ML20198E084
| ML20198E084 | |
| Person / Time | |
|---|---|
| Issue date: | 10/28/1998 |
| From: | Travers W NRC OFFICE OF THE EXECUTIVE DIRECTOR FOR OPERATIONS (EDO) |
| To: | |
| References | |
| SECY-98-248, SECY-98-248-01, SECY-98-248-1, SECY-98-248-R, NUDOCS 9812230337 | |
| Download: ML20198E084 (106) | |
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POLICY ISSUE d
(NEGATIVE CONSENT)
October 28.1998 SECY-98-248 yd FOR:
The C mmissioners FROM:
William D. Travers Executive Director for Operations
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SUBJECT:
PROPOSED GENERIC LETTER 98-XX " STEAM GENERATOR TUBE
[ l[j INTEGRITY" l
l PURPOSE:
f This paper informs the Commission of the staff's intent to delay the issuance for public comment i
of proposed Generic Letter 98-xx, " Steam Generator Tube Integrity," while the staff works with
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g the Nuclear Energy Institute (NEI) and the nuclear power industry to resolve concerns with the il J industry initiative entitled NEl 97-06, " Steam Generator Program Guidelines." It is the staff's 1 {(
objective to avoid having to issue a generic letter and instead to endorse the industry initiative as qij an acceptable approach to resolving current problems associated with steam generator (SG)
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l tube integrity. Nonetheless, the staff intends to release now for public comment the following J
three documents: (1) Draft Regulatory Guide DG-1074, Steam Generator Tube Integrity; (2)
Differing Professional Opinion (DPO) Consideration Document; and (3) Memorandum dated September 25,1998, to the Commission from Joram Hopenfeld, the DPO submitter.
BACKGROUND:
In COMSECY-97-013, the staff informed the Commission that it would (1) develop a generic letter containing model technical specifications (TSs) for SG tube surveillance and maintenance that requests licensees to address problems with current TSs; (2) develop guidance to support implementation of the generic letter model TSs; (3) give licensees the option to pursue alternate li SG tube repair criteria supported by an appropriate risk assessment; and (4) evaluate, as part of
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the individual plant examination followup program, plants that appear to have a higher potential l
j for core damage sequences that can challenge SG tubes. The staff also stated that the u
l proposed generic letter package being issued for public comment would contain an assessment f 0
- l of issues raised in a differing professional opinion (DPO) concerning SG tube integrity. In the l '
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CONTACT: Timothy A. Reed, DE/NRR i
1 415-1462 SECY NOTE:
In the absence of
't instructions to the contrary,
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223 7 981028 SECY will notify the staff on Friday, November 13, 1998 that
! j 99-248 R P,DR the Comn.ission, by negative consent, assents to the action proposed j
in this paper.
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The Commissioners staff requirements memorandum dated June 30,1997, the Commission approved the revised regulatory approach. The staff was committed to provide the proposed generic letter package to the Commission by September 30,1998.
DISCUSSION:
In support of this commitment, the staff developed a proposed generic letter that (1) informs pressurized-water reactor (PWR) licensees that plant TSs for maintaining SG tube integrity do not alone provide the needed assurance that SG tube integrity is being adequately monitored and maintained in accordance with NRC regulations and plant licensing bases; (2) advises licensees that they may request license amendments to their plant TSs to implement the model TSs attached to the generic letter for maintaining SG tube integrity, or justify alternate approaches for ensuring that SG tube integrity is monitored and maintained consistent with applicable regulatory requirements and plant licensing bases; and (3) requires that licensees submit to the NRC written responses that describe their ongoing or planned activities to monitor and maintain SG tube integrity consistent with NRC regulations and plant licensing bases, along with supporting safety bases for the plant-specific approaches. The staff also developed draft Regulatory Guide DG-1074, " Steam Generator Tube Integrity" (Attachment 1) and the DPO Consideration Document (Attachment 2). In support of issuance of the proposed generic letter for public comment, the staff has received endorsement from the Advisory Committee on Reactor Safeguards and met with the Committee To Review Generic Requirements in June and July 1998 to discuss the package.
