant uncertainties such as to provide a conservative assessment of the condition of the tubing 3rojected to exist prior to the next scheduled inspection wit 1 respect to the performance criteria.

e.

Tube repair criteria All tubes found to be defective during preservice or inservice inspection shall be removed from service by plugging or shall be re) aired prior to plant startup from the inspection outage.

Tu)es are defective when they contain indications which fail to meet the applicable repair criteria as follows:

1.

Generally applicable repair criterion: flaw indications for which the maximum measured flaw depth equals or exceeds the 40% of the initial tube wall thickness. Measured flaw depths shall be as determined by NDE techniques and personnel which are validated for sizing.

In cases of flaw mechanisms for which NDE techniques and personnel are not (Continued)

Attachment A Page 7 of llo Programs and Manuals 5.5

'5.5 Programs and Manuals

(

5.9.9 Steam Generator Tube Intearity Proaram (continued) validated for sizing, all detected flaw indit.ations associated with such mechanisms shall be assumed to exceed the 40% criterion.

2.

- Alternative repair criteria (flaw specific): [ Alternative, flaw specific criteria approved by NRC for inclusion in the technical specifications are listed here.]

f.

Tube repair methods Repairs (e.g.. sleeving) of defective tubes, using any of the repair methods listed below, may be implemented as an alternative to removing these tube from service by plugging.

[Repafr methods approved by the NRC are listed here.]

1 a

g.

Acceptance Criteria The steam generators shall be determined OPERABLE for a. period not exceeding 90. days following plant restart from a steam generator inspection outage after:

1.

all tubes with. indications exceeding the applicable tube repair criteria have been removed from service'by plugging or repaired in accordance with 5.5.9.g. and 2.

a preliminary operational assessment in accordance with 5.5.9 d and accompanying corrective actions have been completed as necessary to demonstrate that the tube integrit period. y performance criteria will be met during the 90 day.

The OPERABLE status period for steam generators may be extended to not exceeding the next scheduled steam generator inspection.

outage 'after completion of the final operational assessment in accordance with 5.5.9.d and associated corrective actions as necessary to demonstrate that' the tube integrity performance criteria-will be met-prior to the next scheduled inspection, i

h.

Reporting requirements (Continued)

Attachment A Page 8 of 11 Programs and Manuals 5.5 5.5 Programs and Manuals 5.9.9 Steam Generator Tube Intearity Proaram (continued)

(1) Within 15 days following the completion of each inservice inspection of the steam generator tubes, the number of tubes plugged in each steam generator shall be reported to the Commiss1on.

(2) The complete results of the steam generator tube inservice inspection and condition monitoring assessment shall be

}

submitted within 12 months following completion of the inservice inspection. This report shall include:

(a) the number and extent (e.g., full length, hot leg only) of tubes subjected to inservice inspection and to any supplemental testing (e.g., in-situ pressure testing) as part of the condition monitoring assessment, t

(b) the location and measured size of each indication found by inservice inspection and the type of NDE test prob used (e.g., eddy current bobbin coil, eddy current rotating pancake coil).

Measured size shall be in terms of parameters (e.g., flaw depth, flaw length, and/or flaw voltage response) which can be directly compared to the applicable plugging limit for subject degradation mechanism. The orientation of the flaw (e.g.

axial, circumferential) shall be provided in cases of linear type indications such as due to cracks.

(c) the results of any supplemental testing beyond inservice inspection performed as part of the condition monitoring assessment (e.g., in-situ pressure testing).

(d) identification of tubes plugged.

(3) Failure of the condition monitoring assessment to confirm that the tube integrity performance criteria have been met should be reported, in accordance with 10 CFR 50.72, to the i

NRC within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

A written followup report shall be provided prior to plant restart with a description of investigations conducted to determine the cause of this (Continued)

Attachment A Page 9 of 11 Programs and Manuals 5.5 5.5 Programs and Manuals 5.9.9 Steam Generator Tube Intearity Proaram (continued) occurrence and corrective actions taken to prevent recurrence, i.

Definitions active degradation mechanisms means that new indications associated these mechanisms have been identified during inservice ins)ection or that previously identified indications associated wit 1 these mechanisms have exhibited growth since the previous inspection of the subject tubes, defined region means a three-dimensional region which can be demonstrated to bound the region where the subject degradation mechanism is active.

Technical justification to support identification of a critical area should be maintained as part of the inspection record, degraded tube means a tube containing an indication measured to be less the ap)licable plugging limit by an NDE technique and personnel whic1 are validated for sizing for the subject degradation mechanism, indication means the NDE signal response to a tube flaw. An indication may or may not be measurable relative to the applicable plugging limit.

potential degradation mechanisms are degradation mechanisms which may potentially affect the steam generator tubes at a given plant during the steam generator lifetime based on an consideration of plant and steam generator design. materials, operational practice (e.g.. temperature, secondary water chemistry control performance), accumulated service time and degradation experience at the plant and other plants of similar design.

materials, and operational practice, as appropriate.

qualified for detection means that NDE techniques and personnel have undergone performance demonstration for a given degradation mechanism and been shown capable of reliably detecting flaws associated with the degradation mechanism before these flaws are of sufficient size to cause the performance criteria to be exceeded.

(Continued)

Attachment A-Page 10 of 11 Programs and Manuals 5.5 5.5 Programs and Manuals 5.9.9 Steam Generator Tube Intearity Proaram (continued)

[ Note: Guidance in DG-1074 states that an acceptable approach for being qualified for detection is to satisfy the EPRI guidelines for NDE qualification.]

structural limit means the calculated maximum allowable flaw size developed consistent with the safety factor performance criteria in C.2.1.1.

l validated for sizing means that NDE techniques and personnel have undergone performance demonstration for a given degradation mechanism as necessary to quantify the error / variability of flaw size measurements (e.g., measured flaw depth, flaw length, and/or flaw voltage response) made under field conditions.

The data set l

for performance demonstration may consist of actual service degraded tube specimens and/or specimens containing fabricated flaws provided it is established in written documentation to be e

maintained as part of the validation record that signal responses are consistent with those in the field in terms of voltage amplitude and signal-to-noise for the same flaw geometry. The data set shall span the range of flaw sizes from les-than the applicable plugging limit in 5.5.9.e to a size where the structural performance criteria in 5.5.9.b.1 would not be met.

Where the applicable plugging limit is expressed in terms of the physical dimensions of the flaw (e.g., depth. length, crossectional. area). NDE technique and personnel performance shall be evaluated against that actual flaw geometry.

l The following model adninistrative control technical specification section is relative to the WOG STS. Revision 1. 04/07/95. Revisions to this section are shaded (example) and lined out (c=p?c).

5.5.10 Mevshtjis HeishrM9i th]ssMct]t65StEhm]Gehe[atbdTths3nte#[ity -

ThWpF69tainW6sidsOfoF3mihiliiizihp?ths"p6tentfaKforiTitdiiE Jhisl[ program 4hallfiscludeja;secon,g: active? degradati tube degradation andWorimitigatin isms r ^

daryjater; chemistry 1 program:and a (Continued)

Attachment A Page 11 of 11 Programs and Manuals 5.5 5.5 Programs and Manuals 5.9.9 Steam Generator Tube Intearity Prooram (continued) program;t6colntroEloosijarts75ndffor^eign(objectsasifollowsi al Secondary water chemistry program This program provides controls for monitoring secondary water chemistry to inhibit SG tube degradation and low pressure turbine disc stress corrosion cracking. The program shall include:

13-Identification of a sampling schedule for the critical variables and control points for these variables:

2A Identification of the procedures used to measure the values of the critical variables:

3.e-Identification of process sampling points. which shall l

include monitoring the discharge of the condensate pumps for j

evidence of condenser in leakage:

4M-Procedures for the recording and management of data:

Sie-Procedures defining corrective actions for all off control 7

point chemistry conditions: and 6l4-A procedure identifying the authority responsible for the interpretation of the data and the sequence and timing of administrative events. which is required to initiate corrective action.

b; LContr61 ofQooselpartfand foreignlobjects; Thi s Tpr6g' ram *irovi des (forfmorii t6 ring'chnd ?c6ntr' l ? ofil o~osh" parts o

and foreign o)jects in thepsteam generators tojinhibitdretting and wear { induced degradationlof theLtubing.

t (Continued)

.u._.

Attachment B Model Technical specifications for Reactor Coolant Values for Flex Program The following model is an example of an acceptable approach for the implementation of the flex program for the reactor coolant technical specifications.

Revision 1, 04 It is intended to replace Section 3.4.16 of the WOG STS, comparable sec/07/95 in its entirety.

It can also be utilized to replace tions

• • • • • • • • • • • • • • • • • • • • of the CE TS for reactor coolant.

I e

s

RCS Specific Activity.

B 3,4,16 8 3,4 REACTOR COOLANTcSYSTEM (RCS):

B 3.4.16' RCS Specific Activity BASES BACKGROUND The maximum dose to the whole body ~and the thyroid that an individual at the +4e ficlisionTeres? boundary receive for 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> dur'inf an~Tc&ident brlarMh(t.AB) Jean

~

dividual.

beat ~d?itiinyIpothEositd e

radio)icanireceivatduringithe%1;6Wps@itionlszone!bounda

[LPZ Fehtire! period ofosssagelof;~a active?cloudfreshiting?fros M estulatodifission p' roduct!reliaselii~~ spic ~ified'15~10 JR"100'~fRif~T).

bpecifieslthatsadequateTr]adianlonTprotectionVihil15t f ^~~S provideditoip?aikacceislandEsechpancytof1thefcontro kndeMaccident"dond i t ions twi thoutt personnil(rece1Vi ng~Lroom

~

radi ation fexpos uresd nyexcess Fof? 6 ;remiwhol ei body [orfiti bquival entitot anVlpart 94feto:bodidentho duratisn?b thi a'ccidentM(Refegnce?t)%The"11mits on TpeEific~ictiVi doseNguivalentb Irand g~rdsIWidi6istWitifihlE64jsEEtion~

hith?allowableipheary;d irithinfthe guidelineidosesFf68 thit^thi~dojii~are hel tof secssdarfleakag' elrateshenisFe "

GiriiGilicuidistiTeihiEKaiy sinW1vefprimarfitoMec6ndaEy ~

leakage.%The bf ~the 10 CFR; guideline'dosetlevels>atepe a small frastion 100~11siiti~duFisg~EET ::. tr:::i::t: ::d

id ;t:KlicksdTFot6Eoffitesm~ge'lnifatoFht (SGTR;?ohntf will?within! Parts 100 e11mitsiforj.ubiffuptsis

)

aicontro1 Fo ejecti oniaccidentio6a!aa inutsaml1 ine ibreakawi thia 6"~~~B a' c c i dent-i n i ti ated tspi ke pahd ithe f fu11 &l 02CFR fl00lgu'i'Bil lhiei forJa?mainistiamilinsbreakV(MSLB spi k(B Contro1 Fioomi spaira tor? dose)1withiaTpre4xis ting ~"~~

sFausttaseti4DCX19~

hideligsif_orja&gfMpptulatejdlaMMentsf~

The RCS specific activity LCO limits the allowable concentration EEthiff level of radionuclides in the reactor c ool anti b6thii niterms #6fia~niliEinTillsfrabliMiltistini6ui Esheisfid6gequivalentWUand.ithe 48thouravaluetofs s

) qui val en t b-ba shjfunct%nioLal~lowab1 Rphimarylto~dosi

^~

secondarylliikage. Thi'IC0~11mits iFe~iitatillsheil~to iiiiWisififthi~^6ffiite radioactivity dose consequences in the event of a :t::: ::: :t:r tu b 7: t:L: 'SGTR accident %i ltSLBWiT1oEksd!FotoE?ic6tdintFifro;dfeji$t16K)vibii'dntteF~

some : ether 1 accident 91nvolving idegradati oniefsthetS6 ftubeiB Jheqimitsiarelestablished;tasedupdthefaccident%cenaris F

hndithMdosejcrj teriontwhicMi simos111mitinglwithJrespicf (continued)

WOG STS B 3.4-93 Rev 1, 04/07/95

__.,....__..m.,

RCS Specific Activity B 3.4.16 BASES E "a115Eili1Ilhiiry7ti~sisindiFfTiikig lEGE-s h110wabl e ki nst antano6usi val ve t of r dosef oqui vsl enti liti be termi ned : ba sed 3pon t analyse s lofd SGTRalocked f ro rNr6d hject i oh tandlMSLB ; accident s ?inyol vi ngl a fpr@e-gxi st 11 e ?thsi48i hourjyal usieffdos foquival ent 41s-eterminedibased upon*antahalysis offSGTR$1FckedFofiFW63 jectio' ntand:MSLB?accidentslinvolsinglahiaccident-initiatid~

pikentAssociatediwithitheieianilyses faretas sumedWalues^ '

~

forinormalioperating?primarytods4condarylleakageJandlevou

[ndicetiprimatyltoisycondaIy leJkags -

~ ~ ~ ~ -

d The LCO contains specific activity limits for both L W 48 liudbalusiindit6e misiihilinitintibioss3alsisfoF" DOSE-EQUIVALENT"I-131~isdirbis~ specific ~a'ctivitf.^^ The allowable levels are intended to limit the 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> dose at the e44+

i i: = d:g*lYABKthsid6sdTatithili.pl?tissedTipshit h'i'duFat i oh~6f theiaccidentsand tholdosoitolthefdontroltroom'op'iidit:

Eid11 ~fFOtE5' 'T10W10fdd5 fJ^ iEliH eratot 4e e'

~

lim The

....,its i,n the,LCO,,ar.e e4+nd:rdi::d..,. i;;;d =_ __;;r-- ^ r t :

...._____..._.u......

2___

55555 ' 555:l:555I555.bEsfdN65itfii3Eti5i5iiatI65NNN inaxi'admih116~ GibliFEsrailfopepating primaryl leakage?anditheissents'inducediprimarfftoisecondaryM1eak asiatfuncti6n JhetlimitsEare[ofiRCSiittivitylleve12cf5 dose equivalenti 4?"

"dsterair.ed tbased i upoWe Val uat ionsief

^

consequsncestofgtransientsMny'olvingideiradedtstsam#^~hs "~

generators ?tubesMTyssi cals trins i ent si w t i ch?areT ava15ifid Sheludelthe MSLBetheslockedTrotorntheirodiejectioniandri SGTR.c:ForlalMSLBfaccidentiwithialpre-existing [d upon spikeha^

pet erminati onlis7sadeioffal16 sable 3 ankagelba se maintainingthetthyroid:doseilesssthani300trem$the wh61_e body dosellessithan125tressanditheicontrolbroomioperator~

khyrbid dose >1sssithas30iremTandEtheicontfo15coomloperatEF 6tholeibsdyidosoit'o 5srem8FoBa' MSLBiaccidentiwithiaf ~~

pccident-ihi. t1 atedf sp i ko gthelmaximufallowable ?p rimary if6 secondary 11eakapelissbased!upon?offsite3dosesib' tngY11mited e

to ;wel l !within? Partf100f and ! controliroom f operatora doses sto~

BDCe19 NEThei c6risequences rofia frod isjection ticcident rare ~

sls~silikttedItoiwe111within1Part?!00:forfoffsite

~

hensequencesM ForMSGTR iesent8thell imitsinareidiformGid based;up le a kage $;onitheTmaximsm?allowabl ef primsry;ti?sscondarf' ~~^~^

whichWill 4ma intai nithelthyroid idoseiofian

$ ndi vidual aatEthat EABiorAPZ tto11es sithan?30thslandittis whol e ibodfido s e? tsil e' sithanit ! 5 Eremiand thnntrol srooi s

bperator thyroidid6ieitssleis thstG30Tres?andrthe$c4ntrol.

e hoperatorjwh'ol ei bodddose ttell essilhan]MremRJhe'~

(continued)

WOG STS B 3.4-94 Rev 1, 04/07/95 l

RCS Specific Activity B 3.4.16 BASES 6ffitti36hiiissn~cis9fNi1EEE3iFF6tioWaiEi~distTiWETii l1sitedito3aisma11Afraction*of(Past!100iAThe 11mitsiintthi LC0!any f also^ beidetermined)tiased topontanHacc;ident!1nvol

~

degradation?of;theisteam generatoritubesisuch?thattprimavilng ry helsecondayjleakagelanylocgufdgthelgyg!Ltigf aman!1gnt.2 2

Th: -ir: :tri: :ninti=: -h:= d th; ;t=thi c"-it: d:n h n !- f:r : COT", :n te nt = n = :; ;= ;r ht:1) ::.11 frnti n :f th; 10 Of", 100 d n; ;id:5in li it:.

Inh

ni nti= : n t:n. tr = d = ;;; f ;it:

1i=bh O'

n;h;rh dh;

nt= f=t;n b : ;.rt:tru :=l=ti=,

1 APPLICABLE The LC0 limits-on the specific activity of the reactor SAFETY ANALYSES sedinda,ry(i E h EdiF *BWilsidubiti6n trithitheTa116 coolant FiesFv1ts 1 sa kirateriniiiiFsi"tha t""thi~rsiul it thW~itt

11 frntin f the'EAB?and;theilPZ will not exceed e 10"CFR"100'dois uideline limits EF someTffikt16sthsFi6f following kotodor#a'contro1FrodTifictT6n a SGT falMSteifaii16ckid~

.aceidet'.RThe;spebtfic' a' ctivitifofathaireictor/ coolant 7eiaFali6ibeslimitedtdue GDC019/ghi_deline*do' esIfollowtngla:SGTR$1ockedirotor[^M6 s

~

control erodle,,jectionj oria1MSLB taccident Qghels afety bf~the~fea(ctor coolant :t tEfl00^TiEtt and = n ut h;" nal a

==t:r n:hr,t :tn; ;bendaff31eakage rate ^6f"tS0;gS/SGI6F eritiigipfinifHto7ie=:nt:r '00) tri: s~hs556fiial bp#Ffron:

1 thiskondarySisakageMBased upontthe3artisularidose411 sSG s Jimi tati on Mfaide terminati onli s?madelofi the* maximus '~

allowablefprina? osiecondarydeakageirate?asgfusitT5G"6f (opelequjMent.

Isctivit41eyele1QhelRCS: Thi'infety' analysis assumes he specif<c activity of the secondary coolant at its limit of 0.1 pC1/gm DOSE EQUIVALENT I-131 from LCO 3.7.6, " Secondary Specific Activity."

APPLICABLE The analysis f: th: 00T", :nid=t :stablishes the SAFETY ANALYSES nn tun Ellssibl#jlimits for thsit6 tie ^riliiWQti EEo;ndary'll makage'l:asisifshstioPofjRCS'ipe)c ' 'fi c~ a ct i vi t i

RefelFiWei^t6^thii'iWilysis'is used to assess changes (continued) to the ishtitFEst?sT16sablellsikaisfMTaTNnstisElf!RCS iiiiVityflev'elfis%h(SGi.tubesicontiiueltoidegradeh,M,WM w w = x n zz. w s.n..,..= >. z c. =.=... a a n =.. m =, =. =.. =..

a.

w th: u n;tu n li it:.

(continued)

WOG STS B 3.4-95 Rev 1, 04/07/95

RCS Specific Activity B 3.4.16 BASES F3EthTraHiss?i,rcTdistTihilf~2,TTEtGF(EiiiiWi~ivilsi,fic-sh u n =... c m... m....=.z 2.. _..u..... m.s.n w. ___ 1........,.... u..

irm

=i

t hit.

T6e ~f I Fs tic ase ras s_umes s an? accidentii n i t i a tid lusik~eTai"6scurredcattthel48;hournvaluelfondose' fequivali6E El.MThetRCStisiassumedito1befatia*maximumfoftI Kheiticidengi nit i ated l spi ke sincre ase s Rthe ireleas!i pC1/g 2 and "

e5ofrdose equivalentt-If from'the tfuelitoitheireictorJcoolantib ;a~~

factorEofi335iforitheiSGTRtand by*Talfact' rInf4600lfor)?all o

b t he+r, a, c,c i den t s 9 ^'"'.,..J..'..'.;. T. ' W...'. J

-' '.'.l '. _.-'."..I. 't ','

r=' #- -

""*'#'"'~

hd b;,:.=...

.k,

S

.r a mee e r..

pii: th:t h;r;;;;; th: : :: ::t 5ita h th:

r:::t:r :::hnt he : f::t:r :f :h t 5" i--- :di:t:b :'t:r th: :::id:;t. The second case assumes the initial reactor coolant iodine activity li pal si3f 6Ffdoish,u,l' ' ale,ht A'gt3he 'six Wumf(list f_ ofc60 $C to re v

existin{ spike.~.a..a

,..ui r e..

u c

M^d~iii..:.. Fig. din: :pik; caused by an RCS transient.

In

>oth cases, the noble gas activity in the reactor coolant assumes 1% failed fuel which closely equals the LCO limit of 100/E #Ci/gm for gro,ss specific activity.

l The analysis also assumes a loss of offsite power at the same time as the SGM event. Th; SCT" ::::::

7:d::th; h r:::t:r :::hnt h :nt:r r:::t:r t i; fr;; ; h y.

Th; r:d :t Sn uit':t:: :

r

::: i::r pr;;;;r:

i;;;l :r :n RC" v:rt::p:;:tur; d.T :ign:1.

The coincident loss of offsite power causes the steam dump valves to close to protect the condenser.

bisfof ThelWiIi57; b f fsi tijsserffesul ti{i nithe5Fil eisilf *r h: S h

thi~Mt: Fir!C~disiSrgif~radi6ictiVily contaminated steam to the atmosphere through the SG power operated relief valves and the main steam safety valves foF?theI16Ekid Fot 6rEcontVol?rodliject issinLSGTRia6Eidents 2 ForitKi flSLBkradioactivityeis? assumed tosbeireleasedsdirectlyj~fR5 theibreakitolatmosphbre#ForztheiNSLBland thei5GTR ^

' ccident'si~the^IinaffedtidSGi" Vim 6Ve Y6fi'^di&iy~heit by a

kent'ing~ steam to the atmosphere until the cooldown ends.

The safety analysis shows the radiological consequences of an SGTR br7a}thE71'E'^dEEF:1ockid M ts Eaccident are fraction of dose guideline limits 6f#ifi

)D07ahd}thititEsT6nisidehdii'6fJatMSL831s[Withthithe-~

gui del i ne ;l imi t siefi Parte 100 ?foria lprek exi s ting tspike'Tiid twell Wri thin 1Pa rtdO0 ifor?thelaccident4i niti atod ispi kisca si NDif0Eiaicojttrolgo,disjs11oglaccide(tiiTjteldo_sf^~^'-"'

0 (continued) il0G STS B 3.4-96 Rev 1, 04/07/95

RCS Specific Activity B 3.4.16 BASES b ____, t_o a rco_n.t_rol r..__t_or_(fo.

ll :acci_ den.t.

onsequencesf f oom opera rma t

m' ust1be;::within't

'iodihe ^ip^ecifiE~he guidelines:ofgGDCL19f'05eration~with~setlVit is permissible if the gialefithe'nofmallopsFatingfisiafi Wsecoridaffil$ikiisNndithe1projectedieventsinducedfl hoesinotiexceed::theNyalue?in Figure:3;4.16;1 forithe,eakags a' ccidentMnitiatedjsp~ike ca~sejforftheicorrel' tediaEtivity a

levils~de Est"illii;. tht~1 bi Ji~i.?f0h'ih Tii;?i"!.i.15 1 h

th: ppik:th : ::ifh:thn for more than 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> d

iiiximum?a116Giab1IsihEtivity3e,ielrofidoielegiiVilenffM i

f

$1chimanbelassumeditsAg#gf

~

hiiFiHEWdidFlWY ijiifil3Z1871i1YT11sItill6E"bEthi F

E' ~ llin?the RCS > asia'functionfofiallowableiprimarysto-~~

• icond ary?l ea ka ge ;dThei combin a t ionlo fje ' maximum ; alliEli s

$ n stan tane ous y val ue?o f;do se ' equiia l ent't-I! and ?the"marimus"~

hilowable:priaa~ryitotsecondaryAeakageWite hastboen- ~

de termi ned t ba sediuponi: l ini ti ng ?the i con s equence s to fi a ?SGTR kndialockedirotor/accidentitoiwithin*afsmall fraction >of the7 dose guideliniilimitsfof Parti 100}andfthe consequencei i

l bfAticontrolirodiejectioniaclcident tand:MSLBTaccidents ~~

2 n1 ti ated is pi ke'cas e itoiwel l) wi th in ? Part 71003 imi tsdi[thi konsequen6e s ? o f2 a ? MSLB rpre;ex t s ti ng 3pi ke icas6 to1 Part n100 i?

l Thetconsequehcestoffany accident 7sust not>resultAirnthe - ~~

l g" ui del i ne s i ofL GDC)191 being7 exceeded JThymaximum ?all owibli

$sif f tf YsTif t s~ hli;forTdose iequ i val entsMisWT'~'~Thf~~^

nstantaneousWalue

i E 0ffsht EEd ";i? ?^I; M 55 f h d k :

pikh; hv:h ;; t: 50.0 #C1/gml 00!E E0'.'!YALENT ! 1 1.

Th: r;;;ht:r Of th; :b::: 1 hit ;; m h:tbh i:d h: hv S

h:un h Tig;r: 2.4.15 1 :r: ::::pt:th i:::::: :f th: hw pr:i:tility :f : ::T". :::id: t :::;rrh; dark; th:

t:bli;h:d t0 5:;r it:: lirit. Th; :::;rr:n;; f :n SCTP, APPLICA"LE

id:nt :t th::: ;;mh:ibh hv;h :: 1d her:::: th: :ite SffETY ?E LYSES 5:;nd:ry d::: hv:h, but :till 5: with h 10 CFP, 100 d:::

(::nt b.' d)

i'

1 6

li;it:.

The limits on RCS specific activity are also used for establishing standardization in radiation shielding any-plant personnel radiation protection practices.

RCS specific activity satisfies Criterion 2 of the NRC Policy Statement.

(continued)

WOG STS B 3.4-97 Rev 1, 04/07/95

RCS Specific Activity B 3.4.16

-BASES LC0 The specific iodine activity is limited to FliiiiilisiiiiiiTu's 76rEthe1487h5DFWa16e'ofjl.0 pC1/gm DOSE EQUlVALENT~l-131",'

an(for;the'eaxi' linstantaneousijilueTif>60ipC1 fed ~thiThe grois~ipiElfic '/diiiifot boseagstvalenti r

actTvity

'ih~ths fiict~oF~'coolint is limited to the number of #C1/gm equal to 100 divided by E (average disintegration energy of the sum of the average beta and gamma energies-of the coolant nuclides). The limit on DOSE EQUIVALENT I-131 ensures the 2 h=r thyr:id dose to an individual at the +44e innd:ry d;rt - th: 5 ;i h;i;f.nidnt(0"';$ABiasditPZ will be : =:1I fr=ti=;;f th: :lh=d th[ffectionithereof~

"nid _siitithin

' hi3uideliheiToD10JCFRIPiFt110076risciiie~

t f or ? a ; 1 oc ked irotoM contro1 Trod ie' ject ion S$GTRhoriMSL8 "

accident G Thei consequenceff4 Diny!acc i den ti ou s t i n6tireifil t l

in;the'gutdelineMof GDC019Sbeingixceededjfontheicontrel ~

p6omoieratopMThiTimit~66^gF6sispicificactiviifeniUFes the'T.5Ef7h31e body dose to an individual at the +44e h=d:ry durin; th 0"", JABTahdithilLPZjwill be a small fraction of the :1hnd wholi^ body ~d6ie f6Ri!$GTRT4Ei 16cked76t EMcididentWthEfe11 PaFtt1001thyroididose*fo~rii NLBtwithia! pre-existing (spike!a[ddTwslinithin!Part?1004for.

alcontrolitsd iej ection t accidents andiatMSLB iwithiani acc ident j n t t i ated Espi ke glaniallicas_esjdhelguidelj nesloflGDCM 9 ~~

mustabelantn Th SCT", :=id=t =:ly:S (5f. 2? :h= tht th 2 hur ciu h=d:ry d=: h=h :=. ith1:==;t:th li;it;.

Violation.of the LCO may result in reactor coolant radioactivity levels that could in the event of an SGTR11

$LB3166 kid FotbF2iE3tiihtf61 NidTijicti6niisc idsnf)'the le$f tFit ti^ E5EdiFTd o sis"atttheIEAB ?sr3 LPZ"t h'it"'eWEiid 10 CFR 100 dose-IPe atidlhisjd;guidelihistandifonthosc6' ntr615FssaMijildelines l

l

-APPLICABILITY In MODES I and 2, and in MODE 3 with RCS average temperature 2 500'F, operation within the LC0 limits for DOSE EQUIVALENT I-131 and gross specific activity are necessary the potential consequences of an SGTR!If16dkedW to containitsFpM66t F6d ejectisnTeiFVMSLB?acEidistl to withiE~thi~iEEspt'ibli~

6iti'iEEfidIFf~d6si~M1E5T uideTiWiMf4PiFt1100M ' ' ' ~~

ffectioEthep6fliidi;thili)videlissieffGDCG9f~risssi

(= tin =d)

WOG STS B 3.4-98 Rev 1, 04/07/95

RCS Specific Activity B 3.4.16 BASES For operation in MODE 3 with RCS average temperature

<S00'F,andinMODES4and5,LBjisunlikelysincethethe release of in the event of a SGTR k a MS saturation pressure of thT riactor coolant is below the lift pressure settings of the main steam safety valves.

(::ntin;;O WOG STS I 3*4 99 Rev 1, 04/07/95 1

J

RCS Specific Act10ity B 3.4.16

-BASES (continued)

ACTIONS.

A Note to the ACTIONS excludes the MODE change restriction of LCO 3.0.4.

This exception allows entry into the a>plicable MODE S tie ACTIONS may(ev)entually require plant shutdown.while relying o This exception is acceptable due to the significant conservatism incorporated into the specific activity limit, the low probability of an event which is limiting due to exceeding this limit, and the ability to restore transient specific activity excursions while the plant remains at, or proceeds i

to power operation.-

l A.1 and A.2 i

With the DOSE EQUIVALENT I-131 greater than the LCO limi",

l samples at intervals of 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> must be taken to demonstrate that the limits of Figure 3.4.16-1 are not exceeded. The Completion Time of 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> is required to obtain and analyze a sample.

Sampling is done to continue to provide a trend.

The DOSE EQUIVALENT I-131 must-bs restored to within limits within 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />.

The Completion Time of 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> is required, if the limit violation resulted from normal iodine spiking.

B.1 and B.2 With the gross specific activity in excess of the allowed limit, an analysis must be performed _within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> to determine DOSE EQUIVALENT I-131.

The Completion Time of 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> is required to obtain and analyze a sample.

The change within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> to MODE 3 and RCS average temperature < 500*F lowers the saturation pressure.of the reactor coolant below the setpoints of the main steam safety.

valves and prevents venting the SG to the environment in an SGTR event. The allowed Completion Time of 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> is reasonable, based on operating experience, to reach MODE 3 below 500*F from full power conditions in an orderly manner and without challenging plant systems.

ACTIONS G,d (continued)

WOG STS B 3.4-100 Rev 1, 04/07/95

RCS Specific Activity B 3.4.16 BASES ACTIONS I.d (continued)

If a Required Action and the associated Completion Time of Condition A is not met or if the DOSE EQUIVALENT I-131 is in the unacceptable region of Figure 3.4.16-1, the reactor must be brought to MODE 3 with RCS average temperature < 500'F within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.

The Completion Time of 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> is reasonable, based on operating experience, to reach MODE 3

~

below 500*F from full power conditions in an orderly manner and without challenging plant systems.

SURVEILLANCE SR 3.4.16.1 REQUIREMENTS l

SR 3.4.16.1 requires performing a gamma isotosic analysis as f

a measure of the gross specific activity of-tie reactor coolant at least once every 7 days. While basically a-quantitative measure of radionuclides with half lives longer than 15 minutes, excluding iodine, this measurement is the sum of the degassed gamma activities and the gaseous gamma activities-in the sample taken. This Surveillance provides an indication of any increase in gross specific activity.

Trending the results of this Surveillance allows proper remedial action to be taken before reaching the LCO limit under normal operating conditions. The Surveillance is applicable in MODES I ard 2, and in MODE 3 with T,Tikeliho at-least 500*F. The 7 day Frequency considers the un of a gross fuel failure during the time.

SR 3.4.16.2 This Surveillance is performed in MODE 1 only to ensure iodine remains within limit during normal operation and following fast power changes when fuel failure is more apt to occur.

The 14 day Frequency is adequate to trend changes in the iodine activity level, considering gross activity is monitored every 7 days.. The Frequency, between 2 and 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> after a power change ;t 15% RTP within a 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> period, is established because the iodine levels peak during this time following fuel failure; samples at other times would provide inaccurate results.

(continued)

WOG STS B 3.4-101 Rev 1, 04/07/95 w

'RCS Specific Activity B 3.4.16 BASES SURVEILLANCE' SR 3.4.16.3-

= REQUIREMENTS

'(continued)

A radiochemical analysis for I determination-is required every 184 days (6 months equilibrium conditions. )The E determination directlywith the plant-o relates to the LCO and is required to verify plant operation within the specified gross activity LC0 limit.. The analysis for E is a measurement of the average energies per

~

disintegration for isotopes with half lives longer than 15 minutes, excluding iodine. The Fre recognizes E does-not change rapidly. quency V 184 days i

This SR has been modified by a Lote that indicates sampling is required to be performed within 31 days after a_ minimum-of 2 effective full power days and 20 days of MODE 1 operation have elapsed since the reactor was last subcritical for at least 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />. This ensures that the radioactive materials are.at equilibrium so the analysis for E is representative and not skewed by a crud burst or other similar abnormal event.

REFERENCES 1.

10 CFR 100.11,.1973.

M63fMIDis[iKTffjM166))Dyg@H[silD0]pFj 2.

hol o

3.4 -REACTOR COOLANT SYSTEM (RCS) 3.4.16 RCS Specific Activity LCO 3.4.16 The specific activity of the reactor coolant shall be within limits.

-APPLICABILITY:

MODES I and 2, MODE 3 with RCS average temperature (Tm) it 500*F.

ACTIONS SURVEILLANCE FREQUENCY

-(continued)

WOG STS B 3.4-43 Rev 1, 04/07/95

RCS Specific Activity 3.4.16 SR 3.4.16.1-

7. days Verify reactor coolant gross specific activity $ 100/E pC1/gm.

SR 3.4.16.2

---

NOTE--------------------

Only required to be performed in MODE 1.

14 days Verify reactor coolant DOSE EQUIVALENT I-131 specific activity s 4,4 Ujs M 314Il6ily C1/gm.

&E Between 2 and 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> after a THERMAL POWER change of 2 15% RTP within a 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> period (continued)

SR 3.4.16.3

---

NOTE--------------------

Not required to be performed until 31 days after a minimum of 2 effective full power days and 20 days of MODE 1 operation have elapsed since the reactor was last suberitical for 2 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />.

Determine E from a sample taken in MODE I after a 184 days minimum of 2 effective full power days and 20 days of MODE 1 operation have elapsed since the reactor was last suberitical for 2 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />.

(continued)

WOG STS 3.4-44 Rev 1, 04/07/95 l

Plant A TS Plot of Allowable Leakage 1

Allowable Leakage, gpm 10,000

+ r w

so.

+m ww.o

~ h#g Pump Cepeel,y 1,000

- a n-v

-.w

=

q_

~

x m

l 10

~~

1 0.1 1

10 100 RCS Activity DE l-131, uCi/gm Figure 3.4.16-1 A

Plant B TS Plot of '.~owable Leakage Allowable Leakage, gpm 10,000

+,

% w.

i h : %w a,

e

= =,

1,000

,y 1._.w l

<z m

10 1

1 0.1 1

10 100 RCS Activity Dose Equivalent I-131, uCi/g Figure 3.4.16-1 B

Plant C TS Plot of Allowable Leakage Allowable Leakage, gpm 10,000 1,000 100

+r

% so.

10 V- -

• Chorg.no Pwny Cepeelty

~ve 1

L 0.1 1

10 100 RCS Activity Dese Equivalent I-131, uCi/g Figure 3.4.16-1 C

DRAFT REGULATORY GUIDE DG 1074 9/5/97 STEAM GENERATOR TUBE INTEGRITY A. INTRODUCTION The steam generator (SG) tubes in pressurized water reactors have a number of important safety functions. These tubes are an integral part of the reactor coolant pressure boundary (RCPB) and, as such, are relied upon to maintain primary system pressure and inventory. As part of the RCPB, the SG tubes are unique in that they are also relied upon as a heat transfer surface between the primary and secondary systems such that residual heat can be removed from the primary system and are relied upon to isolate the radioactive fission products in the primary coolant from the secondary system. In addition, the SG tubes are relied upon to maintain their integrity, as necessary, to be consistent with the containment objectives of preventing uncontrolled fission product release under conditions resulting from core damage i

severe accidents.

As used in this regulatory guide, tube integnty mears that the tubes are capable of performing their intended safety functions consistant with the current licensing basis, including applicable regulatory requirements as summarized in B.1.

Concerns relating to the integrity of the tubing stem from the fact that the SG tubing is subject to a variety of corrosion and mechanically-induced degradation mechanisms which are widespread throughout the industry. These degradation mechanisms can potentially impair tube integrity if not managed effectively.

This regulatory guide describes an acceptable approach for monitoring and maintaining the integrity of the SG tubes at operating PWRs. It also provides guidance on evaluating the radiological consequences of design basis accidents involving degraded SG tubing in order to demonstrate that 10 CFR 100 guidelines regarding offsite doses and GDC-19 regarding control room operator doses can be met. This guide applies on!y to pressurized water reactors (PWRs).

B. DISCUSSION 1.

Current Licensing Basis, including Applicable Regulatory Requirements Title 10 of the Code of Federal Regulations establishes the fundamental regulatory requirements with respect to the integrity of the SG tubing. Specifically, General Design Criteria (GDC) of 10 CFR, Part 50, Appendix A, applicable to the integrity of the steam generator tubes include the following:

a. GDC-1, " Quality Standards and Records," states in part that structures, systems, and components important to safety shall be designed, fabricated, and tested to quality standards commensurate with the importance of the safety functions to be performed.

2 DG 1074 8/5/97

b. GDC 2," Design Basis for Protection Against Natural Phenomena," states in part that structures, systems, and components important to safety shall be designed to withstand the effects of natural phenomena without loss of capability to perform their safety functions....

c. GDC-4, " Environmental and Dynamic Effects Design Basis," states in part that structures, systems, and components important to safety shall be designed to accommodate the effects of and +n be compatible with the environmental conditions associated with normal operation, maintenance, testing, and postulated accidents and shall be protected against dynamic effects that may result from equipment failures and from conditions and effects outside the nuclear unit. However, dynamic effects associated with postulated pipe ruptures in nuclear power units may be excluded from the design basis when analyses reviewed and approved by the NRC detoonstrate that the probability cNping rupture is extremely low under canditions consistent with the design basis for the piping.

d. GDC 14, " Reactor Coolant System Boundary," states that the RCPB shall be designed, fabricated, erected, and tested so as to have an extremely low probability of abnormalleakage, of rapidly propagating failure, and of gross rupture.

e. GDC 30, " Quality of the Reactor Coolant Pressure Boundary," states that components which are part of the RCPB shall be designed, fabricated, erected, and tested to the highest quality standards practical. Means shall be provided for detecting and, to the extent practical, identifying the location of the source of the reactor coolant leakage.

- f. GDC-31 " Fracture Prevention of Reactor Coolant System Boundary," states in part that the RCPB shall be designed with sufficient margin to assure that when stressed under operating, maintenance, testing, and postulated accident conditions the probability of rapidly propagating fracture is minimized. The design shall reflect consideration of service temperature and other conditions of the RCPB materials and the uncertainties in determining material properties; residual, steady state, and transient stresses; and the size of flaws,

g. GDC-32, " Inspection of the Reactor Coolant Pressure Boundary," states that components which are part of the RCPB shall be designed to permit periodic inspection and testing of important areas and features to assess their structural and leak tight integrity.