By letter dated December 16,1997, the NRC staff was informed that the industry, through the NEl Nuclear Strategic issues Advisory Committee, had voted to adopt NEl 97-06. The chief objective of the industry initiative is for PWR licensees to evaluate their existing SG programs and, where necessary, to revise or strengthen program attributes to meet the intent of the NEl 97-06 guidelines. The NEl 97-06 guidelines are intended to improve both the quality and the consistency of SG programs throughout the industry. The NEl 97-06 initiative is a higher tiered document that commits PWR licensees to a programmatic approach conceptually similar to that recommended by DG-1074. NEl 97-06 references two types of lower tiered documents for guidance on the implementation of individual programmatic features: Electric Power Research Institute (EPRI) guidelines which are directive in nature (the licensee must meet the intent of directives), and EPRI guidelines which are non-directive in nature (may be used by the licensee as general guidance). The December 1997 NEl letter indicated that the NEl initiative would be implemented no later than the first refueling outage after January 1,1999.
Throughout the development of the proposed generic letter and its predecessor, the draft SG rule, as well as during plant-specific, ad hoc reviews, the staff and the industry have interacted extensive:y on the development of SG guidance. Both the staff and the industry have incorporated portions of each other's guidance into their respective guidance documents as part of this technicalinterchange. The focus of the technical interchange has been to identify where additional actions (beyond the minimum required by current TSs) are needed to ensure SG tube integrity consistent with goveming regulations and plant licensing bases. During this process, the staff assembled draft DG-1074, which provides one acceptable means for complying with the governing regulations and plant licensing bases to ensure tube integrity. At the same time, and in response to the staff's ongoing regulatory development effort, the industry focused its l
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a i
3 The Commissioners !
efforts on improving existing SG inspection guidance and developing new guidance. Two examp'as are the PWR Steam Generator Examination Guidelines now in Revision 5 and the PWR Primary-to-Secondary Leak Guidelines (both of these documents are directive guidelines as defined in NEl 97-06). The industry's efforts to improve industry guidance culminated in the NEl 97-06 initiative previously described.
Currently, technical differences still remain between the industry and the staff, as well as issues regarding the appropriate regulatory framework for implementing the NEl guidelines. However, 1
consistent with Direction Setting issue (DSI) 13, the staff's preferred approach is to endorse an industry initiative that addresses all staff and stakeholder concerns rather than issue a generic 1
letter. The staff is working with industry to resolve issues associated with NEl 97-06.
Accordingly, the staff proposes to delay issuance of the proposed generic letter while it meets with industry in 0-der to try and resolve staff and any stakeholder concerns, with the objective of being able to erMorse NEl 97-06 in a regulatory guide. The staff expects to determine whether the generic letter effort should be reactivated by January 1999 based on the progress in resolving remaining concerns with the industry.
The staff has concluded that this approach makes the best use of available staff resources, enables the staff to monitor the industry's effort to complete the guidance supporting NEl 97-06 and to implement the initiative, gives appropriate credit to the industry initiative, and is consistent with DSI 13. To provide a basis for the discussion of technicalissues with interested stakeholders and the industry, the staff continues to support issuance of DG-1074 and the DPO consideration document for public comment, in order to inform the Commission of his continued concerns about steam generator tube integrity, the DPO submittee prepared the document that has been included as Attachment 3.
i Since this document will also provide a basis for the discussion on technical issues, it will be i
provided for public comment. Attechment 3 was prepared after staff completion of Attachment
- 2. Attachment 2 has not been reviewed for any changes that might be necessary.
In COMSECY-97-013, the staff indicated that it would develop an application specific regulatory I
guide containing guidance for asst,3ing the changes in risk associated with proposed I
relaxations to SG tube repair crite..a. Accordingly, the staff is developing draft regulatory guide DG-1073 "An Approach for Plant-Specific, Risk-Informed Decision Making: Steam Generator Tube Integrity and intends to issue it for public comment after the staff makes its final decision on the need for a generic letter on SG tube integrity and whether industry guidance supporting NEl 97-06 will adequately address risk.
RECOMMENDATION:
The staff intends to delay issuance of the proposed generic letter package while it works with industry to reach agreement on NEl 97-06. The staff will reassess the need for issuance of the proposed generic letter on the basis of the progress in resolving concerns with NEl 97-06. The
The Commissioners staff intends to issue for public comment the attached DG-1074, the DPO consideration document, and the memorandum to the Commission from Hopenfeld to provide a basis for the discussion of technicalissues with interested stakeholders and the industry.
The staff requests action within 10 days. Action will not be taken until the Staff Requirements Memorandum is received. We consider this action to be within the delegated authority of the Executive Director for Operations.
-EN -
/
William D. Travers Executive Director for Operations Attachments: 1. Draft Regulatory Guide DG-1074," Steam Generator Tube Integrity"
- 2. Differing Professional Opinion Consideration Document
- 3. Memorandum to the Commission from Joram Hopenfeld,"J. Hopenfeld's Differing Professional Opinion Concerning Voltage-based Repair Criteria for Steam Generator Tubes: Release of DPO Consideration Document for Public Comment," dated September 25,1998 DISTRIBUTION:
Commissioners OGC OCAA OIG OPA OCA ACRS CIO CFO EDO REGIONS SECY l
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U.S. NUCLEAR REGULATORY COMMISSION SIptImber 1998
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OFFICE OF NUCLEAR REGULATORY RESEARCH Division 1 5
Draft DG-1074
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DRAFT REGULATORY GUIDE Contact E. L. Murphy (301)415-2710 l
l DRAFT REGULATORY GUIDE DG-1074 l
l STEAM GENERATOR TUBE INTEGRITY l
I This regulatory guide is being issued in draft form to in-eve the public in the earty stages of the development of a regulatory position in this i
area. It has not receeved completa staff review and does riot represent an official NRC staff posmon.
Puolic comments are being solicited on the draft guide (including any implementation schedule) and its associated regulatory analysis or
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value/tmpact statement Comments should be accompanied by appropriate supporting data. Written comments may be submitted to the Rules
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and Directives Branch. Office of Administration, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001. Copies of comments received may be examined at the NRC Public Document Room,2120 L Street NW., Washington, DC. Comments will be most helpfulif received by Requests for single copies of draft or active regulatory guides (which may be reproduced) or for placement on an automatic distribution list for single copies of future draft guides in specific divisions should be made in writing to the U.S. Nuclear Regulatory Commission, Washington, D 205500001 Attention: Reproduction and Distribution Services Section, or by fax to (301)415 228g.
i ATTACHMENT 1
A. INTR ODUCTION....................................................,
B. DI SC U S SI ON.......................................................
C. REGUI.ATORY POSITION................................................
1.
SG TUBE INSPECTION.................................................
1.1 Inspection Scope and Frequency..................................... 11 1.1.1 Preservice Inspection....................................... 11 1.1.2 Frequency of Inservice inspections............................. 11 j
1.1.3 initial Inspection Sample for Inservice inspections................. 12 1.1.4 - Expanded Inspection Sample................................. 12 i
1.2 NDE Data Acquisition and Analysis...................... -............. 13 1
1.2.1 Qualification for Detection.................................... 14 1.2.1 Validation for Detection / Sizing................................. 15
- 2. -
PERFORMANCE CRITERIA FOR SG TUBE INTEGRITY....................... 17 2.1 Structural Performance Criteria...................................... 17-2.1.1 Deterministic Structural Performance Criteria..................... 17 2.1.2 Probabilistic Structural Performance Criteria...................... 18 2.2 Operational Leakage Performance Criteria.........................
Accident Leakage Criteria.......................................... 1) 2.3
.... 18 4
3.
CONDITION MONITORING ASSESSMENT................................. 1W l
3.1 Structural integrity............................................... 20 3.1.1 Assessment Vis-a-Vis Deterministic Performance Criteria........... 20 3.1.2 Assessment Vis-a-Vis Probabilistic Performance Criteria............. 20 t
3.2 Operational Leakage Integrity....................................... 21 3.3 Accident Leakage integrity........................................ 21 3.4 Special Considerations for Condition Monitoring Assessment.............. 22 i
3.4.1 Load ings................................................. 22 3.4.2 Empirical Models.......................................... 23 3.4.3 in Situ Pressure Tests...................................... 25 4.
OPERATIONAL ASSESSMENT.......................................... 27 4.1 Structural lntegrity............................................... 27 4.1.1 Assessment Vis-a-Vis Deterministic Performance Criteria........... 27 4.1.2 Assessment Vis-a-Vis Probabilistic Performance Criteria............ 29 4.2 Accident Leakage lntegrity........................................ 29 4.3 Special Considerations for Operational Assessment..................... 30 l
4.3.1 Load i ngs................................................ 30 4.3.2 Empirical Models........................................... 30 4.3.3 Defect Growth Rates........................................ 30 l.
4.3.4 Rate and Size of New Indications.............................. 31 4.3.5 NDE Indication Sizing Error or Variability........................ 32 5.