10 CFR 50, Appendix B, establishes the quality assurance requirements for the design, construction, and operation of safety related components. The pertinent requirements of this appendix apply to all activities affecting the safety related functions of these components; these include, in part, inspection, testing, operation, and maintenance. Criteria IX, XI, and XVI of Appendix B are particularly noteworthy with respect to the integrity of the steam generator tubing. Criterion IX," Control of Special Processes", requires that measures be established to assure that special processes such as welding, heat treating, and nondestructive testing are controlled and accomplished by qualified personnel using qualified procedures in accordance with applicable codes, standards, etc. Criterion XI, " Test Control", requires in part that a test program be established to assure that all testing required to demonstrate that structures, a

f I

l 3

DG-1074 l

8/5/97 l

systems, and components will perform satisfactorily in service is identified and performed in accordance with written test procedures which incorporate the requirements and acceptance l

limits contained in applicable design documents. Criterion XVI," Corrective Action", requires,in part, that measures be established to assure that conditions adverse to quality are promptly identified and corrected.

1 l

As part of the plant licensing basis, applicants for a PWR operating license are required to analyze the consequences of postulated design basis accidents which assume degradation of l

the SG tubes such that primary coolant leaks to the secondary coolant side of the steam generators. Examples of such accidents are a steam generator tube rupture (SGTR), a main steam line break (MSLB), a locked rotor, and a control rod ejection. Analyses of these accidents consider the primary to secondary leakage that may occur during these postulated events to demonstrate that radiological consequences do not exceed 10 CFR 100 guidelines, or some fraction thereof, concerning offsite doses and GDC 19 concerning control room operator doses. NUREG 0800," Standard Review Plan"(SRP), Reference 1, provides guidance by which the staff evaluates these accidents. This regulatory guide also provides acceptable alternative guidelines concerning the assessment of the radiological consequences of SGTR and MSLB accidents.

Consistent with the GDC,10 CFR 50.55a specifies that components which are part of RCPB must (be designed and constructed to) meet the requirements for Class 1 components in Section lil of the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code. To ensure the continued integrity of the tubing at operating PWR facilities, 50.55a further requires, in part, that throughout the service life of a PWR facility, ASME Boiler and Pressure Vessel Code (ASME Code) Class 1 components meet the requirements, except design and access provisions and preservice examination requirements, in Section XI, " Rules for Inservice Inspection of Nuclear Power Plant Components," of applicable editions of the ASME Code, to the extent practical. This requirement includes the inspection and repair criteria of Section XI of the ASME Code. However, paragraph (b)(2)(iii) of 10 CFR, Part 50.55a, states that where technical specification surveillance requirements for steam generators differ from those in Article IWB 2000 of Section XI of the ASME Code, the inservice inspection program shall be governed by the technical specifications.

The plant technical specifications, which are typlified by the standard technical specifications in References 2,3, and 4, require that licensees perform periodic inservice inspections of the SG tubing and to repair or remove from service (by installing plugs in the tube ends) all tubes exceeding the tube repair limit, in addition, operationalleakage limits are included in the technical specifications to ensure that should tube leakage develop, the licensee will take prompt action to avoid rupture of the lenking tube (s). These requirements are intended to ensure that burst margins are maintained consistant with 10 CFR 50, Appendices A and B and that the potential for leakage is maintained consistant with what has been analyzed as part of the plant licensing basis. This regulatory guide addresses shortcomings in these plant technical specifications in terms of ensuring that these objectives are met. The technical specifications should be revised as necessary to be consistent with this regulatory guide.

NRC Regulatory Guide 1.83," Inservice Inspection of Pressurized Water Reactor Steam

4 DG-1074 8/5/97 Generator Tubes," Revision 1, July 1975, provides guidance concerning SG inspection scope and frequency and nondestructive examination (NDE) methodology. This regulatory guide is referenced by the standard review plan (SRP) and is intended to provide a basis for reviewing inservice inspection criteria in the technic.al specifications. However, this guidance is superseded by this regulatory guide, NRC Regulatory Guide (RG) 1.121, " Bases for Plugging Degraded Steam Generator Tubes," August 1976, provides guidelines for determining the tube repair criteria and operationalleakage limits which are specified in the technical specifications. These guidelines are superseded by this regulatory gulde, 2.

Summary of Approach This regulatory guide provides an acceptable approach for monitoring and maintaining the Integrity of the SG tubes consistent with 10 CFR 50, Appendices A and B, and the plant licensing basis. This framework includes performance criteria commensurate with tube integrity, programmatic considerations for providing reasonable assurance that the performance criteria will be met during plant operation, and guidelines for monitoring the condition of the tubing to confirm that the performance criteria are being met.

Figure 1 provides a flow chart illustration of the overall program strategy embodied in this regulatory guide, including each of the major program elements and sub-elements. Figure 1 includes a cross-reference to the sections in Part C of this regulatory guide containing the specific guidance for these program elements and sub-elements.

Specific implementation details and methodologies for these program elements are to be developed by the utilities, with the exception of element 1 (performance criteria) and element 9 (radiological assessment) for which specific guidance is provided herein. This regulatory guide provides broad guidelines concerning the key considerations, parameters, and/or constraints which should be addressed as part of the development of these program elements to ensure, that tube integrity performance can be effect'vely monitored and controlled relative to the tube performance criteria. It is the intent of these guidelines that licensees have the flexibility to adjust the specifics of the program elements within the constraints of these guidelines to reflect new information, new NDE technology, new degradation mechanisms, changes in flaw growth rates, etc. without NRC review and approval. Full realization of this flexibility will necessitate development and implementation by licensees of steam generator defect specific management (SGDSM) strategies. SGDSM strategies involve an integrated set of program elements, paralleling those in this regulatory guide, which address specific degradation mechanisms.

As shown in Figure 1, the program strategy begins with an NDE tube inspection following plant shutdown in accordance with Section C.1 of this regulatory guide. The inspection is intended to provide information concerning the active degradation mechanisms present in the SGs, the identity of tubes containing flaws and the size of these flaws for each active degradation mechanism, and the rate of flaw evolution for each active degradation mechanism, This information is used as part of other program elements, discussed below, to assess tube integrity performance relative to the tube integrity performance criteria, to determine the

l l

5 DG-1074 l

8/5/97 1

l appropriate time interval to the next inspection, to determine the appropriate tube repair limits, l

to determine which tubes fail to satisfy these repair enteria (and which must, therefore, be repaired or removed from service), and to assess needed improvements in measures being taken to mitigate active degradation mechanisms.

i With respect to tube inspections in accordance with C.1, C.1.1 provides guidance for assessing, prior to each inservice inspection, degradation mechanisms which may potentially affect the tubing. This is to ensure that appropriate NDE inspection techniques and personnel

(

are used to address each mechanism. C.1.2 provides guidance conceming the development and implementation of NDE data acquisition and analysis procedures for each degradation mechanism. This is to ensure that NDE sizing and detection performance is known and thus can be appropriately accounted for in assessing tube integrity performance relative to the tube integrity performance criteria. C.1.2 includes guidance conceming the qualification and performance demonstration of NDE techniques and personnel. C.1.3 provides guidance pertaining to the frequency of inspection and tube inspection sample size. This is to ensure the frequency and scope of Inspection is defined in such a manner as to ensure that tube integrity performance is consistent with the tube integrity performance criteria.

The tube inspections are followed by assessments of tube integrity performance relative to NRC accepted performance criteria which are commensurate with adequate tube integrity.

Performance criteria acceptable to the NRC are given in Section C.2 of this regulatory guide.

These performance criteria address three areas of tube integrity performance; namely structural integrity, operationalleakage integrity, and accident induced leakage integrity. These performance criteria are expressed in terms of parameters which are directly measurable or which may be calculated on the basis of direct measurements. The criteria correspond to conditions under which public health and safety is still assured.

Performance criteria for tube structural integrity which are acceptable to the NRC, as identified in C.2.1.1, involve deterministic safety factors against burst which are consistent with the original design basis; namely, factors of safety consistent with the stress limits of Section lll of the ASME Code. Alternatively, acceptable performance criteria for tube structuralintegrity may be based on probabilistic criteria, as identified in C.2.1.2, which are consistent with GDC-14 and 31, and will be subject to demonstrating that an acceptable level of risk from induced tube failure will continue to be maintained. Guidance to conduct the associated risk assessment is contained in regulatory guide DG 1073,"An Approach to Plant Specific, Risk-Informed Decision Making: Induced Steam Generator Tube Rupture."

Performance criteria for accident-induced leakage which are acceptable to the NRC, as identified in C.2.3, are consistent with the current licensing basis. The current licensing basis for most PWRs consider that SG tube leakage during postulated accidents will be within an assumed value for purposes of demonstrating that the consequences are in accordance 10 CFR 100 guidelines, or some fraction thereof, and GDC-19. The performance criteria for accident induced leakage may be revised, consistent with C.2.3, subject to updating the licensing basis radiological assessments in accordance with the guidance in C.9 to consider an assumed SG tube leakage value consistent with the revised performance criteria and subject to demonstrating in accordance with the guidance in DC-1073 that these criteria are consistent i

6 DG 1074 8/5/97 with ensuring that risk is maintained at an acceptably low level.

Tube integrity performance is subject to two different types of assessments, as indicated in Figure 1; a condition monitoring assessment in accordance with Section C.3 of this regulatory guide and an operational assessment in accordance with Section C.4. The condition monitoring assessment is " backward looking"in that it's purpose is to confirm that tube integrity has been maintained since the previous inspection. Condition monitoring involves an assessment of the "as found" condition of the tubing relative to the tube integrity performance criteria. The condition monitoring assessment may utilize information from the tube inspections and/or from attemative test / examination methods to assess the condition of the tubing. NRC should be promptly notified in accordance with Section D.2 should condition monitoring reveal one or more tubes that fall to meet the performance criteria. Note that this kind of finding may or may j

not be indicative of programmatic deficiencies in the licensee's program for monitoring SG tube integrity, in addition, licensees should assess the causal factors associated with this type of finding and implement appropriate corrective actions in accordance with Section C.6 of this regulatory guide. The condition monitoring assessment and implementation of resulting corrective actions, if necessary, must be completed prior to plant restart.

The operational assessment differs from the condition monitoring assessment in that it is

" forward looking" rather than " backward looking." Its purpose is to demonstrate reasonable assurance that the tube integrity performance criteria will be met throughout the period prior to the next scheduled tube inspection. Operational assessment involves projecting, at an appropriate level of confidence, the condition of the tubing at the time of the next scheduled inspection outage relative to the tube integrity performance criteria. This projection is based on the above mentioned inspection results, the tube repair criteria to be implemented for each degradation mechanism in accordance with C.S.1, and the time interval prior to the next scheduled tube inspection. Corrective actions in accordance with Section C.6 should be taken, as necessary to ensure that the performance criteria are met. Corrective actions may include inspecting the steam generators at more frequent intervals and/or reducing the tube repair criteria. The operational assessment and implementation of resulting corrective actions, if necessary, should be completed within 90 days following plant restart. However, it will generally be necessary to perform at least a preliminary assessment prior to performing tube plugging and/or repairs to ensure that the tube repair criteria being implemented are sufficient to support operation for the planned operating interval preceding the next scheduled steam generator inspection.

Plugging and/or repair of defective tubes is performed in accordance with Section C.5, prior to plant restart, based on the resu"s of the tube inspections and operational assessment.

Defective tubes are those with indicated flaws exceeding the tube repair limit. Plugging and/or repair of defective tubes is intended to ensure that tubes remaining in service will meet the tube integrity performance criteria until the next scheduled tube inspection.

C.S.1 provides guidelines for determining the appropriate repair limits for each degradation mechanism. An acceptable repair limit which is applicable to all de0radation mechanisms is the 40% throughwall, depth-based criterion. Alternative repair criteria (ARC) may developed and implemented for specific degradation mechanisms as part of a steam generator degradation-m

7 DG-1074 8/5/97 specific management (SGDSM) strategy, subject to demonstrating that risk will be maintained at an acceptably low value. SGDSM constitutes an integrated approach consisting of an operational assessment methodology in accordance with C.4, specific inservice inspection programs (with specified frequency and level of sampling, specified qualified / validated NDE techniques) consistent with C.1, and repair limit computational methods aimed at ensuring that the performance criteria for tube integrity are met prior to the next scheduled inspection. C.S.2 provides guidelint.s for developing appropriate plugging and repair methodologies, including the associated hardware (e.g., plugs and sleeves).

Preventive measures are implemented in accordance with Section C.7 and involve measures to mitigate active degradation mechanisms and to minimize the potential for new degradation mechanisms. C.7.1 addresses secondary water chemistry control. C.7.2 addresses measures to controlloose parts and foreign objects within the steam generators.

C.7.3 addresses other measures for mitigating active degradation mechanisms. Various preventive measures are implemented continuously during plant operation and shutdown. The need for enhancements to these measures should be reviewed and implemented, as necessary, based on inspection results and the tube performance assessments.

Operational primary to-secondary leakage monitoring is performed in accordance with Section C 8. These guidelines are intended to ensure that leakage is effectively monitored and that appropriate and timely action will be taken before a leaking tube exceeds the tube integrity performance criteria, including tubes undergoing rapidly increasing leak rates. C.8.1 addresses development of monitoring programs. C.8.2 addresses development of LCO limits in the technical specifications for allowable operational leakage. C.8.3 addresses development of procedural limits for operational limits to ensure the performance criteria are met.

Guidelines for evaluating the radiological consequences of SG tube leakage during l

postulated accidents relative to 10 CFR 100 guidelines for offsite doses, or some fraction i

thereof, and GDC 19 criteria for control room operator doses are addressed in Section C.9.

l Section C.10 of this regulatory guide discusses the need for conducting risk assessment to support:

1.

any initial use (at a given plant for a given degradation mechanism) of performance criteria for tube structural integrity which are probabilistically-based; 2.

any initial um (at a given plant for a civen degradation mechanism) of updated performance criteria for accident induced leakage integrity based on revisions to

- licensing basis to consider revised leak rates assumed to occur during design basis accidents; and 3.

use at a given plant of any defect specific alternate tube repair criteria.

Guidelines for conducting the risk assessment are in DG-1073 and for submitting reports to the NRC are provided in Section D.

g DC 10,74 8/$/ 7 Figure 1 PROGRAM STRATEGY / STEAM GENERATOR TUBE INTEGRITY Mont m

thutdaw yn' 4

15 4 ****= f** *a*"*a' l I r 3.0 Porterm Cendleen Mennenne Acessement 9

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I VM 4.0 PortomOperosenet ir Assosoment

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-E teW6eh Tube Repe6r 4.0 5; _. :.1 Corvoetive Assens a

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8.0 Monitor Opero#enalLookepe 8.0 Pederm Apprepnote Plugelng'Aspeles jg t

7.0 enpasmontmovenove Plant 11.0 Submn Repen to N.Outoge mesterly C

l l

10 DG-1074 8/5/97 C. REGULATORY POSITION l

The guidelines herein provide an acceptable approach for monitoring and maintaining the integrity of the SG tubes. This program should be documented in plant procedures, be auditable, and should conform to 10 CFR 50, Appendix B. Reporting requirements should be in accordance with Part D of this regulatory guide.

C.1 Tube inspections A steam generator tube preservice and inservice inspection program should be developed and implemented. The objective of the preservice inspection is to establish the baseline NDE response of tubes in new and replacement steam generators and to identify and remove from service or repair any defective tubes prior to initial operation of the steam generators. Defective tubes are tubes containing flaws (as indicated by inservice inspection) which fail to satisfy the applicable repair criterion (see C.S.1). The objectives of the inservice inspection program are to (1) identify active tube degradation mechanisms which are present, (2) detect and size tubing flaws, (3) determine the rate of new indications for each active degradation mechanism, (4) determine flaw growth rates for each active degradation mechanism, and (5) remove from service or repair all tubes found to be defective. Knowledge of the active degradation mechanisms is important from the standpoint of (1) identifying potential corrective measures which can be taken to mitigate these mechanisms as discussed in C.7.3, (2) ensuring that the most suitable NDE techniques are applied to address each mechanism as discussed in C.1.2, and (3) determining the appropriate repair limit to apply to each detected indication as discussed in C.S.1. The detection and sizing of flaws are a key objective since this information is needed to (1) determins which tubes contain indications exceeding the appropriate repair limit and which therefore need to be removed from service or repaired, (2) to perform a condition monitoring assessment in accordance with C.3 to confirm that performance criteria commensurate with adequate tube integrity are being met, and (3) to perform an operational assessment in accordance with C 4 to ensure that these performance criteria will continue to be met prior to the next scheduled inspection. The observed rate of new indications and observed growth rate of old indications (indications observed during the previous inservice inspection in tubes that were left in service and not repaired) for each active degradation mechanism are also needed in order to perform the operational assessment in C.4.

The preservice and inservice inspection program should include the following elements and considerations:

C.1.1 Assessment of Potential Degradation Mechanisms Licensees should assess what degradation mechanisms may potentially affect the steam generator tubes during the steam generator lifetime. The purpose of this assessment is to ensure that inspection techniques and personnel used for the detection and sizing of flaws are appropriate for all potential degradation mechanisms. Degradation mechanisms, in this context, include the circumstances of the degradation which may affect the appropriate NDE technique (s) which are applicable to that degradation. For example, the circumstances of J

m

11 DG 1074 8/5/97 stress corrosion cracking include (1) whether it initiates from the outer diameter (OD) or inner diameter (ID) surface of the tube, (2) whether it is axially or circumferentially oriented, and (3) the presence of tube or support structure geometric discontinuities, dents, or deposits which may mask defect signals. The assessment for potential degradation mechanisms should be performed prior to preservice inspection of new and replacement steam generators and prior to each scheduled inservice inspection of the steam generators. This assessment should include consideration of plant and steam generator design, materials, and operational practice (e.g.,

temperature, secondary water chemistry control performance). This assessment should also include consideration of the accumulated service time and degradation experience at the subject plant and at other plants of similar design, materials, and operational practice, as L

~ appropriate.

C.1.2 NDE Data Acquisition and Analysis Licensees should ensure that each organization (e.g., utility or vendor) that conducts SG NDE inspections has a written procedure for conducting NDE data acquisition and analysis. These procedures should be in accordance with the EPRI Steam Generator Examination Guidelines, Revision [X][ subject to satisfactory revision of the EPRI guidelines, Revision 4, to address NRC staff comments provided to the industry and NEl on April 8,1996 (see meeting summary dated April 22,1996, T. Reed to J. Strosnider).]. These procedures should also incorporate the following enhancements and clarifications:

a)

The procedures should ensure that NDE techniques used to address each potential degradation mechanism are " validated" for that mechanism and that this validation is applicable to the specific plant. For purposes of this regulatory guide, " validated" techniques are techniques.which have been qualified in accordance with the EPRI Steam Generator Examination Guidelines, Revision [X], Section 7 and Appendix H, and which have undergone supplemental performance demonstration in accordance with C.1.2.1. The technique validation is applicable to a specific plant when the circumstances of the degradation (as defined in C.1.1), noise amplitude (e.g., electrical noise, tube noise, calibration standard noise, deposit noise, dent signals, etc.), and signal-to-noise ratios were representatively included in the EPRI qualification and supplemental performance demonstration test samples. For degradation mechanisms for which there is no validated technique available, non-validated NDE techniques may be used provided that the techniques are qualified for detection in accordance with the EPRI guidelines. In addition, the data acquisition and analysis procedures should ensure that the use of non-validated techniques satisfy the guidelines in C.1.2.2.

Note, NDE technique refers to the specific data acquisition equipment and

-instrumentation, data acquisition procedures, and data analysis procedures. "NDE technique" in this context includes the summation of techniques directed at each degradation mechanism.

For example, the use of bobbin probes for performing an initial screening inspection followed by a rotating pancake coil (RPC) inspection to confirm possible indications found by the bobbin would constitute a single NDE technique for detection purposes.

Also note, NDE detection performance is evaluated in the EPRI guidelines in

_. terms of the probability that a given flaw is detectable, i.e., " probability of detection"(POD), and

i 12 DG-1074 8/5/97 the percentage of detected flaw indications which in fact are false calls, i.e., false call percentage (FCP). NDE techniques and personnel are " qualified for detection" when the subject performance criteria for POD and FCP in the EPRI guidelines are met. NDE techniques and personnel are " validated for detection" when they are " qualified for detection" and when l

supplemental performance demonstration in accordance with C.1.2.1 has been completed for i

detection. NDE sizing performance is evaluated in the EPRI guidelines in terms of the accuracy of NDE flaw size measurements versus actual flaw size. Accuracy is evaluated in terms of root-mean squared-error (RMSE) for a group of measurements. NDE techniques and personnel are

" qualified for sizing" when the subject performance criteria on sizing accuracy in the EPRI guidelines are met. NDE techniques and personnel are " validated for sizing" when they are

" qualified for sizing" and when supplemental performance demonstration in accordance with C.1.2.1 has been completed for sizing.

b)

The procedure should provide (directly, or by reference) a technique specification for each NDE technique to be employed to address each degradation mechanism.