TUBE PLUGGING AND REPAIRS...................................... 32
' 5.1 Tube Repair Criteria............................................ 33 5.2 '
Tube Plugging and Repair Methods.................................. 33 6.
CORRECTIVE ACTIONS............................................. 33
7.
PREVENTIVE M EASU RES.......................................... 34 7.1 Secondary Water Chemistry Program................................ 34 7.2 Loose Parts and Foreign Objects....
.............................35 7.2.1 Secondary Side Visual Inspections........................... 35 7.2.2 Control of Loose Parts and Foreign Objects.....................
35 7.3 Measures To Mitigate Active Degradation Mechanisms.................. 35 8.
OPERATIONAL PRIMARY-TO-SECONDARY LEAKAGE MONITORING AND LIMITS
............................................ 36 8.1 Leakage M onitoring.............................................. 36 8.1.1 Monitoring Strategy......................................... 36 8.1.2 Operational Guidance...................................... 37 8.1.3 Operator Training......................................... 38 8.1.4 Program Updates and Self-assessment........................ 38 8.2 Technical Specification LCO Leakage Limits........................... 38 8.3 Procedural Limits on Operational Leakage........................... 39 9.
RADIOLOGICAL ASSESSMENT....................................... 39 9.1 Dose Calculation Methodology..................................... 41 9.1.1 Default Methodology....................................... 42 9.2.2 Flex Methodology.......................................... 43 9.2.3 Technical Specifications..................................... 47 10.
REPORTS TO THE NRC.............................................. 54 10.1 SG Tube Inservice Inspection....................................... 54 10.2 Failure of the Condition Monitoring Assessment........................ 54 D. I M P LE M E NTATI O N..................................................... 54 RE F ER E N C E S.............................................................. 5 5 REG ul.ATO RY ANALYSIS.................................................. 56
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A. INTRODUCTION The steam generator (SG) tubes in pressurized water reactors have a number of important l
safety functions. These tubes are an integral part of the reactor coolant pressure boundary (RCPB) and, as such, are relied upon to maintain the primary system's 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; the SG tubes are also 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 severe accdents.
l In this regulatory guide, tube integrity means that the tubes are capable of perforrNg their intended safety functions consistent with the licensing basis, including applicable reguletory l
requirements.
i Concems 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 mechanismd that are widespread throughout the industry. These degradation mechanisms can impair tube integrity if l
they are not managed effectively.
Title 10 of the Code of Federal Regulations establishes the fundamental regulatory requirements with respect to the integrity of the SG tubing. Specifically, several General Design l
Criteria (GDC) in Appendix A,2 " General Design Criteria for Nuclear Power Plants," to 10 CFR Part 50, " Domestic Licensing of Production and Utilization Facilities," are applicable to the integrity of the steam generator tubes.
GDC-1, " Quality Standards and Records," states in part that structures, systems, and components important to safety must be designed, fabricated, and tested to quality standards commensurate with the importance of the safety functions to be performed.
i GDC-2, " Design Basis for Protection Against Natural Phenomena," states in part that structures, systems, and components important to safety must be designed to withstand the
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effects of natural phenomena without loss of capability to perform their safety functions.
GDC-4, " Environmental and Dynamic Effects Design Basis," states in part that structures, systems, and components important to safety are to be designed to accommodate the effects of and to be compatible with the environmental conditions associated with normal operation, maintenance, testing, and postulated accidents. These structures, systems, and components must 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 l
'Words in bold-faced type are defined in " Definitions" in Section B.
I 2For PWR facilities licensed prior to the promulgation of 10 CFR 50 Appendix A, similar requirements may appear in the plant licensing basis 1
i
analyses that have been reviewed and approved by the NRC demonstrate that the probability of piping rupture is extremely low under conditions consistent with the design basis for the piping.
GDC-14, " Reactor Coolant Pressure Boundary," states that the RCPB shall be designed, fabricated, erected, and tested so as to have an extremely low probability of abnormal leakage, of rapidly propagating failure, and of gross rupture.
GDC-30, " Quality of Reactor Coolant Pressure Boundary," states that components that are part of the RCPB must be designed, fabricated, erected, and tested to the highest quality standards practical. Means are to be provided for detecting and, to the extent practical, identifying the location of the source of the reactor coolant leakage.
GDC-32, " Inspection of Reactor Coolant Pressure Boundary," states that components that are part of the RCPB are to be designed to permit periodic inspection and testing of important areas and features to assess their structural and leaktight integrity.