The technique specification should identify the data acquisition equipment and instrumentation, data acquisition and analysis procedures, and values of all essential variables. For qualified / validated techniques, the technique specification should be consistent with what has been qualified / validated in accordance with item a above. In addition, the technique specification should be consistent with the data acquisition equipment and instrumentation, data acquisition and analysis procedures, and values of all essential variables implicit in steam generator degradation specific management (SGDSM) strategies being implemented in accordance with C.S.1 for specific flaw mechanisms.

c)

The procedure should ensure that all NDE personnel are " validated" for the NDE techniques to be used and for the degradation mechanisms for which they are being applied. For purposes of this regulatory guide, " validated" personnel are personnel who have been " qualified"in accordance with the EPRI guidelines (Reference X), Section 6 (including i

site specific performance demonstration) and Appendix G, and have undergone supplemental performance demonstration in accordance with C.1.2.1. This assumes that the NDE techniques are validated for the subject degradation mechanisms in accordance with item a above. Where this is not the case and a non-validated technique is being employed pursuant to C.1.2.2, the procedures should ensure that the NDE personnel meet the guidelines of C.1.2.2.

NDE personnel refers to NDE data analysts and to computerized data analysis systems.

Licensees should ensure that the qualification and supplemental performance demonstration records for NDE personnel describc the limits of applicability of the qualification and supplemental performance demonstration and that the NDE personnel are not performing their duties outside these limits of applicability; i.e., the specific NDE techniques and the " application" of these techniques for which the personnel have been validated. " Application" refers to the specific degradation mechanisms to which the subject NDE technique is being applied.

I C.1.2.1 Supplemental Performance Demonstration

[The guidelines of the section may be deleted in the final version of this regulatory guide if satisfactorily incorporated into the EPRI guidelines, Appendices G and H. In addition, " qualification"in accordance with the EPRI guidelines also constitutes " validation"in

i 13 DG-1074 8/5/97 accordance with C.1.2 provided the qualification satisfies the supplemental performance demonstration guidelines herein.]

NDE technique and personnel qualif4ation in accordance with the EPRI Steam Generator Examination Guidelines, Revision [XJ, ensures a minimum acceptable level of l

proficiency in the conduct of inservice inspections. However, the detection and sizing performance achieved during the qualification may or may not be fully indicative of the performance that can be expected in the field. For this reason, NDE techniques and personnel l

should undergo supplemental performance demonstration in accordance with the guidelines of this section to quantify their flaw detection and sizing performance for all potential degradation mechanisms to assess their capability to perform a reliable inspection, to determine the most appropriate NDE techniques for a given application, to identify needed improvements in NDE l

capabilities, to support the development of alternative tube repair criteria addressed in C.S.1, and to support the condition monitoring and operational assessments addressed in C.3 and C.4, respectively, POD performance is not considered directly as part of me condition monitoring assessment. However, POD performance should be assessed to ensure its adequacy to identify indications which potentially may fail'o meet the structural performance criteria of C.2.a.(1) or which may leak under postulated accident conditions. POD performance is considered as part of the operational assessment and development of tube repair criteria, either directly or indirectly, since the rate and size distribution of new indications that may occur prior to the next scheduled inspection is, in part, a function of POD. Sizing performance is considered directly as part of the condition monitoring assessment, operational assessment, and tube repair criteria development.

For some degradation mechanisms, " relative" sizing performance rather than

" actual"(i.e., " absolute") sizing performance may be of interest. This is the case when models for tube structural performance and leakage performance, used for the condition monitoring and operational assessments in C.0 and C.4, are based on empirical correlations with a measured NDE parameter (e.g., indicated length, depth, and voltage) rather than actual defect geometry (e.g., actuallength, depth, width). Relative sizing performance consists of the consistency (i.e.,

repeatability) of the size parameter response and the consistency (i.e., repeatability) of the analyst interpretation of this response. Absolute sizing performance consists of the accuracy of the NDE size parameter response and the analyst measurement of that response relative to the actual size of the flaw.

Demonstration of NDE relative sizing performance is not subject to the supplemental performance demonstration guidelines of this section lit is assumed that the forihcoming revision to the EPRI guidelines willprovide a satisfactory basis for quantifying relative sizing performance. The most immediate need in the EPRI guidelines involves the need for quantifying voltage measurement performance since structural and leakage models have been developed which are a function of voltage. If not addressed in the EPRI guidelines, the supplementalperformance demonstration guidelines of this section will have to be expanded tc address voltage measurement performance.)

Supplemental performance demonstration for NDE techniques and personnel should be performed on a common data set such as to allow overall NDE detection sizing

i 14 DG 1074 8/5/97 l

performance to be evaluated against actual flaw geometries. A written protocol for supplemental performance demonstration should be prepared by organizations (utilities or Vendors) performing the demonstration. The performance demonstration protocol for data l

acquisition and data analysis should conform to the EPRI guidelines (Reference X), Appendices G and H, as applicable, subject to the following guidelines:

a)

Separate data sets should be employed for each potential degradation mechanism identified in C.1.1. Extraneous signals (e g., denting, deposits, tube geometry changes, etc) should be included as part of the data sets for each degradation mechanism, as 1

applicable based on SG Inservice inspection experience. Note, where such extraneous signals are found to have a significant influence on the detection and/or sizing performance of an NDE technique, the NDE performance demonstrations should be performed to address these extraneous signals consistent with the degree to which these extraneous signals exist in the steam generators to be inspected.

b)

Data acquisition with the subject NDE technique should be conducted for the entire data set. Data analysis by individual analysts should be conducted for a portion of the total data set such that the analysts are not tested on identical data sets. The data acquisition and analysis should be blind tests, c)

The total and partial data sets for each degradation mechanism should contain a sufficient number of flawed and unflawed grading units to permit probability of detection (POD) performance, probability of false call (FCP) performance, and/or sizing performance to be evaluated at an appropriate level of confidence for the range of flaw sizes of interest (i.e., flaw sizes ranging from less than the repair criteria to sizes where the structural performance criteria would not be met).

d)

Each data set for a given degradation mechanism should consist of service degraded tube specimens (i.e., specimens removed from operating steam generators),

to the extent practical. Data acquisition with the subject NDE technique should take place prior to tube removal. Service degraded tube specimens may be supplemented as necessary by tube specimens containing flaws fabricated using mechanical or chemical methods provided it is firmly established in written documentation to be maintained as part of the supplemental performance demonstration record that signal responses are fully consistent with those in the field for the same flaw geometry. In particular, fabricated i'IEWs shNid exhibit signal responses of similar voltage amplitude and signal to noise as flaws in the fielJ with the same flaw geometry. For example, electric discharge machining (EDM) notches should not be used to represent stress corrosion cracks since EDM notches exhibit a higher voltage response than cracks with higher signal to noise.

e)

NDE technique and personnel flaw detection, false call, and sizing performance for each grading unit should be evaluated against the actual flaw geometry.

f)

Records of the supplemental performance demonstration should be maintained by the organization (e.g., vendor, utility) conducting the demonstration.

Documentation to be included as part of the technique supplemental performance

l l

15 DG-1074 8/5/97 demonstration records should include a complete description of the NDE technique (data acquisition equipment and instrumentation, data acquisition procedures, and data analysis l

procedures), including all essential variables and the demonstrated values of these variables, the data sets used (including a description thereof), and the results of the performance demonstration.

C.1.2.2 Use of NonNalidated NDE Techniques Non validated NDE techniques refers to techniques that have not been validated for a given application in accordance with C.1.2 of these guidelines.

Non validated techniques may be used to supplement the use of validated techniques. However, with respect to any additionalindications detected by the non-validated technique (i.e., not detected by the validated technique), technical justification must be developed as a basis for not repairing the affected tubes. The technicaljustification, to be maintained as part of the inspection record, must demonstrate that the additionalindications satisfy the applicable repair criteria.

Non-validated NDE techniques for flaw detection and/or sizing may be used for applications for which there are no available techniques which have been validated in accordance with C.1.2 of these guidelines, provided the techniques are qualified for detection in accordance with the EPRI Steam Generator Examination Guidelines, Revision [XJ, Section 7 and Appendix H. A comparative evaluation should be performed for available non-validated techniques and the best of these techniques in terms of detection and sizing performance for that degradation mechanism should be employed. This comparative evaluation should be documented as part of the inspection record. POD and sizing performance for such alternative techniques should be quantified based on available information from the field and the laboratory to assess the capabilities of these techniques to perform reliable detection and sizing of flaws associated with a given mechanism, to determine the most appropriate NDE technique for that application, and to identify needed improvements in NDE capabilities. POD performance should be assessed to ensure that the subject technique can reliably detect flaws before these flaws fail to meet the structural performance criteria of C.2.1.1 or before they may potentially leak under postulated accident conditions. The detection and sizing performance estimates should consider the potential decrement in performance if flaws of a given size in the field are exhibiting lower signal to noise than is implicit in the bulk of the available information. In the meantime, licensees should take action to develop a validated technique in accordance with C.1.2. This action should be taken on an expedited basis in concert with other affected utilities and/or industry organizations.

When no validated NDE technique for flaw sizing exists for a given application (flaw mechanism), allindications found which are potentially associated with that degradation mechanism should be considered to exceed the applicable plugging criteria.

NDE personnel should undergo training, written examination, and performance demonstration consistent with the guidelines of the EPRI Steam Generator Examination Guidelines, Revision [XJ, Section 6.2 or Appendix G, prior to the use of a non-validated NDE

16 DG-1074 8/5/97 technique for a given application, to the extent practical. The major practicality consideration is the availability of an appropriate, statistically significant data set for performance demonstration.

For some degradation mechanisms, such as various stress corrosion cracking mechanisms, there may be no available techniques that have been validated for sizing in accordance with C.1.2 of these guidelines. Nevertheless, information on actual sizing performance demonstrated as part of the supplemental performance demonstration of this section can be a useful tool for facilitating the condition monitoring and operational assessments in C.3 and C.4, respectively. For example, in cases where depth sizing performance is very poor, it may be possible to demonstrate that flaws at or near 100%

through wall can reliably identified. This kind of information can be useful for performing condition monitoring and operating assessments on tube leakage integrity. Additionally, in cases where depth sizing performance is poor, it will generally be possible to quantify length sizing performance. This kind of information can be useful for performing conservative condition monitoring assessments and operational assessments for tube structural and leakage integrity. Finally, in cases of poor depth sizing performance, it may be possible to demonstrate that NDE techniques and personnel are capable of reliably sorting out a subset of indications which have a high likelihood of containing the most limiting indications from structuralintegrity and leakage integrity point of view. The basis for sorting could be the indicated depth or voltage response of each indication. The identified subset of tubing may then be subjected to additional monitoring actions as discussed in C.3, such as in situ pressure testing, to confirm that the tube integrity performance criteria in C.2 are met.

C.1.3 Inspection Scope and Frequency C.1.3.1 Preservice Inspections The EPRI Steam Generator Examination Guidelines, Revision [XJ, provide acceptable guidance for conducting preservice inspections, subject to the following clarifications.

1)

Preservice inspection should be conducted over the full tube length.

2)

This inspection should be performed after the field hydrostatic test and prior to initial power operation.

C.1.3.2 Frequency of inservice Inspections The EPRI Steam Generator Examination Guidelines, Revision [XJ, Section 3.2, provide acceptable guidelines concerning the frequency of inservice inspection for each steam generator subject to the additional guidance of this section below [and subject to the resolution of the aforementioned NRC staff comments concoming the EPRI guidelines].

Inservice inspection of each steam generator should be performed at the first refueling outage (a duration not less than 6 EFPM and not more than 24 EFPM). Subsequent inservice inspections of each steam generator should be performed at a frequency as needed such that

17 DG-1074 8/5/97 l

operational assessment in accordance with C.4 demonstrates that tube integrity performance l

criteria in C.2 will continue to be met prior to the next scheduled inspection of that steam generator. No steam generator should operate more than two fuel cycles between inservice I

inspections. Inservice inspections (unscheduled) should also be performed during plant shutdown subsequent to any of the following conditions:

1) primary-to secondary leakage leading to plant shutdown for repair of the leaking tube (s); applicable only to leaks involving tube, plug, or sleeve flaws or sleeve to-tube welds 2) seismic occurrence greater than the Operating Basis Earthquake 3) loss-of coolant accident requiring actuation of the engineered safeguards 4) main steam line or feedwater line break C.1.3 3 Initial inspection Sample for Inservice Inspections l

The initial inspection sample size and selection should be in accordance with the EPRI Steam Generator Examination Guidelines, Revision IXJ, Section 3.3, subject to the additional guidelines of this section [and subject to resolution of the aforemontioned NRC staff comments concerning the EPRl guidelinesJ. The initial tube for inservice inspection, scheduled and unscheduled, should include a minimum 20% random sample of the total number of steam generator tubes which remain in service (i.e., tubes which have not been plugged). This sample should be divided equally among all steam generators being inspected during a given plant outage. The initial inspection sample should be over the full tube length (hot leg tube end to cold leg tube end) using appropriate NDE techniques and personnel as described in C.1.2.

The initial inspection sample in a steam generator should be supplemented to include tubes previously found to be degraded but left in service without repair, The number and identity of such tubes to be inspected should be 100% or, alternatively, as necessary to demonstrate by operational assessment in accordance with C.4 that the tube integrity performance criteria in C.2 will continue to be met prior to the next scheduled inspection of that steam generator. These supplementalinspections may be limited to a partiallength of the tube containing the previously observed indication provided the subject degradation mechanism can be shown to be limited to that partiallength. These supplementalinspections should use appropriate NDE techniques and personnel for the subject degradation mechanism as discussed in C.1.2.

In general, the above guidance for initial sampling applies also for unscheduled inspections caused by primary to-secondary leakage for the steam generator affected by the leak. However, if the degradation mechanism associated with the leak has been established to be confined to a " critical area"(per definition in C.1.3.4 below), the initial inspection sample may be limited to the defined region of the affected steam generator.

18 DG-1074 8/5/97 Indications found during the initial sample should be evaluated as necessary to establish the active degradation mechanisms present in the steam generators. The appearance of one or more new indications and/or indicated growth in pre-existing indications l

indicate active degradation mechanisms.

C.1.3.4 Expanded Inspection Sample l

For each active degradation mechanism identified during initial sampling, an expanded inspection sample should be performed. (For unscheduled inspections caused by primary to secondary leakage, an expanded inspection sample is only performed if non-leaking indications involving the subject degradation mechanism are found during the initial sample.)

The expanded sample should apply to the entire tube bundle of the affected steam generator unless the degradation mechanism can be demonstrated to be confined to a " critical area"in which case the expanded inspectinns for the subject degradation mechanism may be confined to a " defined region" consisting of the " critical area" and a surrounding " buffer zone". A " critical area"is a three dimensional region which can be demonstrated to bound the region where the subject degradation mechanism is active. Technicaljustification to support identification of a l

critical area should be maintained as part of the inspection record. Technicaljustification j

should either (1) address the uniqueness of essential contributing factors (for the subject i

degradation mechanism) to the critical area or (2) demonstrate that the indications found during initial sampling are of sufficient number and spacial distribution to provide a strong empirical basis for the critical area. The " buffer zone" should extend radially from the critical area such as to include a sufficient number of tubes to confirm that the critical area does in fact bound the region where the subject degradation mechanism is active. (Specific guidanco for defining the buffer zono should bo developod and includod in the forthcoming revision to the EPRI guidelinos such that it can be referenced in this regulatory guide.]

The size of the expanded sample (within the tube bundle or defined region, whichever is applicable) should be 100% or, alternatively, as necessary to demonstrate by operational assessment in accordance with C 4 that the tube integrity performance criteria in C.2 will continue to be met prior to the next scheduled inspection of that steam generator. The inspection should also be expanded into any uninspected steam generators, starting with a initial sample inspection in accordance with Section C.1.3.3. However, for each active degradation mechanism, this initial sample may be initially limited to defined regions which have been identified for the subject degradation mechanism.

The expanded inspection sample for each active degradation mechanism should be performed with appropriate NDE techniques and personnel for that mechanism as discussed in C.1.2 Where more sensitive and more accurate NDE techniques are being employed compared to previous inspections, additional inspections conducted with the previously used techniques may be used as a benchmark for determining flaw growth between inspections and the rate of new indications.

The inspection results for each active degradation mechanism should be evaluated to identify all defective tubes and to provide information (e.g., flaw sizes, flaw growth rates, rate of occurrence of new indications) as necessary to support the condition monitoring 1

19 DG 1074 8/5/97 assessment in C.3 and the operational assessment in C.4. " Defective" tubes are tubes containing flaws (as indicated by inservice inspection) which fall to satisfy the applicable repair criteria. The applicable repair criteria are addressed in C.S.1.

C.2 Performance Criteria Commensurate with Adequate Tube Integrity Condition monitoring assessments in accordance with C.3 and operational assessments in accordance with C.4 should meet the performance goals below which are commensurate with adequate tube integrity. Use of alternative performance criteria should be supported by a risk assessment in accordance with C.10 and are subject to NRC review and approval.

C.2.1 Structural Performance Criteria C.2.1.1 Deterministic Structural Performance Criteria All tubes should retain margins of safety against gross failure and/or rupture of the tubing which are consistent with the safety factor margins implicit in the stress limit -

=l criteria of the ASME Code, Section Ill,1989 edition and addenda through 1989, for all service levelloadings. These criteria include a margin of not less than 3 against burst (rupture) under normal operating conditions and a margin determined by the stress limits in NB-3225 of Section lli of the ASME Boiler and Pressure Vessel Code under postulated accidents concurrent with the safe shutdown earthquake (SSE).

C.2.1.2 Probabilistic Structural Performance Criteria Probabilistic criteria may be used as an alternative to the use of deterministic criteria as part of an SGDSM program for specific degradation mechanisms subject to demonstrating in accordance with C.10 that the use of such criteria for the intended application is consistent with maintaining risk an acceptably low level. These criteria should not exceed the following:

a)

The frequency of SG tube ruptures which occur as spontaneous, initiating events under normal operating conditions should not exceed 2.5X10-3 per reactor-year.

b)

The conditional probability of rupture of one or more tubes under postulated accident conditions should not exceed 2.5X10 2.

The above criteria apply to the total tube rupture frequency per plant and the total conditional probability of rupture associated with all degradation mechanisms affecting each steam generator. Frequency and conditional probability criteria applicable to any one degradation mechanism should not exceed 40% of the above values.

C.2.2 Operational Leakage Performance Criteria Operational primary-to-secondary leak rate should not exceed the primary to-

20 DG-1074 8/5/97 secondary leakage rate LCO limit for any one steam generator.

C.2.3 Accident Leakage Criteria Calculated potential primary to-secondary leak rate during postulated design basis accidents other than an SGTR should not exceed 1 gpm or, alternatively, what has been analyzed as part of the current licensing basis for purposes of demonstrating that 10 CFR 100 guideline limits for offsite doses, or some fraction thereof, and GDC-19 criteria for control room operator doses are met.

Any proposal to revise the current licensing basis to accommodate a larger leak rate during design basis accidents must be reviewed and approved by the NRC and may necessitate technical specification changes (see C9 for additional details). Such a proposal should include a radiological assessment in accordance with C.9 to demonstrate that the consequences of design basis accidents meet the 10 CFR 100 guideline limits for offsite doses, or some fraction thereof as appropriate to the accident, and GDC-19 criteria for control room operator doses. In addition, the risk implications of such a proposal should be assessed in accordance with C.10. Following NRC acceptance and approval, the description of the new accident and its consequences must be incorporated into the licensee's updated final safety analysis report (UFSAR).

Note that any change to the current licensing basis to accomodate a larger leak rate during design basis accidents is applicable to the specific degradation mechanism l

addressed by the supporting risk assessment. Any accident-induced leakage involving mechanisms not addressed in the supporting risk assessment must still be limited to the previous licensing basis leakage rate assumption until the risk assessment has been (1) updated to address these other mechanisms and (2) reviewed and approved by the NRC staff.

C.3.

Condition Monitoring Assessment The as found condition of tubing should be monitored during each tube inspection, whether scheduled or unscheduled, to confirm that tubes meet the performance criteria of C.2.