Appendix B, " Quality Assurance Criteria for Nuclear Power Plants and Fuel Reprocessing Plants," to 10 CFR Part 50 estat""shes 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 ensure that special processes, including welding, heat treating, and nondestructive testing, are controlled and accomplished by qualified personnel using qualified procedures in accordance with applicable codes, standards, specifications, criteria, and other special requirements. Criterion XI, " Test Control," requires in part that a test program be established to assure that all testing required to demonstrate that structures, systems, and components will perform satisfactorily in service is identified and performed in accordance with written test procedures which incorporate the requirements and acceptance 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.
This regulatory guide describes a method acceptable to the NRC staff for monitoring and maintaining the integrity of the SG tubes at operating pressurized water reactors (PWRs). It also provides guidance on evaluating the radiological consequences of design basis accidents involving leaking SG tubing in order to demonstrate that guidelines in 10 CFR Part 100, " Reactor Site Criteria," regarding offsite doses and GDC 19 regarding control room operator doses, can be met. This guide applies only to PWRs.
1 Regulatory guides are issued to describe to the public methods acceptable to the NRC staff fo^ implementing specific parts of the NRC's regulations, to explain techniques used by the staff in evaluating specific problems or postulated accidents, and to provide guidance to applicants. Regulatory guides are not substitutes for regulations, and compliance with regulatory guides is not required. Regulatory guides are issued in draft form for public comment to involve the public in developing the regulatory positions. Draft regulatory guides have not received complete staff review; they therefore do not represent official NRC staff positions.
l The information collections contained in this draft regulatory guide are covered by the requirements of 10 CFR Part 50, which were approved by the Office of Management and Budget, 2
approval number 3150-0011. The NRC may not conduct or sponsor, and a person is not required to respond to, a collection of information unless it displays a currently valid OMB control number.
B. DISCUSSION As part of the plant licensing basis, applicants for a PWR operating license analyze the consequences of postulated design basis accidents that assume degradation of 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 when demonstrating that radiological consequences do not exceed the 10 CFR Part 100 guidelines, or some fraction thereof, for offsite doses, nor GDC-19 for control room operator doses. NUREG-0800, the Stanc4rd Review Plan. (5RP) (Ref.1), would be used by the staff to evaluate these accidents.
This regulatory guk1e also provides acceptable attemative guidelines conceming the assessment of the radiological consequences of SGTR and MSLB accidents.
Consistent with the GDC,10 CFR 50.55a(c) specifies that components that are part of the reactor coolant pressure boundary must be designed and constructed to meet the requirements for Class 1 components in Section 111 of the American Society of Mechanical Engineers (ASME)
Boiler and Pressure Vessel Code (Ref. 2). To ensure the continued integrity of the tubing at operating PWR facilities,50.55a further requires that throughout the service life of a PWR facility, Class 1 components meet the requirements in Section XI, " Rules for Inservice inspection of Nuclear Power Plant Components" of the ASME Code (Ref. 2). This requirement includes the inspection and tube repair criteria of Section XI of the ASME Code. However, an exception is provided for design and access provisions and preservice examination requirements in Section XI. In addition,10 CFR 50.55a(b)(2)(iii) states that if the 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 is govemed by the technical specifications.
A plant's technical specifications, which are typified by the standard technical specifications in References 3,4, and 5, require that licensees perform periodic inservice inspections of the SG tubing and repair or remove from service (by installing plugs in the tube ends) all tubes exceeding the tube repair limit. In addition, operational leakage 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 leaking tubes. These requirements are intended to ensure that burst margins are maintained consistent with Appendices A and B to 10 CFR Part 50 and that the potential for leakage is maintained consistent with what has been analyzed as part of the plant licensing basis.
Revision 1 of NRC Regulatory Guide 1.83, " inservice Inspection of Pressurized Water Reactor Steam Generator Tubes" (Ref. 6), provides guidance concerning SG inspection scope and frequency and nondestructive examination (NDE) methodology. Regulatory Guide 1.83 is referenced in the SRP and is intended to provide a basis for reviewing inservice inspection criteria in the technical specifications. However, this guidance will be superseded by the final version of this regulatory guide.
NRC Regulatory Guide 1.121, " Bases for Plugging Degraded PWR Steam Generator Tubes" (Ref. 7), provides guidelines for determining the tube repair criteria and operational 3
leakage limits that are specified in the technical specifications. These guidelines are superseded by this regulatory guide.
SUMMARY
OF APPROACH This regulatory guide provides an acceptable programmatic namework for monitoring and maintaining the integrity of the SG tubes consistent with Appendices A and B to 10 CFR Part 50 and the plant ticensing basis. This framework includes performance criteria that, if satisfied, provide reasonable assurance that tube integrity is being maintained consistent with the licensing basis. In addition, this framework provides for monitoring and maintaining the tubes to ensure inat the performance criteria are met at all times between scheduled inspections of the tubes.
Figure 1 provides a flow chart illustration of the overall program strategy embodied in this regulatory guide, including each of the major program elements.
Procedures for imnlementing these program elements are to be developed by the utilities.
This regulatory guide provides broad guidelines conceming the key considerations, parameters, and constraints that should be addressed as part of the development of these program elements to ensure that tube integrity performance can be effectively monitored and controlled. Thess guidelines are intended to provide licensees with 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 or defect types, changes in flaw growth rates, and other changing circumstances. Licensees must develop and implement steam generator defect specific management (SGDSM) strategies to fully achieve this flexibility. SGDSM strategies involve an integrated set of program elements, paralleling those in this regulatory guide, that address specific defect types.
As shown in Figure 1, the first program element consists of tube inspections using NDE methods in accordance with Regulatory Position 1 of this regulatory guide. These inspections are 1
intended to provide information conceming the defect types present in the SGs and to identify tubes containing defects and the size of these defects. This information is used as part of other program elements, discussed below, to assess tube integrity performance relative to the performance criteria, to determine which tubes fail to satisfy the applicable tube repair criteria (and which must, therefore, be repaired or removed from service by plugging), and to assess needed improvements in measures being taken to mitigate active degradation mechanisms and defect types.
Guidelines for determining the appropriate frequency ofinspection and level of tube sampling are provided in Regulatory Position 1. Guidelines for NDE data acquisition and analysis are given in Regulatory Position 1.2. NDE techniques and NDE personnel should be qualified for detection in accordance with the guidelines of Regulatory Position 1.2.1. Using NDE techniques and NDE personnel that are qualified for detection constitute a minimum acceptable approach that, in conjunction with implementation of the other programmatic elements of this regulatory guide, ensures that the tube integrity performance criteria will be met until the next scheduled inspection. If available, NDE techniques and NDE personnel that are also validated for detection and validated for sizing should be used. Validation involves quantifying the defect detection and sizing performance of NDE techniques and personnel. This information,if available, affords the licensee additional flexibility within the framework of this regulatory guide for ensuring that the performance criteria will be met until the next scheduled inspection.
4 I
i Figure 1 PROGRAM STRATEGY /
L STEAM GENERATOR TUBE INTEGRITY
+
NDE i
Qualification /
inservice l
Validation Inspection j
Condition Monitoring 3-i i
Per-j-
No formance Inform NRC C
Criteria Satisfied
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p Yes Corrective Operational Actions Assessment J L 1 f No Per-formance Criteria Satisfied
?
Yes Plug /
Submit Outage Repair Report 4 k Preventive Measures
+
[PlantN Monitor
\\
Restaryt Leakage m
The tube inspections are followed by assessments of tube integrity performance relative to performance criteria. Performance criteria acceptable to the NRC staff are given in Regulatory Position 2 of this regulatory guide. These performance criteria address three areas of tube integrity performance: structural integrity, operational leakage integrity, and accident-induced leakage integrity. These performance criteria are expressed in terms of parameters that are directly measurable or that may be calculated on the basis of direct measurements. The criteria correspond to conditions undar which public health and safety is assured.
a Performance criteria for tube structural integrity that are acceptable to the NRC, as identified in Regulatory Position 2.1.1, involve deterministic safety factors against burst that are consistent with tha original design and licensing basis; namely, factors of safety consistent with the stress limits of Section ll1 of the ASME Code (Ref. 2). Alternatively, licensees may submit a proposed change to the licensing basis to permit use if probabilistically based performance criteria for tube structural integrity, as identified in Regulatory Position 2.1.2, which are consistent with GDC-14. Proposed changes should be risk-informed and give appropriate consideration to defense in depth (i.e., the containment function of steam generator tubes). Guidance for submitting risk-informed proposed changes to the licensing basis is provided in Regulatory Guide 1.174, "An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Specific Changes to Licensing Bases" (Reference 8).