In addition, operational leakage should be monitored in accordance with C.8 to confirm that performance criterion C.2.2 is met. Should these performance criteria not be met, this should be reported to the NRC within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> and corrective actions should be implemented in accordance with C.6 prior to plant restart.

For an unscheduled inspection due to primary to-secondary leakage, the condition monitoring assessment need only address the degradation mechanism which caused the leak provided the interval between scheduled inspections are not lengthened. (However, it will be necessary to estimate the contribution of accident induced leakage from the other active degradation mechanisms, as determined from the most recent operational assessment for these mechanisms, to demonstrate that performance criteria for accident induced leak rate is met.)

Specific considerations relative to monitoring tube structural integrity, operational leakage I

4

21 DG-1074 8/5/97 integrity, and accident leakage integrity are presented in C.3.1, C.3.2, and C.3.3, respectively.

Additional details concerning specific topics in these sections are addressed in C.3.4. The condition monitoring assessment is subject to the reporting criteria in D.1 and D.2.

C.3.1 Structural Integrity l

Tube structural integrity may be monitored against either the deterministic criteria in C.3.1.1 or the probabilistic criteria in C.3.1.2 for each degradation mechanism.

C.3.1.1 Assessment Vis a Vis Deterministic Performance Criteria Tube structural integrity may be monitored against the deterministic criteria of C.2.1.1 by analysis, based on the results of inservice NDE inspection, or by alternative means (e.g., in situ pressure testing) for each degradation mechanism. Tube structuralintegrity may l

l be demonstrated by analysis for a given degradation mechanism provided the sizing performance of the NDE technique and personnel has been quantified in accordance with validation process of C.1.2. The analysis approach involves demonstrating that the most limiting flaws associated with each degradation mechanism, as determined from inservice inspection, do not exceed the appropriate " structural limit" for each degradation mechanism.

" Structural limit" refers to the calculated maximum allowable flaw size developed consistent with the safety factor performance criteria in C.2.1.1. The analysis should account for all significant uncertainties such that for a flaw measured by inservice NDE inspection to be at the structural limit, the flaw satisfies the performance criteria with a probability of 0.95 evaluated at 50%

confidence. Conservative bounding models/ assumptions should be employed to account for uncertainties not directly treated in the assessment.

Potential significant sources of uncertainty include NDE flaw size measurement error / variability, material property variability, and structural modeling uncertainties. Considerations for assessing NDE flaw size measurement error / variability is addressed in C.4.3.5. Structural models (i.e., models relating burst pressure to a flaw size parameter (s) or to an NDE indicated flaw size parameter (s)) may be empirical or analytical (i.e.,

idealized models based on engineering mechanics). Empirical models should be in accordance with C.3.4.2 and should quantify significant model uncertainties such as burst pressure data scatter and the parameter uncertainty of the empirical fit. Analytical models generally do not explicitly quantify uncertainties in the model estimates and, thus, should be developed to produce bounding estimates. The conservatism of analytical models should be confirmed by test.

For certain degradation mechanisms, analytical approaches to demonstrating tube integrity may be inappropriate or inefficient due to an inability to size certain flaw dimensions, large measurement error / variability of NDE sizing measurements, and/or large uncertainties of the structural models. These difficulties may necessitate bounding approaches to ensure a conservative analysis, but may lead to unrealistic (overly conservative) resuitsc Other approaches, such as in-situ pressure testing, may provide a more realistic assessment and may be used as an alternative to, or as a supplement to the above analytical approach for a given degradation mechanism to demonstrate structural integrity in accordance with the j

22 DG-1074 8/5/97 performance criteria of C.2.1.1. Guidance for in situ pressure testing to demonstrate the performance criteria are met is provided in C.3.4.3. In addition, accumulated data from in situ pressure testing, over time and from among different plants (using consistent NDE techniques),

may be used to develop empirical structural models and, thus, may provide an enhanced basis for condition monitoring by analysis. (Such empirical models, of course, would only be applicable to tubes with burst strengths less that the maximum pressure achieved during in-situ pressure testing.) Such empirical models are subject to the criteria of C.3.4.2. In addition, the variability of NDE flaw size measurements should be quantified in accordance with C.4.3.5.

C.3.1.2 Assessment Vis a Vis Probabilistic Performance Criteria Considerations for monitoring tube structural integrity against the probabilistic performance criteria of C.2.1.2 should include the following for a given degradation mechanism:

a)

Probabikstic approach should only be used in cases where inservice inspection techniques and personnel are validated for detection and sizing in accordance with C.1.2.

b)

Establish the as-found frequency distribution of indicated flaws at, e function of the relevant NDE indicated flaw size parameter (s) (e.g., indicated flaw depth, length, and/or voltage). The as-found distribution should be adjusted to consider the percentage of tubes sampled to address the subject degradation mechanism. The uncertainty of the as found frequency distribution is characterized by consideration of NDE flaw size measurement error / variability in accordance with C.4.3.5.

c)

Establish empirical models for burst pressure and/or failure load as a function of the relevant NDE flaw response parameter. These models for burst pressure and/or failure load should account for data scatter and model parameter uncertainties and should also satisfy criteria in C.3.4.2.

d)

The probability of burst calculation should account for variabilities / uncertainties in NDE flaw size measurement, material properties, and in the burst pressure / failure model with rigorous statistical analyses. Statistical sampling methods such as Monte Carlo may be used.

e)

The conditional probability estimate should be an expected (mean) value.

C.3.2 Operational Leakage Integrity Operational leakage integrity should be monitored during plant operation in accordance with C.8.1.

C.3.3 Accident Leakage Integrity The potential total primary-to-secondary leakage rate and the associated

23 DG-1074 8/5/97 radiological consequences for the most limiting postulated design basis accident should be assessed, based on the "as-found" condition of the SG tubing, to confirm that the performance criteria for accident induced leakage (Section C.2.3) were met immediately prior to the outage.

The potentialleak rate may be determined by analysis, based on the results of inservice NDE inspection, or by alternative measures (e.g., in-situ pressure testing). The potentialleak rate may be determined by analysis for a given degradation mechanism provided the sizing performance of the NDE technique and personnel has been quantified in accordance with the validation process of C.1.2. The pntential accident induced totalleak rate should be an upper 95% quantile estimate (one sided) evaluated at 50% confidence, based on quantitative l

consideration of uncertainties affecting the estimate. Conservative bounding models/ assumptions should be employed to account for uncertainties not directly treated in the assessment.

I Key elements of a condition monitoring accident leakage assessment by analysis should include the following for each degradation mechanism:

1)

Establish the as found frequency distribution of indicated flaws for each active flaw mechanism as a function of the relevant NDE indicated flaw size parameter (s) (i.e.,

indicated flaw depth, length, and/or voltage). The distribution should be adjusted statistically to consider the percentage of tubes sampled to address the subject degradation mechanism. The uncertainty of the as-found frequency distribution is represented by the uncertainty / variability of l

the NDE measurements. Treatment of NDE measurement uncertainty / variability is addressed in Section C.4.3.5.

2)

Establish the potential for an!.nagnitude of leakage as a function of the relevant flaw size parameter (s) (flaw depth and/or length) or the relevant NDE indicated flaw size parameter (s) (i.e., indicated flaw depth, indicated flaw len0th, or voltage response) for each flaw mechanism. The potential for leakage may be characterized as the probability that a given flaw (of given size or NDE indicated size) may leak under the postulated accident conditions (i.e., probability of leakage (POL)). Magnitude of leakage may be characterized as the conditional leak rate for the given flaw, given that leakage occurs. Models for evaluating POL and conditlanal leak rate may be analytical (i.e., idealized models based on engineering mechanics) or empirical. Analytical models generally do not explicitly quantify uncertainties in the model estimates and, thus, should be developed to produce bounding estimates. The conservatism of analytical models should be validated by test. Empirical models should conform to the guidance of Section C.3.4.2 and quantify significant uncertainties. Potential sources of uncertainty to be considered should include model parameter (model fit) uncertainties, uncertainties indicated by data scatter, and material property uncertainties.

3)

The leakage calculation for each flaw and/or for total SG leakage rate may be performed deterministically or probabilistically (e g., with statistical sampling methods such as Monte Carlo). The calculation should account for variabilities / uncertainties in NDE flaw size measurement error / variability, material properties, POL, and conditional leak rate model with rigorous statistical analyses.

In situ pressure testing in accordance with the guidelines in C.3.4.3 may be used

l 24 DG-1074 8/5/97 as part of, or as an alternative to condition monitoring by analysis for a given degradation mechanism. Data from in situ pressure testing may be used to develop empirical POL and I

conditionalleak rate models as a function of NDE indicated flaw size parameters and, thus, l

provide a basis for condition monitoring by analysis. Such empirical models are subject to the l

criteria of C.3.4.2. In addition, the variability of the measurement of the NDE flaw response parameter must be quantified in accordance with C.4.3.5. In the meantime, pending development of valid empirical models and quantification of NDE measurement variability, condition monitoring by in-situ pressure testing may be performed as an alternative to condition monitoring by analysis for a given degradation mechanism. Estimates of totalleak rate from the results of the in-situ tests should assume no functional relationship between leakage and the NDE flaw response parameter, unless there is sufficient data and a rigorous statistical basis for doing so in accordance with C.3.4.2. These estimates should be adjusted to reflect indications involving the subject degradation mechanism whbh were not subjected to the pressure tests, in addition, these estimates should reflect the percentage of tubes sampled by NDE to address the subject degradation mechanism. Assuming a sufficient number of tubes leak during testing, the totalleak rate estimate should be a bounding estimate with a probability of 0.95 evaluated at 50% confidence. Alternatively, an acceptable bounding approach for determining totalleak rate is to assume that POL equals the percentage of tubes that were pressure tested that exhibited leakage and that the conditional leak rate, given leakage occurs, is equal to the maximum leak rate observed among the leaking tubes. Totalleak rate may be assumed to equal zero if no leaking tubes are observed during in situ pressure testing.

C.3.4 Special Considerations for Condition Monitoring Assessment C.3.4.1 Loadings The following types of loadings should be considered:

a)

Loadings associated with normal plant operation, including startup, operation in the power range, hot standby, cool down, as well as all anticipated transients (e g., loss of electrical load, loss of off site power) that are included in the design specifications for the plant.

b)

Loadings and tube deformations imposed on the tube bundle during the most limiting postulated design basis accidents. Dynamic loading considerations should be included in the evaluation. All major hydrodynamic and flow-induced forces should be considered.

The combination of loading conditions for the postulated accident conditions should be evaluated in accordance with the licensing basis and should include, but nu necessarily be limited to, consideration of the following sources:

Pressure differentials associated with loss of secondary system pressure

l 25 DG 1074 l

8/5/97 l

Impulse loads due to rarefaction waves during blow down e

Loads due to fluid friction from mass fluid accelerations l

Loads due to centrifugal force on u bends caused by high e

velocity fluid motion e

Loads due to dynamic structural response of the steam generator components and supports Seismic loads Flow induced vibration during blow-down from main steam line break (MSLB)

C.3.4.2 Empirical Models C.3.43.1 Statistical Modeling Empirical models may be used to establish the relationship between a tube integrity parameter (e.g. burst pressure, probability of leakage (POL), conditional leak rate) and the appropriate flaw size parameter (e.g., depth, length, NDE voltage response).

Development of empirical models should conform to principles of good statistical practice for purposes of establishing the nominal correlation between the tube integrity parameter (typically the dependant variable) and the flaw size parameter (typically the independent variable) and for quantifying the uncertainties associated with the nominal correlation.

Empirical correlations should reflect a statistically significant set of data such that uncertainties associated with the correlation can be quantified. Ideally, the number of data should be relatively uniform over the range of flaw sizes of interest. In cases where the data set is relatively sparse over a portion of the flaw size range compared to another portion, standard statistical tests should be performed to ensure that the model parameters are not being unduly influenced by individual data in the sparsely populated portion of the flaw size range.

Empirical correlations should be a reasonable fit of the data as evidenced by " goodness-of fit" and residual analysis. Empirical models for burst pressure and conditional leak rate should explicitly account for data scatter and for model parameter (e.g.,

slope and intercept) uncertainties. Such models should involve a statistically significant correlation with flaw size (e.g., a linear regression fit of the data can be shown valid at the P =

0.05 level).~ Where such " significance of correlation" cannot be rigorously demonstrated for conditionalleak rate models, the regression fit of the leak rate data as a function of flaw size (or indicated flaw size) should be assumed to be a constant value. Empirical models for probability of leakage (POL) should explicitly account for parameter uncertainty. For POL models, a number of functional forms may exhibit similar " goodness of fit" attributes; however, they may lead to significantly different results for a given flaw size. Thus, the functional form of the fit

26 DG 1074 8/5/97 should be selected with care such as to ensure a conservative leakage assessment.

C.3.4.2.2 Test Specimens Test specimens should consist of pulled tube specimens as practicalin cases where the tube integrity parameter is being correlated with actual physical flaw size (e.g.,

flaw depth, flaw length). However, laboratory specimens (i.e., specimens with flaws induced in the laboratory by mechanical or chemical means simulating the degradation mechanism of interest) may be used in lieu of or to supplement pulled tube specimens in cases where the laboratory flaw can be expected to yield representative or conservative values of the tube integrity parameter for a given flaw size.

Tube specimens from the field should be included as part of the data base in cases where the tube integrity parameter is being correlated with an NDE flaw size response parameter (e.g., indicated _ depth, voltage amplitude). Field specimens may consist of pulled tube specimens or installed tubing which is tested in situ. In these cases, at least two field specimens from a given plant must be included as part of 'he data base before the correlation may be applied for that unit. In addition, two additional field specimens should be included in the data base for each plant after at least two but not more than three operating cycles have elapsed since the initial specimens were removed from the steam generators.

Installed tubing tested in situ may be substituted for the two additional pulled tube specimens.

Field specimens may be supplemented by laboratory specimens provided it can be demonstrated through standard statistical methods that the two data sets are producing consistent results, both in terms of the nominal correlation and in terms of the indicated uncertainties associated with the correlation.

__ Results from in situ pressure tests may be used to supplement or as an alternative to test data from pulled tube and laboratory specimens in cases where the tube integrity parameter is being correlated with an NDE indicated flaw size parameter. (At least two flawed specimens from pulled tubes from each plant where the correlation is to be applied must still be included in the data base, as discussed above.) Note that the in situ pressure test method has limitations with respect to the maximum test pressure that may be achieved and the maximum leak rate which may be sustained. Thus, care must be exercised to enst.re that these limitations do not lead to bias in the model. For purposes of establishing a burst pressure correlation, in-situ burst test data can be used without creating bias by considering data for NDE indicated flaw sizes above a threshold value. This threshold flaw size value is the minimum value beyond which burst was achieved for allin situ pressure tests. Below this threshold flaw size, the in situ pressure test results can be used to establish a lower bound correlation. For purposes of establishing a probability of leakage model as a function of NDE indicated flaw size, generally all of the in situ data can be used. For purposes of establishing a conditional leakage rate model, in-situ conditional leakage data may be used without creating bias by considering data for NDE indicated flaw sizes below a threshold value. The threshold flaw size value is the maximum value below which the maximum observed leak rate did not reach the maximum value which can be sustained (at the desired pressure) by the test facility.

Alternatively, in-situ conditionalleakage data may be considered over the full range of NDE indicated flaw sizes provided appropriate adjustments in accordance with C.3.4.2.2 are made to

I 27 DG 1074 8/5/97 leakage data for which the desired test pressure at the flaw could not be reached.

C.3.4.2.3 Testing Issues Laboratory test systems, including the test apparatus, instrumentation, and procedures, for measuring burst pressure and leak rate are subject to the requirements of 10 CFR 50, Appendix B," Quality Assurance." These systems should accommodate and permit measurement of as high a leak rate as may be practical, including leak rates which may be in the upper tail of the leak rate distribution for a given flaw size (e.g., length, voltage). The test systems should be evaluated for their accuracy, capabilities, and limitations as part of the test l

system qualification. The maximum and minimum measurable leak rates and the accuracy of l

the measured leak rates should be determined as a function of applied pressure. The maximum test pressure should be established as well as available pressurization rates and the ability to hold reasonably constant pressure as a function of time. Attention should be paid to functional limitations that might impair the nominal measuring ranges, such as when the order of magnitude of the flow resistance of piping connections becomes comparable to that of the degraded, leaking section of the tube. It is useful to know the applied pressure at the defect site as a function of leak rate when large leakage occurs. For example, the development or enlargement of through wall cracks during pressure testing can lead to large leak rates which l

prevent further pressurization. The pressure at the defect location could then be significantly less than the pressure at the supply location.

Application of a test system for a specific application (i.e., flaw type, orientation, and location along tube) should take into consideration actions necessary to produce a prototypic or conservative stress state at the flawed location in terms of the stress components which have a dominant effect on failure at that location. Consideration also should be given to the fact that primary membrane plus bending stress from sources other than the pressure differential across the tube (see Section C.3.4.1, " Loadings") may be present under the most limiting postulated accident plus SSE conditions. This may be dealt with by including these loads as part of the test or by increasing the test pressure as necessary to produce a conservative test.

Leak rate data should be collected at temperature for the differential pressure loadings associated with the limiting postulated accident. The test pressure should be adjusted relative to the accident pressure value to account for pressure measurement uncertainty. When it is not practical to perform hot temperature leak tests, room temperature leak rate testing may be performed as an alternative. However, the test pressure should be adjusted further as necessary to account for material property differences at temperature. In addition, thermal-hydraulic adjustments to the leakage data should be performed to reflect at temperature conditions.

Leakage tests where it is not possible to reach and maintain the desired test pressure due to leakage through the flaw in excess of test system capabilities should not be treated as invalid tests. To do so would systematically exclude high leakage data from the data base leading to a non-conservative bias in the empirical model. Additional testing and analysis of the test specimen should be performed as necessary to extrapolate the 1

28 DG-1074 8/5/97 expected leakage rate at the desired test pressure. One approach is to place a bladder over the leaking flaw and to pressuriia the specimen to the desired test pressure. A further adjustment to the test pressure may be necessary to acccant for strengthening of the test specimen provided by the bladder. (Strengthening effects of from 5 to 10% have been estimated in one industry report.) The bladder should then be removed and the specimen loaded to the maximum valid pressure for which a valid leak rate measurement can be attained.

This leak rate measurement should be used to extrapolate the leakage rate at the desired test pressure using an appropriate hydraulic model.

Burst testing may be performed at room temperature. Burst correlations and/or data should be adjusted as necessary to reflect material property values at temperature. Burst correlations and/or data should also be adjuwed as necessary to account for the strengthening effect provided by bladders when such bladders are used.

Additional guidance pertaining to the conduct of in-situ burst and leakage testing is addressed in C.3.4.3.

C.3.4.2.4 Data Management issues Each empirical model should be supported by a data management system which ensures data records cra maintained, that all relevant data have been considered in the development of the model, and that models are periodically updated as additional relevant data become available. In cases where an empirical model for a specific degradation mechanism is based on pulled tube and/or laboratory flaw data, the relevant data include all such data obtained for each plant and for the range of flaw sizes for which the empirical model e

will be applied. Available in-situ pressure tests results need not be included as part of the data bMe. However, such data should be evaluated to ensure that it is statistically consistent with the data from the pulled tube and/or laboratory flaw data. In cases where an empirical modelis based in part on in-situ pressure test reso'ts, all relevant in-situ data for the subject degradation mechanism obtained for each plant and for the range of flaw sizes for which the empirical model will be applied should be included as part of the data base. For empirical burst pressure models, the relevant in-situ data include all data above the " threshold daw size" discussed in C.3.4.7.2. Where the empirical burst pressure model is intended to be a lower bound model for flaw sizes less than the " threshold", the relevant in-situ data include all data regardless of flaw size. For empirical" probability of leakage" models, the relevant in-situ data include all data regardless of fisw size. For empirical conditional leak rate models, the relevant in-situ data include all data below the " threshold flaw size" discusced in C.3.4.2.2. Alter r Nely, the relevant in-situ data include all data regardless of flaw sia provided appropriate adjustments are made to leakage data in accordance with C.3.4.2.3 in cases where leakage exceeded the makeup capacity of the test system before the desired test pressure could be reached.

Valid reasons for excluding relevant data are limited to the following:

a)

Data are associated w..n an invalid test. Note, this criteria does not apply when tests are systematically invalid for the most extreme data. For example, failure to attain the desired test

29 DG-1074 8/5/97

. pressure due to excessive specimen leakage is a

" systematically" invalid test rather than " randomly" invalid test.

This is because test system limitations prevent leakage measurements for specimens exhibiting relatively high leak rates. Exclusion of such data would tend to skew the correlation, b)

Data are associated with atypical morphology based on morphology criteria which are defined rigorously and applied to all data, and which can be unambiguously applied by an independent observer provided: (1) the model can be conservatively applied to flaws exhibiting the atypical morphology or (2) a separate model is developed to address flaws with the atypical morphology and NDE can reliably discriminate flaws exhibiting the atypical morphology. This l

criterion should not be applied when the supporting data base depends in part on in-situ pressure test results, i

c)

Exclusion of data results in conservatism associated with application of the affected correlation in terms of the calculated structural limit, probability of burst, and total accident-induced -

leak rate.

Statistical tests alone do not provide an adequate basis for determining a burst or leakage test to be invalid or for deleting data from the data base.

C.3.4.3 In-situ Pressure Tests The following guidelines for performing in-situ pressure tests apply when the test results are to be used as an integral part of the condition monitoring or operational assessment.

C.3.4.3.1 Methodology Section C.3,4.2.3 provides general guidance concerning the conduct of leakage and burst testing. This section supplements the guidance in Section C.3.4.2.3 as it applies to in-situ pressure tests, in-situ pressure testing refers to hydrostatic pressure tests performed on installed tubing in the field. The purpose of these tests is to demonstrate the subject tubes satisfy the structural and accident-induced leak rate performance criteria in C.2.

In-situ pressure testing, including the test apparatus, instrumentation, and procedures are subject to the requirements of 10 CFR 50, Appendix B, " Quality Assurance."

A structural assessment should be performed and maintained, or cited by reference, as part of the test record for each application (i.e., flaw mechanism and location) demonstrating that the test is capable of producing a stress state at the flawed section of tubing which is equivalent to, or a conservative bound of the actual stress stato during normal l

1

30 D3-1074 8/5/97 operation and postulated accident conditions multiplied by the appropriate factor of safety in accordance with C.2.1.1, Where the actuallimiting stress state includes bending stress (e.g.,

from loss-of coolant accidents (LOCA) or SSE), the corresponding test pressure should be adjusted as appropriate to reflect these stresses. The tests may be conducted at room temperature; however, the test pressures should be adjusted to account for tube material properties at the appropriate hot conditions. In addition, leak rate data should be adjusted as appropriate to reflect the ectual temperature during postulated accidents. The design of the test apparatus and test pressures must also consider any potential f;xidity between the tubes and tube support plates due to the buildup of corrosion products, as necessary, to ensure that the appf-priate stress state is produced by the test.

Leak rate testing should be conducted at a pressure differential simulating the most limiting postulated accident, subject to test pressure adjustments discussed above and in C.3.4.2.3. Should it not be possible to achieve the desired pressure level due to leakage through the flaw in excess of the makeup capacity of the test system, additional testing and analysis should be conducted in accordance with C.3.4.2.3 to determine the expected leak rate at the desired pressure level. Subsequent to leak rate testing, each subject tube should be tested at a pressure corresponding to the most limiting deterministic structural criterion to demonstrate adequate structural margin, subject to test pressure adjustments discussed above l

in C.3.4.2.3.

i l

C.3.4.3.2 Tube SNection

[ Guidelines for numoer and selection of tubes for hydrostatic pressure testing are under development by the industry. The staff will review these guidelines for possible endorsement by this regulatory guide.]

l The sample size and selection of tubes for in-situ pressure testing should be such as to ensure that the most limiting tubes from a structural and accident-induced leakage integrity standpoint are included in the sample. Tube selection should be based on consideration the inservice NDE inspection results in terms of the indicated depth, length, and/or voltage response of the tubing. The size of the sample should be determined on the basis of the NDE sizing performance as demonstrated during the NDE validation such that there is reasonable assurance that the most limiting tubes are included in the sample. In cases where NDE sizing performance has not been validated, the initial sample size should be at least 10 tubes assuming there are at least 10 tubes identified as being degraded from this mechanism. A second sample consisting of the second ten potentially most limiting tubes (assuming there are at least an additional 10 degraded tubes involving this mechanism) should also be tested to confirm that the most limiting tubes from a burst and leakage standpoint were inciuced in the first sample. If not confirmed by the second sample, a third and if necessary ubsequent samples should be tested until there is reasonable assurance that the most limiting tubes have been tested.

C.4.0 Operational Assessment An operational assessment should be performed to demonstrate that the performance

31 DG 1074 8/5/97 criteria of C.2 will continue to be met until the next scheduled steam generator inservice inspection. The length of the operating cycle prior to the next scheduled inspection and the tube repair criteria should be adjusted as necessary to meet this objective. Additional corrective actions in accordance with C.6 should also be performed as necessary to meet this objective. The operational assessment and implementation of the resulting corrective actions should be fully completed within 90 days following plant restart from an inspection outage.

However, it will generally be necessary to perform at least a preliminary assessment prior to performing tube plugging and/or repairs to ensure that the repair criteria being implemented are sufficient to support operation for the planned operating interval preceding the next scheduled steam generator inspection.

For an unscheduled inspection due to primary-to-secondary leakage, the operational assessment need only address the degradation mechanism which caused the leak provided the scheduled interval between scheduled inspections remains unchanged and provided the leakage was not due to a factor that would affect prior operational assessments performed for the other degradation mechanisms.

Specific considerations for performing an operational assessment of tube structural integrity and accident leakage integrity are provided in C.4.1 and C.4.2, respectively. The performance criteria in C.2.2 for operational leakage integrity does not apply to the operational assessment of this section. Additional details concerning specific topics in these sections are addressed in C.4.3.

C.4.1 StructuralIntegrity l

C.4.1.1 Assessment Vis-a-Vis Deterministic Performance Criteria Reasonable assurance that tube structural integrity will continue to be adequately maintained is established by demonstrating that the projected condition of the most t

limiting tubes immediately prior to the next scheduled inspection satisfies the deterministic criteria of C.2.1.1 for each degradation mechanism. Conceptually, this involves demonstrating that the projected limiting flaw sizes do not exceed the appropriate "structurallimit"(previously defined in C 3.1.1) for each degradation mechanism. Equivalently, this can involve demonstrating that the projected limiting flaws for each degradation mechanism will exhibit failure load capacities consistent with the criteria of C.2.1.1. The assessment methodology should account for all significant uncertainties such that should the most limiting projected flaw size be at the calculated structural limit immediately prior to the next scheduled inspection, the flaw satisfies the performance criteria with a probability of 0.95 evaluated at 95% confidence.

The assessment methodology may performed deterministically or probabilistically (e.g., with statistical sampling methods such as Monte Carlo). Conservative bounding models/ assumptions should be employed to account for uncertainties not directly treated in the assessment.

Potential significant sources of uncertainty include uncertainties associated with the projected limiting flaw size, material property variability, and structural model uncertainties. General considerations for projecting the most limiting flaw sizes associated with 9

32 DG-1074 8/5/97 each degradation mechanism, including potential significant sources of uncertainty / variability, include the following:

a) the frequency distribution of detected indications left in service as a function of NDE indicated flaw size b) the frequency distribution of detected indications in each previous inspection as a function of NDE indicated flaw size for tubes which have not been repaired or plugged and were not inspected during the current inspection c) the frequency distribution of flaw growth rates determined in accordance with C.4.3.3 d) the rate and size distribution function of new indications as a function of time between inspections in accordance with C.4.3.4 e) the distribution of NDE sizing error / variability determined in accordance with C.4.3.5 l

f) the level of sampling performed during the current inspection and date of last inspection for uninspected tubes Note the above considerations for projecting the limiting flaw size are based on the premise that the flaw sizing performance of the NDE technique and personnel has been quantified in accordance with validation process in C.1.2 for the subject degradation mechanism. Where this is not the case, alternative and/or bounding approaches must be taken as discussed later in this Section.

Specific details for projecting the maximum flaw size are to be developed by licensees. The performance of the predictive methodology in projecting the maximum flaw size should be evaluated based on the results of future inservice inspections and appropriate adjustments made to the methodology as necessary to ensure this objective is met.

Structural models (i.e., models relating burst pressure to a flaw size parameter (s) or to an NDE flaw parameter (s)) may be empirical or analytical (i.e., idealized models based on engineering mechanics). Empirical models should be in accordance with C 3.4.2 and should quantify significant model uncertainties such as burst pressure data scatter and the parameter uncertainty of the empirical fit. Analytical models generally do not explicitly quantify uncertainties in the model estimates and, thus, should be developed to produce bounding estimates. The conservatism of analytical models should be confirmed by test.

For certain degradation mechanisms, operational assessment methodologies may be inefficient due to an inability to size certain flaw dimensions, large measurement error / variability of NDE sizing measurements, and/or large uncertainties of the structural models. These difficulties may necessitate bounding approaches to ensure a conservative 9

33 DG-1074 8/5/97 analysis, Appropriate benchmarking of the assessment against the results of in-situ pressure tests performed during condition monitoring provide a potential means for mitigating excessive conservatism. However, the davelopment of NDF. techniques with good POD and sizing performance and more precise structural models is key to ensuring a realistic operational assessment and avoiding unnecessary corrective actions (including operational restrictions).

C.4.1.2 Assessment Vis a Vis Probabilistic Performance Criteria Considerations for performing the operational assessment against the probabilistic performance criteria of C.2.1.2 for structuralintegrity should include the following for a given degradation mechanism:

a)

Probabilistic approach should only be used in cases where inservice inspection techniques and personnel are validated for detection and sizing in accordance with C.1.2.

b)

Calculate the frequency distribution of flaws by size projected to exist immediately prior to next scheduled inspection based on the considerations identified in C.4.1.2. Specific details for projecting the distribution of flaw sizes are to be developed by licensees. The performance of the predictive methodology in projecting a distribution which results in a conservative estimate of conditional probability of rupture should be evaluated based on the results of future inservice inspections and appropriate adjustments made to the i

methodology as necessary to ensure this objective is met.

c)

Establish empirical burst pressure and/or failure load as a function of the relevant NDE flaw response parameter. These empirical models should account for data scatter and model parameter uncertainties and are subject to the special considerations in C.3.4.

d)

The projected distribution of flaw sires and conditional probability calculation should include a rigorous statistical treatment of all significant sources of uncertainty / variability affecting the calculation including growth rate, NDE sizing measurement, and burst pressure / failure model. Statistical sampling methods such as Monte Carlo may be used.

e)

The conditional probability of rupture should be evaluated at the one sided, upper 95% confidence level.

b.

Accident Leakage Integrity The potential total SG primary-to-secondary leak rate and the associated radiological consequences during the most limiting postulated design basis accident should be assessed relative to the performance criteria for accident-induced leakage integrity in C.2.3, based on the frequency distribution of flaw indications as a function of NDE indicated flaw size projected to occur immediately prior to the next scheduled SG inspection outage. This may be accomplished by demonstrating that the potential accident-induced total leak rate does not

34 DG-1074 8/5/97 exceed the normal charging pump capacity of the primary coolant system and that the associated radiological consequences, calculated in accordance with C.9, do not exceed 10 CFR Part 100 guidelines for offsite doses, or some fraction thereof, and are in accordance with GDC 19 for control room operator doses. The potential accident induced total leak rate should be an upper 95% quantile estimate (one sided) evaluated at 95% confidence, based on quantitative consideration of uncertainties affecting the estimate. Conservative bounding models/ assumptions should be employed to account for uncertainties not directly treated in the assessment.

Conservative bounding models/ assumptions should be employed to account for uncertainties not directly treated in the assessment.

General considerations for projecting the flaw size frequency distribution for each degradation mechanism as a function of NDE indicated flaw size, including potential significant sources of uncertainty / variability, are the same as those identified in C.4.1.1 for projecting the most limiting flaw sizes. Considerations for establishing the potential for and magnitude of l

leakage for each degradation mechanism as a function of flaw size or NDE indicated flaw size are the same as those identified in C.3.3.

For certain degradation mechanisms, operational assessment methodologies may be inefficient due to an inability to size certain flaw dimensions, large measurement error / variability of NDE sizing measurements, and/or large uncertainties of the structural models. These difficulties may necessitate bounding approaches to ensure a conservative analysis. Appropriate benchmarking of the assessment against the results of in-situ pressure tests performed during condition monitoring provide a potential means for mitigating excessive conservatism. However, tr.a development of NDE techniques with good POD and sizing performance and more precise structural models is key to ensuring a realistic operational assessment and avoiding unnecessary corrective actions (including operational restrictions).

C.4.3 Special Considerations for Operational Assessment C.4.3.1 Loadings See C.3.4.1 C.4.3.2 Empirical Models See C.3.4.2 C.4.3.2 Flaw Growth Rates Flaw growth rates over the next inspection interval must be estimated for each degradation mechanism for purposes of projecting flaw size or flaw size distributions expected to exist prior to the next scheduled inspection. These projected flaw sizes or flaw size distributions are used as part of operational assessments performed in accordance with C.4.

Where possible, these growth rate estimates should be based on the inservice inspection

35 DG-1074 8/5/97 results from the most recent inspection and the previous one or two inspections. The inservice inspection results may be used where the NDE techriiques and personnel used to obtain these results were validated for sizing in accordance with C.1.2. When non-validated techniques and personnel have been employed, the inspection results may still be used for purposes of assessing growth rates provided it has been demonstrated during the validation process that there is a statistically valid correlation between the actual flaw size or burst strength and the NDE measured flaw size. Where the NDE technique does not satisfy these provisions, indications found during a given inspection will generally be "new indications" since indications found in previous inspections will have been plugged or repaired in accordance with C.1.2.2.

Under these circumstances, the projected flaw size distribution prior to the next scheduled inspection will be determined primarily on the basis of the observed " rate and size of new indications"(see C.4.3.4) rather than on the basis of observed growth rates.

Flaw growth rates should be evaluated on the basis of the change in flaw size between inspections where there is a detectable flaw indication during both inspections (Growth implications of new indications are addressed in C.4.3.4). These growth rates should be adjusted as necessary to reflect any increase or decrease in the length of the time interval l

between scheduled inservice inspections. For a given indication found during the latest inspection, the previous inspection results for the subject location should be evaluated, consistent with the NDE data analysis guidelines for the degradation mechanism being l

i evaluated. Where the data analysis guidelines employed during the previous inspection differ from those employed during the latest inspection, the previous data should be evaluated to the latest data analysis guidelines. In addition, the previous data should be adjusted to compensate for differences in data acquisition procedures to the extent there is a technical basis for doing so. When this is not possible, the locations of the indications (or a large sample of these locations) should be reinspected using the previous data acquisition procedures such that results can be compared directly to the previous inspection results. It is desirable that the same analyst be used for a given location to evaluate the data from the latest and previous inspections for purposes of assessing incremental flaw growth.

It is acceptable to supplement plant specific growth data with applicable data from other units in cases where plant-specific data is scarce for a given degradation mechanism. The data applied from other units should be consistent with or conservative with respect to available plant-specific data regarding average and bounding growth rates. Other considerations conceming the applicability of data from other plants include, for inside diameter degradation, similarities in inconel microstructure, primary water chemistry, relevant design features (e.g., residual stress levels associated with tube expansions and u-bends, sleeve design), level of denting, and operating temperature. Other considerations for outer diameter corrosion include similarities in secondary water chemistry, crevice chemistry, thermal and hydraulic environment, Inconel microstructure, level of denting, and relevant design features.

It is acceptable to use a statistical model fit of the observed growth rate distribution to support operational assessments provided that the statistical model accounts for the upper tail of the observed distribution.

When statistical sampling techniques are applied to the growth rate 1

J'

36 DG-1074 3/5/97 distribution, negative growth rate samples should be treated as zero growth rate.

Probability distributions of flaw growth rates constructed directly from comparative inspection results will tend to be contaminated by NDE flaw measurement repeatability error which will tend to extend the tails of the distribution in both directions. It is conservative to ignore this contamination where the measurement error is random.

Alternatively, approprid.e statistical methods may be employed to separate out the contribution of measurement error. However, the deconvolved distribution attributable to rnoasurement error should be evaluated to ensure that it is consistent and fully accounted for in what is being assumed for NDE measurement error in C.4.3.5 below.

C.4.3.4 Rate and Size of New Indications The frequency distribution of indications as a function of indicated flaw size projected to exist prior to the next inspection consists of two groups of indications. The first group consists of flaws found by inservice inspection that were permitted to remain in service prior to plant restart and which have subsequently undergone flaw growth. Thus, the projected frequency distribution of indications associated with this first group can be determined from the known distribution of indications left in service and the known distribution of flaw growth rates (see C.4.c.(3)). The second group consists of indications that were not detected by inservice inspection prior to plant restart. The indications were not detected previously because either (1) flaws were present but not detected by inservice inspection, or (2) flaws did not initiate until i

after plant restart. Failure of inservice inspection to detect flaws that were present can be due i

either to the fact that (1) the subject tube was not inspected at the flaw location or that (2) the tube was inspected, but the flaw was not detected due to NDE technique or personnel limitations. Methodologies should be developed for each degradation mechanism for projecting the frequency distribution of indications associated with the second group of indications (i.e.,

indications not detected during previous inspections). Predictions using these methodologies should be assessed versus the actual distribution of new indications found at the next inspection. These methodologies should be revised as necessary, based on the results of the comparative assessment.

The projected rate and size distribution of new indications may be determined, in part, on the basis of the inservice inspection results. This is contingent in the case of the size distribution on the NDE technique satisfying the same provisions as identified in C.4.3.3 for determining flaw growth rate. The projected rate of new indications should account for the anticipated rate of increase in the rate of new indications over time based on plant-specific and applicable industry experience. The previously observed size distribution of new indications may be fitted with a statistical model which conservatively accounts for the upper tail of the distribution such that the distribution may be scaled to reflect the expected number of new indications.

In cases where the NDE technique does not satisfy the provisions in C.4.3.3, alternative approaches may be taken for purposes of projecting the most limiting sizes of new indications for purposes of supporting a conservative or bounding operational assessment. For example, burst test results of in-situ pressure tests performed as part of condition monitoring b

37 DG-1074 8/5/97 may be used to estimate flaw sizes equivalent to the observed burst pressures or to conservatively bound the flaw sizes based on the maximum test pressures achieved where no burst was observed. The projected bounding values of flaw size should be adjusted as appropriate to reflect the projected increase in rate of new indications (which would tend to stretch the upper tail of the size distribution to higher values) and to account for increases or decreases in the length of the time interval between scheduled inservice inspections.

5)

NDE Sizing Error The probability distribution of NDE measurement error may be determined from the performance demonstration data for NDE techniques and personnel obtained during the validation process for sizing in accordance with C.1.2.0 and C.1.2.1. Consideration should be given to whether personnel measurement uncertainty can be reduced with the practice of reviewing field data with independent analysts. Whether this can in fact lead to a reduction in measurement uncertainty would need to be demonstrated for each application (i.e., for each set of degradation mechanisms, NDE technique, data analysis procedures, and procedures relating to how the independent analyses are performed and discrepancies resolved).

C.5 Tube Plugging and Repairs All tubes found to be defective during preservice or inservice inspection should be removed from service by plugging or repaired prior to plant startup. Tubes are defective when they contain flaws which fail to satisfy the applicable tube repair criteria for the subject degradation mechanism. Guidelines for the development of tube repair criteria are given in C.S.1 below. Guidelines concerning the development of plugging and repair methodologies are given in C.S.2 below.

C.S.1 Tube Repair Criteria The purpose of tube repair limits, in conjunction with the other programmatic elements of this regulatory guide, is to provide reasonable assurance that tubes accepted for continued service without repair will exhibit adequate tube structural and leakage integrity, consistent with the performance criteria of C.2, with appropriate allowance for NDE measurement error and for flaw growth prior to the next scheduled inspection.

The tube repair criteria for each active degradation mechanism should be 40% of the nominal tube wall thickness, subject to demonstrating by operational assessment in accordance with C.4 that the tube integrity performance criteria in C.2 will continue to be met prior to the next scheduled inspection of that steam generator. This 40% criterion is applicable to the maximum measured depth of the subject indication.

Alternative repair criteria (ARC) may be developed and implemented for specific degradation mechanisms as part of a steam generator degradation specific management (SGDSM) strategy. Implementation of SGDSM at a given plant for a given degradation mechanism is subject to demonstrating that risk will be maintained at an acceptably low level.

SGDSM constitutes an integrated approach consisting of an operational assessment

38 OG-1074 8/5/97 methodology in accordance with C.4, specific inservice inspection programs (with specified frequency and level of sampling, specified qualified / validated NDE techniques) cons; stent with C.1, and repair limit computational methods aimed at ensuring that the performance criteria for tube integrity in C.2 are met prior to the next scheduled inspection. The ARC associated with an SGDSM strategy may not be a fixed value, but may involve a computational method to be implemented as part of the operational assessment for determining an acceptable ARC value which is consistent with ensuring that the performance criteria for tube integrity are met prior to the next scheduled inspection. SGDSM strategies and their technical bases should be documented in a technical report that is referenced in the plant procedures as the methodology for implementing the associated ARC.

C.5.2 Tube Plugging and Repair Methods Plugging and repair methods should be developed, qualified, and implemented in accordance with the applicable provisions of the ASME Code and 10 CFR 50, Appendices A and B. These methods should be designed to ensure tube structural and leakage integrity, and should be qualified by both analytical and experimental programs. Repair methods may include leak limiting repair methods; however any potential leakage from these repairs during operational transients or postulated accidents should be included as part of the operability assessment of C.4. Plugs and repaired portions of tubing should be inspectable with I

appropriate NDE techniques and personnel as described in C.1.b. [EPRiis developing guidelines for developing and implementing sleeving repairs. The staff will review these EPRI guidelines when and if they become available and consider whether these guidelines should be referenced or endorsed as part of this regulatory guide.]

C.6 Corrective Actions Failure of condition monitoring to confirm that the performance criteria have been satisfied should lead to the following actions prior to plant restart from the inspection outage:

a) assessment of causal factors such as, for example:

new or unexpected degradation mechanism insufficient sample sizes for tube inspection o

unexpectedly high crack growth rates o

performance of NDE techniques and/or personnelis less than expected e

deficiencies in predictive methodology for condition maintenance assessment e

(e.g., inadequate treatment of uncertainties) b)

implementation of corrective actions, for example:

shortened inspection interval e

I

39 DG-1074 8/5/97 water chemistry enhancements e

chemical cleaning e

reduce hot leg temperature e

design modifications e

larger tube inspection samples e

improved inspection techniques (to enhance POD and sizing performance) e enhanced training of NDE personnel e

more restrictive tube repair (plugging) criteria e

enhanced monitoring of operationalleakage e

reduced coolant iodine activity limits e

enhancements to predictive methodology for operational assessment e

Note, the adequacy of these corrective actions to provide reasonable assurance that tube structural and leakage integrity will be maintained prior to the next scheduled inspection should be confirmed as part of the operational assessment in accordance with C.4. A reduction in the length of operating time between inspections should be made if it cannot be shown with a high degree of confidence that other corrective actions are sufficient to ensure that the performance criteria in C.2 will be met for the period extending to the next scheduled inspection.

Irrespective of whether the condition monitoring assessment confirms that the tubes meet the performance criteria of C.2, actions should be taken as necessary such that the operational assessment confirms that the performance criteria will be satisfied throughout the operating cycle prior to the next scheduled inspection.

C.7 Preventive Measures Preventive measures should be developed and implemented to minimize the potential for tube degradation and to mitigate active degradation mechanisms in accordance with the guidelines given below. The effectiveness of these preventive measures, as indicated by inservice inspection results and other pertinent indicators, should be assessed as part of the periodic operational and condition monitoring assessments discussed in Sections C.3 and C.4, respectively.

C.7.1 Secondary Water Chemistry Program Licensees should have a program for monitoring and control of secondary water i

40 DG-1074 8/5/97 chemistry to inhibit secondary side corrosion induced degradation. This program should include:

1) identification of all critical variables, 2) identification of a sampling schedule for the critical variables and control points for these variables, 3) identification of the procedures used to measure the values of the critical variables, 4) identification of process sampling points, which should include monitoring the discharge of the condensate pumps for evidence of condenser in-leakage, 5) procedures for the recording and management of data, 6) procedures for defining corrective actions for all off-control point chemistry conditions, and 7) a procedure identifying (a) the authority responsible for the interpretation of the data, and (b) the sequence and timing of administrative actions required to initiate corrective action.

Development of the specifics of this program is the responsibility of the licensee.

However, licensees should consider the recommendations in Reference 1 when developing and/or updating their programs.

C.7.2 Loose Parts and Foreign Objects Licensees should have a program for monitoring and control of loose parts and foreign objects to inhibit fretting and wear degradation of the tubing as follows:

C.7.2,1 Secondary Side Visual inspections The program should include secondary side visualinspections. The program should define when such inspections are to be performed, the scope of inspection, and the inspection procedures and methodology to be utilized. Loose parts or foreign objects which are found should be removed from the steam generators, unless it is shown by evaluation (to be maintained as part of the inspection record) that these objects pose no potential for damaging the SG tubing or any other part of the secondary system. Tubes found to have visible damage should be inspected non-destructively and plugged or repaired if the tube repair criteria developed under Section C.5 of this guide are not satisfied.

C.7.2.2 Control of Loose Parts and Foreign Objects The program should include procedures effective in precluding the

41 DG-1074 8/5/97 introduction of loose parts or foreign objects into either the primary or secondary side of the steam generator whenever it is opened (e.g., for inspections, maintenance, repairs, and modifications). Such procedures should include (1) detailed accountability procedures for all tools and equipment used during an operation, (2) appropriate controls on foreign objects such as eyeglasses and film badges, (3) cleanliness requirements, and (4) accountability procedures for components and parts removed from the internals of major components (a.g., reassembly of cut and removed components).

C.7.3 Measures to Mitigate Active Degradation Mechanisms Licensees should consider developing and implementing, at their discretion, additional measures to mitigate active degradation mechanisms. Examples of such measures include providing for improved condenser integrity, minimizing air in-leakage into the secondary system, elimination of copper bearing alloys from the feed train, chemical cleaning, boric acid treatments, and operating with a reduced hot leg temperature.

C.8 Operational Primary-to-Secondary Leakage Monitoring / Limits C.8.1 Leakage Monitoring Primary-to-secondary leakage monitoring is an important defense-in-depth measure which can assist plant operators in monitoring overall tube integrity during operation.

Monitoring also gives operators information needed to safely respond to situations in which tube integrity becomes impaired and significant leakage or tube failure occurs.

Objectives: (1) Provide clear, accurate, and timely information indicating loss of tube leakage integrity to allow remedial actions to be taken to prevent tube rupture. (2) Provide clear, accurate, and timely information to facilitate the mitigation of any tube failure event.

Although leak-before-break cannot be totally relied upon for steam generator tubes, primary-to-secondary leakage monitoring can afford early detection and response to rapidly increasing leakage, thereby serving as an effective means for minimizing the incidence of steam generator tube ruptures. This can be achieved by having near real time leakage information available to control room operators. Use of such monitoring capability, along with appropriate alarm set points and corresponding action levels, can help operators respond appropriately to a developing situation in a timely manner.

The monitoring program should account for plant design, steam generator tube degradation, and previous leakage experience. Degradation and leakage experience should not be limited to a specific plant. A primary measure of program effectiveness rests with the ability of operators to approprir tely deal with the full range of primary-to-secondary tube leakage. The program should ensure that operators have the information and guidance needed to safely and appropriately respond to situations ranging from stable leakage at very low levels, to rapidly increasing leakage leading to or resulting from tube failure. Program elements which the staff believes will contribute to meeting the stated leakage monitoring objectives are discussed below. These elements have been shown to be important based on corrective

42 DG-1074 8/5/97 actions taken following tube leakage or rupture events.

C.8.1.1 Monitoring Strategy f

Each monitoring method has limitations, therefore, no single means of detecting primary-to-secondary leakage, nor a single monitored pathway <>r radionuclide should be relied upon. A monitoring strategy should use an array of methods to detect and measure leakage, and indications should be available to control room operators. Continuous control room display of key radiation monitor trends (e.g., blowdown, condenser exhaust, N-16 monitor leakage rates and change in leak rate over time) gives operators real-time inforrnation which can be used to safely respond to the full range of primary to-secondary leakage.

Although no single monitor should be expected to fulfill all monitoring roles, some monitoring methods have demonstrated particular value in certain situations. Use of Nitrogen 16 monitors installed on or near steam lines has become increasingly common in the industry as a supplemental means of monitoring leakage. These monitors exhibit short time response to changes in leak rate and are very useful to operators, provided their limitations are understood. Indications from these monitors can greatly aid operator ability to diagnose and combat a quickly escalating primary-to-secondary leakage situation. However, the short halflife for N-16 presents some problems in the ability of the detector to measure leak rate. Changes in power level, and characteristics of the leak itself (location and type of leak) will affect the N-16 concentration reaching the detector.

i Licensees should evaluate the monitoring methods available based on factors such as those given in guidance provided by EPRI Report TR-104788, "PWR Primary-to-Secondary Leak Guidelines," May 1995. Detection capability and measurement

{

uncertainties are discussed in the guidance, as well as the characteristics of certain monitoring methods. This is a useful basis upon which a licensee can determine the adequacy of specific parts of their monitoring system and the effectiveness of the combination of methods used.

The monitoring program should also include provisions for detection of primary-to-secondary leakage during low power or piant shutdown conditions. Licensees should ensure that means are available to detect tube leakage whenever primary pressure is greater than secondary system pressure. This includes hot shutdown conditions and plant startup situations, when normal means of detecting leakage might be limited or unavailable.

For instance, the radionuclide mix is altered following a period of plant shutdown so that condenser off gas monitor indications may be questionable during startup since they are calibrated for a specific radionuclide mix based on power operation. Also, N-16 monitoring is not considered reliable at low power since lower levels of N-16 are available to trigger detector response during a tube leak.

Shutdown or low power monitoring methods do not need to be relied upon to track low levels of leakage over extended periods as might be required for power operation.

Plants spend a relatively small fraction of time in low power or hot shutdown. However, it is prudent to have techniques and procedures available to detect a rapidly developing leak under these circumstances. In the event a tube failure develops, operators should have reasonable

43 DG 1074 8/5/97 time to respond to the situation before the pbnt reaches full power operation, when the consequences of a tube failure would be magnified.

Monitoring instrumentation alarms and operator action levels should be selected to ensure that operators can respond to leakage in a timely fashion, prior to developing serious tube failures. Refer to Section C.8.b of this Regulatory Guide for specific guidance.

C.8.1.2 Operational Guidance Clear guidelines should be available to direct operator response to leakage in order to minimize the chance for operator errors during a developing leak event. The EPRI Guidelines recommend operating actions in response to a range of primary-to-secondary leakage, methods of calculating leak rates from various secondary system sample points, and various strategies to track leakage once detected. The Action Levels given in the Guidelines provide a framework that licensees can use to formulate pre-planned operator actions based on specified leakage indications.

Licensees should be careful, however, not to retum too quickly to a more routine monitoring regime following an increase in leakage. The Guidelines give a definition of stable leak rate (s10% increase in an hour), but confirmation of indications of slowing Isak rate is not discussed. A firm basis, in terms of change in leak rate over time, upon which to determine the stability of the leak is difficult to formulate. Therefore, prudence dictates that operators should use more than a single indication as the basis for concluding that leak rates have stabilized. A similar approach, of confirming leak rates prior to declaring a leakage condition, is applied to Action Level 2 (i.e., leak rate requiring plant shutdown) in the Guidelines.

C.8.1.3 Operator Training Training scenarios should include various types of leakage progressions based on actual leakage events, as much as practicable. The characteristics of specific plant monitoring instrumentation should be considered when providing operator indications for training purposes.

The EPRI Guidelines offer some assistance to licensees in formulating appropriate simulator scenarios. However, licensees should ensure that information gained throughout the industry by operation with primary-to-secondary leakage or from tube failure events is used in training programs. Further, operator training should accurately reflect the expected indications and plant responses for the particular plant during a progressing tube leak that may develop into tube rupture. Various plant conditions and failures of various key indicators should be considered when devising training scenarios.

C.8.1.4 Program Updates and Self-assessment Means should be established for the leakage monitoring program to take advantage of new data. Information from actualleakage events can be used to check the adequacy of the monitoring program or enhance its effectiveness.

1

44 DG-1074 8/5/97 The foregoing leakage monitoring program components can afford a sufficient level of defense-in-depth against primary-to-secondary leakage. However, data from actual leakage events throughout the industry can serve as a valuable tool to help licensees verify that an appropriate balance exists among the program components. For example, licensees have incorporated leakage data from previous events to adjust alert and alarm set points of radiation monitors, improve chemistry sampling procedures, and supplement primary-to-secondary training scenarios.

Licensees should also have measures in place to allow careful evaluation of leakage monitoring program performance following any primary-to-secondary leakage event at their plant. Suitable adjustments in the monitoring program can then be made based on the results of such an evaluation.

C.8.2 Technical Specification LCO Leakage Limits 1)

The technical specifications should include an LCO limit with respect to the allowable primary to-secondary leakage rate through any one steam generator, beyond which prompt and controlled shutdown must be initiated.150 gallons per day (gpd) constitutes an acceptable LCO limit. Attematively, this limit should be established such that an axial crack which is leaking at a rate equal to the limit under normal operating conditions would be expected to satisfy the performance criteria for structural integrity in C.2.1.1. Predictive models, I

l including the treatment of uncertainties, for assessing structural integrity performance relative to I

the structural performance criteria should bo in accordance with C.3.1.1. Sources of uncertainty which should be considered include burst pressure and leak rate uncertainty / variability as a function of crack length and material property uncertainty / variability.

2)

The technical specifications should include, if necessary, an LCO limit with respect to the allowable total primary-to-secondary leak rate through all steam generatort,,

beyond which prompt and controlled shutdown must be initiated. (Such a limit is not necessary if its value would exceed the maximum totalleakage rate which is permitted by the LCC,

- leakage limit for individual steam generators.) This limit should be established such that total leakage in all steam generators equal to this limit under normal operating conditions would be expected to satisfy the performance criteria for accident-induced leakage integrity in C.2.3.

Predictive models, including the treatment of uncertainties, should be in accordance with item 1 above.

C.8.3 Procedural Limits on Operational Leakage Procedural limits for allowable leak rate and the allowable rate of increase in leak rate should be established to ensure that the performance criteria for operational leakage are not exceeded. These limits, when used in conjunction with a leak rate monitoring program in accordance with C.8.1, are intended to ensure that appropriate and timely action will be taken to ensure that leaking tubes, including tubes undergoing rapidly increasing leak rates, satisfy the performance criteria for operationalleakage in C.2.2. The Action Levels 1 and 2 criteria and Recommended Actions in the EPRI Primary-to-Secondary Leak Guidelines, Reference X, provide an acceptable approach with the exception that the >150 gallons per day (gpd) criterion

45 DG-1074 8/5/97 in these Action Levels may need to be revised consistent with the above objectives.

C.9 Radiological Assessment A radiological assessment in accordance with the guidance of this section is necessary to support any change to the performance criteria in C.2.3 for accident-induced-leakage.

The tube integrity performance criteria in C.2 are intended, in part, to ensure that the plant is maintained in a condition consistent with what has been analyzed as part of the design basis and current licensing basis. Consequences of postulated design basis accidents must be

.hown by these analyses to satisfy two conditions. First, the offsite consequences of accidents must not result in doses which would exceed the guideline doses of 10 CFR Part 100, or fraction thereof, as defined in Table C.9.1. Second, the accident must not result in releases which would cause the dose to control room operators to exceed the guidelines of GDC-19.

The consequences of these design basis accidents are,in part, functions of the dose equivalent 1311 in the primary coolant and of primary to-secondary leakage rates. Operational limits on these parameters are included in the plant technical specifications to ensure the plant i

is operated within its analyzed condition. A steam generator tube rupture (SGTR) event is l

among the design basis accidents analyzed as part of the licensing basis. This analysis assumes a bounding primary to secondary leakage rate during the event consistent with a double-ended rupture of a single tube. For other design basis accidents such as main steam line break (MSLB), the tubes are assumed to retain their structural integrity (i.e., they are assumed not to rupture). These analyses typically assume that the tubes will exhibit small l

leakage during the accident at a rate equal to the operational leakage limits in the plant technical specifications. However, limiting operational leakage to within the leakage limits in the technical specifications does not ensure that leakage will not exceed these limits during postulated accidents such as an MSLB.

The performance criteria for accident-induced leakage in C.2.3 is intended to be consistent with the primary-to-secondary leakage rate which has been analyzed as part of the licensing basis for the most limiting postulated accidents not involving an SGTR. Licensees demonstrate by condition monitoring in accordance with C.3 and operational assessment in accordance with C.4 that the condition of the tubing is being maintained such that the performance criteria for accident-induced leakage will be met during the most limiting postulated accident.

For many PWRs, a postulated MSLB is the limiting design basis accident not involving rupture of the tubing. The current licensing basis for many of these units considers a 1 gallon-per-minute leak rate concurrent with a design basis MSLB. Thus, the appropriate performance criteria for these units for accident-induced leakage is 1 gpm during a postulated MSLB. A higher value of this performance criterion may provide licensees with added operational flexibility as can be justified by operational assessment in accordance with C.4. This additional flexibility can take the form of implementing higher tube repair limits (as part of an SGDSM program in accordarice with C.S.1) or operating for an extended period of time between scheduled inspections. However, any change to the performance criterion must be

46 OG-1074 8/5/97 accompanied by an update to the design basis radiological dose analysis to consider a leak rate consistent with this criterion. This represents a change to the current licensing basis for the plant. Such a change would require NRC staff review and approval and may necessitate changes to the plant technical specifications.

For a certain vintage of plants, the current licensing basis (as reviewed and approved by the NRC in its safety evaluation report (SER) does not include a radiological assessment.

Instead, the reactors were given technical specifications for the maximum instantaneous activity level of dose equivalent "'I and a 48 hour5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> value of dose equivalent "'I in reactor coolant. In addition, a maximum activity level for dose equivalent "'I in the secondary coolant and a maximum primary to secondary leak rate were established in technical specifications. At the time that the SER was issued it was the NRC's position that the establishment of these technical specification limits would ensure that the doses resulting from accidents involving steam generators would pose no risk to public health and safety. The staff has concluded that this position remains valid today for plants in this category provided the potential for accident-induced leakage is maintained to within 1 gpm during postulated accidents other than an SGTR. However, the licensing basis would need to be upgraded, including radiological assessments, should licensees for plants in this category desire to employ an accident-induced leakage criterion above 1 gpm. Following NRC acceptance and approval, the description of the new accident and its consequences must be incorporated into the licensee's updated final safety analysis report (UFSAR).

Based upon the dose criteria presented in Table C.9-1, one accident scenario usually will be limiting. This scenario should be utilized in the calculation of doses and in the establishment of the plant specific technical specifications. This scenario willlikely remain the most limiting case until either the scenario or the conditions, associated with the scenario, change. When a new scenario is identified as being the limiting case, if this scenario does not fallinto one of the categories of presented in Table C.9-1, then a submittal is required to the NRC vehich identifies the accident, provides an assessment of the consequences of the accident, identifies the technical specification changes which are required as a result of the assessment and oroposes a limiting dose criteria for the accident.

C.9.1 Dose Calculation Methodology Licensees may select from one of two methodologies for purposes of performing a radiological assessment to support use of higher performance criteria for accident-induced leakage and to update the licensing basis accordingly. Both methodologies are deterministic in nature. The first method is referred to as the default or SRP approach. This methodology utilizes the concepts presented in Standard Review Plan (SRP) Sections 15.1.5, Steam System Piping Failures inside and Outside of Containment (PWR), 15.3.3-15.3.4, Reactor Coolant Pump Rotor Seizure and Reactor Coolant Pump Shaft Break,15.4.8, Spectrum of Rod Ejection Accidents (PWR), and 15.6.3, Radiological Consequences of Steam Generator Tube Failure (PWR). These methodologies may be utilized for calculating the doses resulting from a MSLB, locked rotor, rod ejection, and an SGTR accident, respectively. The second calculation methodology which may be utilized is referred to as the flex methodology. This methodology allows licensees to establish a plot of maximum allowable primary to secondary leak rate (i.e.,

47 DG-1074 8/5/97 the sum of accident induced leakage and nominal operating leakage) as a function of the maximum instantaneous RCS activity level of dose equivalent '3'l and the 48 hour5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> value of dose equivalent '*'l. These plots are based upon the limiting accident scenario. Based upon the projected event induced primary to secondary leakage for the next operating cycle (as determined by operational arsessment in accordance with C.4), licensees may choose to limit the maximum instantaneous RCS activity level of dose equivalent '2'l and the 48 hour5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> value of dose equivalent '8'l so that the accident leakage performance criterion can be met.

C.9.1.1 Default Methodology This methodology is presented in SRP Sections 15.1.5,15.3.3-15.3.4,15.4.8, and 15.6.3.

This methodology assumes that RCS dose equivalent 1311 and normal operating primary to secondary leakage are at the technical specification limits and that accident-induced leak rate is equal to the proposed performance criterion value. Licensees must demonstrate by these calculations that both GDC 19 and Part 100 dose guidelines or a fraction thereof, have been met.

The staff has identified a potential pitfallin the performance of these dose assessments.

This involves calculating the curie content in primary and secondary coolant using a mix of dose conversion factors in the calculation of dose equivalent ' 'I and the calculation of doses. Such an inconsistent application could result in either an underestimation or an overestimation of the dose consequences.

The activity level of dose equivalent '3'l is calculated using the following Equation:

DE '8'l = EDCF,C/DCF,3, where DE ' 'l =

the dose equivalent concentration of '8'l, Ci/g;

DCF, the dose conversion factor for isotope i, rem /Ci;

=

C, the concentration of isotope i in the primary coolant, pCi/g,

=

DCF,3, the dose conversion factor for ' 'l, rem /Ci.

=

The dose conversion factors which are to be utilized are based upon the plant specific technical specification definition of dose equivalent '2'l. Typical dose conversion factors are derived from either RG 1.4, RG 1.109 and ICRP 30. Some licensees may utilize the dose conversion factors from one source in the calculation of the RCS curie content of dose equivalent '3'l but then use a different source in the calculation of doses. Based upon the predominant isotope, '8'l, if the doses are calculated in this manner, then the doses could be incorrectly calculated by as much as 50%. The calculation of curie content in primary and secondary coolant should be based upon the technical specification definition of dose equivalent ' 'l.

9.2.2 Flex Methodology 1

_____j

48 DG-1074 8/5/97 In lieu of using the deiault methodology, the licensee may elect to utilize the dose calculation option which the staff has labeled flex. The intent of the flex methodology is to provide licensees with operational flexibility, yet ensure that the plant is operated within its analyzed licensing basis. The flex methodology is utilized to generate a plot of primary-to-secondary leakage rates as a function of primary coolant activity level of dose equivalent l.

This plot is generated based upon a series of calculations for a number of different accident scenarios in which the primary to secondary leak rates (i.e., the sum of the accident induced leakage and nominal operating leakage) vary with primary coolant activity level of dose equivalent '2'l. With such a plot, licensees are permitted an increase in the allowable accident-induced primary to secondary leakage provided the primary coolant activity level of dose equivalent '2'l is maintained below a pre-determined value. This plot is based upon the limiting accident scenario and conformance with the dose guidelines of Table C.9.1-1. Whichever accident scenario results in the least amount of allowable leakage would be the scenario for which the plot would be established. The plot would consist of two parts. The first would be for the maximum instantaneous value of dose equivalent l in RCS and the second would be for the 48 hour5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> value of dose equivalent '8'l in RCS. The plot would be plant specific and in the technical specifications. It is possible that one accident scenario may be limiting for the maximum instantaneous value of dose equivalent '8'l while a different scenario may be more limiting for the 48 hour5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> value.

The plot would relieve licensees of the burden of generating a technical specification change each outage when inspections identify increased degradation in their steam generators.

However, NRC approval would have to be obtained if a new or a different limiting accident were identified or the consequences of a previously analyzed accident changed or the assumptions, which were the basis for the plot, changed.

Under the default methodology, if operational assessment in accordance with C.4 reveals the performance criteria for accident induced leakage to be exceeded prior to the next scheduled SG inspection, the licensee must either take corrective action as necessary in accordance with C.6 such that the performance criteria is met or the licensee must update the licensing basis to accommodate a higher performance criteria which meets or exceeds the accident-induced leakage which may potentially occur prior to the next scheduled inspection.

Thus, NRC approval would be required prior to the licensee operating within a range outside the previously calculated and approved plot.

The following is an illustration of how the flex methodology might be applied to develop the plot:

The licensee will select a primary coolant activity level based upon the maximum allowable instantaneous value for dose equivalent '3'I. In addition, the technical specification value normal operating primary to secondary operating leakage will be assumed and an accident-induced leak rate will be assumed equal to that predicted by the operational assessment. Based upon these values, for each of the potential accidents, the licensee will calculate the control room operator, EAB and LPZ doses.

Using as an example the pre-existing spike case for a MSLB, the maximum allowable accident-induced primary-to-secondary leakage at the assumed RCS activity level for dose equivalent "'l is determined by multiplying the assumed total primary-to-secondary U

49 OG-1074 8/5/97 leakage rate times the ratio of the dose criteria for the accident case of interest to the maximum calculated dose at the location. A second primary coolant activity level value for dose equivalent l, smaller than the first, would be selected, the accident induced -

leakage assumed and a similar calculation performed. Again, the maximum allowable leakage value for the assumed coolant activity level value would be determined. This process would continue with a series of calculations performed for a number of coolant activity level values of dose equivalent l until the allowable leakage exceeded charging pump capacity. Then a plot would be made of maximum allowable primary to secondary leakage as a function of primary coolant activity level of dose equivalent ' 't. Maximum allowable leakage is limited to charging pump capacity. Primary coolant activity level of dose equivalent '8'l is limited to a maximum of 60 pCi/g.

The second step of the process would have the execution of a similar calculation but for the primary coolant activity level of dose equivalent '*'l at the 48 hour5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> technical specification value for dose equivalent l Again, taking the MSLB accident as a representative case, it would be assumed that a MSLB occurs co-incident with an accident initiated splke. The maximum allowed coolant activity level value for the 48 hour5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> value for dose equivalent '8'l, the technical specification value for normal operating primary to secondary leakage and an assumed accident-induced primary-to-secondary leak rate would be selected. Doses would be calculated at the EAB, LPZ and control room operator locations based upon the spike occurring following the accident. The maximum allowable primary-to-secondary leakage at the assumed primary coolant activity level for dose equivalent '8'l would be determined by multiplying the assumed total primary to secondary leakage rate times the ratio of the dose criteria for the case of interest to the maximum calculated dose for the location. A second smaller primary coolant activity level value for dose equivalent '*'l would be selected, an accident-induced primary-to-secondary leakage assumed and a similar calculation performed. Again, the maximum allowable leakage value for the assumed primary coolant activity level value would be determined. A series of calculations would be performed until, at a given primary coolant activity level, the allowable leakage exceeded charging pump capacity.

These data points would be utilized to generate the plot in the technical specifications for the maximum allowable primary to secondary leakage as a function of the 48 hour5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> value of dose equivalent '*'l. In no cases would the primary to secondary leakage rate be allowed to exceed the charging pump capacity. The primary coolant activity level of dose equivalent "'l is limited to a maximum of 1 pCilg.

Figures C.9.2-1 through C.9.2-3 provide examples of plots for three plants. These plots have been generated from actual amendment requests. These plots demonstrate that allowable leakage is plant specific.

With the flex option, licensees will also be required to perform dose assessments for the locked rotor, rod ejection, MSLB, and SGTR events as well as any other accident which is identified in which primary to secondary leakage impacts releases. The SRPs should be utilized in the performance of such assessments. The EAB, LPZ and control room operator doses would be compared to the dose guidelines of Table C.9-1. The SGTR assessments would be performed at the maximum allowed instantaneous value for dose equivalent ' 'I and

50 DG-1074 8/5/97 the maximum allowed 48 hour5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> value of dose equivalent l. Such an evaluation would be performed to ensure that the most limiting scenario obtained with respect to the determination of the maximum allowed technical specification values for dose equivalent '8'l and ncrmal operating primary to secondary leakage.

Utilization of the flex program incorporates most of the dose assessment methodology contained in SRPs 15.1.5,15.3.3-15.3.4,15.4.8, and 15.6.3. For the MSLB and the SGTR, the parameters which should be utilized in the flex option are shown in Table C.9-2. As noted from a review of this Table, adoption of the flex program requires some changes from the parameters and assumptions in SRPs 15.1,5 and 15.6.3. Such changes include:

1.

Limitation of the dose consequences based upon the accident rather than the case.

2.

Utilization of an iodine spiking factor of 500 for the MSLB and 335 for the SGTR for the accident initiated spike cases.

Whereas, the SRPs for the MSLB and SGTR accidents has the dose acceptance criteria a function of whether the event is an accident initiated spike case or a pre-existing spike case, the staff has established for the flex program the dose acceptance criteria to be a function of the accident, in the SRP approach, for the accident initiated spike case for either a SGTR or a MSLB, the acceptance criteria is 10% of Part 100 guidelines. For the pre-existing spike case for either the SGTR or the MSLB, the acceptance criteria is the full Part 100 guidelines. With the adoption of the flex program, the dose acceptance criteria is no :onger a function of the case but rather a function of the accident. For the MSLB it will be the full Part 100 values for the pre-existing spike case and well within Part 100 for the accident-initiated spike case. For the SGTR it wiil be 10% of Part 100 values.

The spiking factors which are to be utilized for the accident initiated spike cases are 335 for a SGTR and 500 for a MSLB. The value of 335 was obtained from release rate data collected by Adams and Atwood in a paper entitled,"The lodine Spike Release Rate During A Steam Generator Tube Rupture". The value of 500 is the same release rate as that presented in SRP Sections 15.1.5 and 15.6.3. This value remains unchanged because there exists no data on an iodine spike associated with a MSLB and the models which have been proposed do not justify a different value. Since there presently exists no basis for utilization of another value, the value of 500 will continue to be used for a MSLB.

With the selection of the flex option and based upon the determination of the accident-induced primary to secondary leakage rate, licensees will be able to determine, from the previously generated plot which has been incorporated into technical specifications, allowable RCS activity levels of maximum instantaneous dose equivalent '2'l and the 48 hour5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> value of dose equivalent ' 'l.

As noted previously the plot in technical specifications is good so long as a new or different accident need not be considered or a new release pathway need not be considered.

When such situations arise, if those situations result in a new limiting scenario, then an

51 DG-1074 8/5/97 assessment must be submitted to the NRC for review and approval and a new plot for the technical specifications must be developed and submitted for NRC approval.

4 9.2.3 Technical Specifications The STS and the improved STS (ISTS) contain specific values for the primary coolant maximum activity level of dose equivalent l, a 48 hour5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> value of dose equivalent '3'l and a maximum primary to secondary leak rate during normal operations. For those licensees which chose to utilize the default option for the calculation of doses, the existing STS and the ISTS are sufficient. Therefore, no change to their existing technical specifications would be necessary.

However, for those licensees which opt for the flex program, a change to their present technical specifications will be required. A plant which incorporates the flex program will contain in their technical specifications a figure which is a plot of total leakage, both normal operating and event induced leakage, as a function of the primary coolant activity level of dose equivalent '8'l. This figure will be utilized when degradation mechanisms began to appear and total primary to secondary leakage is projected to be greater than normal operating leakage.

Incorporation of this figure into the technical specifications will provide licensees the flexibility of operation to administratively limit themselves to either a lower accident-induced leakage rate (i.e., a lower performance criteria for accident-induced leakage), if the kel is degraded such that primary coolant activity levels are high, or to permit higher leakage rates if the primary coolant activity level is low due to fuel integrity being very good.

With respect to the technical specifications, Table C.9-3 presents the technical specifications required for the default case and for the flex program. The most limiting case for allowable leakage will also be the case which establishes the technical specification values.

_-.:._..____u

52 DG-1074 8/5/97 Table C.9-1 Dose Criteria for SG Accidents Default Methodology Thyroid Whole Body Accident EAB/LPZ Control RQQm EAB/LPZ Control RoQm MSLB

1. Pre-existing 300 30 25 5

Spike Case

2. Accident initiated 30 30 2.5 0.5 spike case SGTR

1. Pre-existing 300 30 25 5

Spike Case 2, Accident init-30 30 2.5 0.5 lated spike case Locked Rotor 30 30 2.5 30 Control Rod Ejection 75 30 6

30 Flex Methodology Thyroid Whole Body Accident EAB/LPZ Control EAB/LPZ Control Room Room MSLB 300' 30 25" 5

SGTR 30 30 2.5 0.5 Other Fuel Damage 300 30 25 5

Accident Locked Rotor 30 30 2.5 30 Control Rod Ejection 75 30 6

30

• 75 rem for the accident-initiated spike case

~ 6 rem for the accident-initiated spike case l

53 DG 1074 8/5/97 Table C.9-2 Parameters to Calculate Thyroid Doses Parameter Default /SRP Deterministic / Flex XQ Site Specific @95%

Site Specific @95%

/

Breathing RG 1.4 Value RG 1.4 Value Rate Dose RG 1.4, RG 1.109, ICRP 30 ICRP 30 Conversion Factor (DCF)

Reactor -

60 pCi/g pre-existing spike curve generated with a Coolant i pCl/g accident initiated spike maximum of 60 pCl/g for the Activity (RCS) pre-existing spike and 1 pCi/g for the acciden',

initiated spike l

- Spiking Factor 500 500 MSLB/ 335 SGTR Dose Limit (Thyroid)

MSLB 300 rem pre-existing spikel 30 300 rem pre-existing spike /75 rem accident initiated spike rem accident-initiated spike SGTR 300 rem pre-existing spikel 30 30 rem all cases rem accident initiated spike Maximum 1 gpm or 150 gpd per SG times Variable, function of limitations Allowable the number of SGs of 48 hour5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> TS value for dose Leakage equivalent *l and the maximum instantaneous value for dose equivalent *l in the RCS and the limiting dose exposure

. pathway and the limiting accident scenario.

54 DG-1074 8/5/97 Table C.9-3 Required Technical Specifications for Dose Assessment Portions of Steam Generator Rule Parameter Default Case Flex Case Maximum Activity Level Dose 60 Variable Equivalent '2'l, pCilg 48 hour5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> value Dose Equivalent 1

Variable

l, pCilg Normal Operating Leakage, 1 gpm or 150 150 gpd/SG Total gpd/SG Dose Conversion Factors for RG 1.4, ICRP ICRP 30 Defining Dose Equivalent *l 30, RG 1.109

' Allowable Leakage, Event NA Variable, function of product of Induced, gpm leakage and dose equivalent

• l activity level, limiting accident and scenario and charging pump capacity RCS Sampling Frequency Once per 4 Once per 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> following a 15% Power Change hours in 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />

Plant A TS Plot of Allowable Leakage Allowable Leakage, gpm 10,000 3

~ w =,

l

+-

w 1,000

=

~

5 L

. m,

~

x

-- x N m, _

~

10 i

e 1

O.1 1

10 100 RCS Activity DE l-131, uCi/gm Figure C.9.2-1

t1lII{\\l' 00 1

.w w

=

e

/g g

e;=.,

i a

C k

u a

+ -

1 e

x 3

L 1

0 I

1 e

~

t 2

n Bb l

e 2

~

l a

a 9

v t

w C

i u

o q

e nl m

l E

ru aA m

e g

s i

p x

o F

l f

g D

o Pt 3

e y

e 1

g t

o iv a

l i

k t

P a

c A

e S

L S

T e

C l

3-b R

a

~

w o

ll

~_

A 1

0 0

0 0

10 0

0 0

0, 0,

1 1

0 1

1 1

~

Plant C TS Plot of Allowable Leakage l

Allowable Leakage, gpm 100,000s j

N 10,000 x

1,000

~

~~ w

+-

10

%~e

- = m,-ww

- as s,

1 O.1 1

10 100 FICS Activity Dose Equivalent I-131, uCi/g Figure C.9.2-3

1 58 DG 1074 8/5/97 C.10.0 Risk Assessment General Design Criterion 14,

• Reactor Coolant Pressure Boundary," of Appendix A,

" General Design Criteria for Nuclear Power Plants," to 10 CFR Part 50 requires that the reactor coolant pressure boundary have an extremely low probability of abnormalleakage, of rapidly propagating failure, and of gross rupture. As a major portion of the reactor coolant pressure boundary, steam generator tubes must meet this requirement. Further, the steam generator tubes serve a unique dual role, functioning as reactor coolant and fission product containment boundaries. The containment function for tubes elevates their safety significance in the hierarchy of multiple fission product barriers, requiring that the tubes be capable of not only withstanding challenges assumed for other reactor coolant pressure boundary components, but also to provide protection from fission product release under conditions which could challenge reactor coolant pressure boundary integrity.

C.10.1 Approach:

The staff conducted an analysis of the potential risk related to induced steam generator tube rupture (ISTRG) at an example plant, using estimates of steam generator tube degradation. That analysis is documented in NUREG-1570 and INEL 95/0641. It indicated that ISTGR may be a dominant contributor to the frequency of large early releases of radioactive materials by severe accidents, and that the frequency may approach the surrogate safety goal for plants operating with degraded tubes. In some of the contributing accident sequences, core damage is caused by events that would be easily mitigated except for the complication of ISGTR. In other sequences, the physical conditions in the reactor coolant system during a sequence that is already causing core damage cause ISGTR, which substantially increases the amount of radioactive materials released by the accident. It is important to note that most of the contributing sequences are not currently included in the probabilistic risk assessments conducted by licensees to perform their Individual Plant Examinations.

While the results of the staffs example plant analysis were within the surrogate safety goal for large early release frequency, it showed that the results are sensitive to a number of plant-specific factors. However, evaluation of risk relative to the surrogate safety goal was not performed on a plant specific basis, The staffs example analysis was not capable of demonstrating that all plants would be within the safety goal as currently designed and operated. Further, the results indicate that changes to the current tube repair criteria could significantly alter the level of risk from ISGTR.

Regulatory Guide DG-1073, "An Approach to Plant Specific, Risk informed Decision Making: Induced Steam Generator Tube Rupture " describes the mechanisms by which steam generator tube rupture may be induced and the various accident sequences that should be included in a probabilistic risk assessment to address the risks associated with these mechanisms when requesting changes to the current licensing basis, Appendix A to DG-1073 specifically addresses requests for changes to the current licensing basis that may be associated with alternate tube repair criteria.

C.10.2 Risk Assessment Regulatory Positinn

59 DG-)074 8/5/97 Licenses should show that an acceptable level of total risk from induced tube failure is l

maintained with the adoption of alternate tube repair criteria defined in Section C.5.1 of this regulatory guide. Staff approval of alternate repair criteria is contingent upon asseptance of the risk assessment demonstrating that the resulting change to risk is acceptable. Guidelines for performing appropriate risk assessments and numerical guidance on the acceptability of results is contained in DG 1073.

l

60 DG 1074 8/5/97 D. REPORTS TO NRC D.1. Licensees should submit the complete results of the steam generator tube inservice inspection and condition monitoring assessment within 12 months following completion of each inservice inspection. This report should include:

1.

the number and extent (e.g., fulllength, hot leg only) of tubes subjected to inservice inspection and to any supplemental testing (e.g., in situ pressure testing) as part of the condition monitoring assessment.

2.

the location and measured size of each indication found by inservice inspection and the type of NDE test prob used (e.g., eddy current bobbin coil, eddy current rotating pancake coll). Measured size shall be in terms of parameters (e.g., flaw depth, flaw lenf a, and/or flaw voltage response) which can be directly compared to the applicable plugging limit for subject degradation mechanism. The orientation of the flaw (e.g., axial, circumferential) shall be provided in cases of linear type indications such as due to cracks.

3.

the results of any supplemental testing beyond inservice inspection performed as part of the condition monitoring assessment (e.g., in-situ pressure testing).

4.

identification of tubes plugged.

D.2.

Failure of the condition monitoring assessment to confirm that the performance criteria of C.2 have been met should be reported to the NRC within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. In addition, a special report should be submitted prior to restart consisting of the information listed in D.'i.a D.1.b, and D,1.d as it pertains to the specific degradation mechanisms for with the performance criteria were not met.

3.

Licensees should submit the analyses demonstrating risk for containment bypass as described in section C.10 and the implementation plans for any plant modifications deemed necessary based on the analysis results prior to the first plant restart following rule implementation.

.