Performance criteria acceptable to the NRC for accident leakage integrity are identified in Regulatory Position 2.3. These involve accident leakage rates consistent with those assumed in the licensing basis accident analyses for purposes of demonstrating that the accident consequences are in accordance with 10 CFR Part 100, or some fraction thereof, and GDC-19.
For most plants, the leakage rates assumed in these analyses are based on operational leakage limits in the technical specifications. Licensees may submit a proposeo change to the licensing basis updating the accident analyses to accommodate revisions to the performance criteria for accident leakap. The staff encourages licensees to follow risk-informed approaches when submitting such properals following the guidance in Reference 8. Such proposals should be supported by an assssment of the radiological consequences in accordance with Regulatcry Position 9.
Tube integdty performance is subject to two different types of assessments, as indicated in Figure 1: a condition monitoring assessment in accordance with Regulatory Position 3 of this regulatory guide and an operational assessment in accordance with Regulatory Position 4. The condition monitoring assessment is " backward looking" in that its purpose is to conf,rr.' that tube integrity has been maintained since the previous inspection. Condition monitoring inauec an assessment of the "as found" condition of the tubing relative to the tube integrity performance criteria. The "as found' condition refers to the condition of the tubes during an SG inspection outage, prior to any plugging or repair of tubes. The condition monitoring assessment may utilize information from the tube inspections or from alternative examination methods to assess the condition of the tubing. Failure of one or more tubes to satisfy the performance criteria may be indicative of programmatic deficiencies in the licensee's program for monitoring SG tube integrity.
Licensees should assess the causal factors associated with this type of finding and implement appropriate corrective actior:s. The condition monitoring assessment and implementation of resulting corrective actions, if necessary, should 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 6
next scheduled tube inspection. Operational assessment involves projecting the condition of the tubing at the time of the next scheduled inspection outage relative to the tube integrity j
performance criteria. This projection is casad on the inspection results, the tube repair criteria to be implemented for each defect type, and the time interval prior to the next scheduled tube j
inspection. Corrective actions should be taken, as necessary, such that it can be demonstrated by operational assessment that the perfcrmance criteria will be met until the next scheduled inservice l
inspection. Corrective actions may include inspecting the steam generators at more frequent intervals or reducing the tube repair criteria. A preliminary operational assessment and implementation of corrective actions, as necessary, should be 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, i
should be completed within 90 days of plant restart, demonstrating that the performance criteria will continue to be met prior to the next scheduled inspection.
Pluggirg and repair of defective tubes is performed in accordance with Regulatory Position 5, prior to plant restart, based on the results of the tube inspections and operational assessment (or preliminary operational assessment). Plugging and 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.
i Regulatory Position 5.1 provides guidelines for determining the appropriate repair limits for each defect type. An acceptable repair limit that is applicable to all defect types is the 40%
through wall, depth-based criterion, subject to demonstrating by operational s'isessment that the performance criteria will be met until the next scheduled tube inspection. Licensees may submit proposed changes to the technical specifications to permit implementation of attemative repair criteria (ARC) for specific defect types as part of an SGDSM strategy. Such proposals should be risk-informed and give appropriate consideration to defense in depth (i.e., the containment function of steam generator tubes). SGDSM is an integrated approach aimed at ensuring that the performance criteria are met until the next scheduled inspection. SGDSM consists of a specific inservice inspection program (with specified frequency and level of sampling, s ncified qualified or j
validated NDE techniques) consistent with Regulatory Position 1 and specific condition monitoring and operational assessment methodologies consistent with Regulatory Positions 3 and 4.
Regulatory Position 5.2 provides guidelines for developing appropriate plugging and repair methodologies, including the associated hardware (e.g., plugs and sleeves). Guidelines for submitting a proposed licensing basis change (including technical specification change) that is risk-informed are provided in Reference 8.
Regulatory Position 6 provides guidelines for implementing corrective actions, depending on the results of condition monitoring and operational assessment, as necessary to ensure the performance criteria will be met until the next scheduled tube inspection.
Preventive measures are implemented in accordance with Regulatory Position 7 and involve measures to mitigate active degradation mechanisms and to minimize the potential for new degradation mechanisms. Regulatory Position 7.1 addresses secondary water chemistry control.
Regulatory Position 7.2 addresses measures to control loose parts and foreign objects within the steam generators, and Regulatory Position 7.3 addresses other measures for mitigating active degradation mechanisms.
Operational primary-to-secondary leakage monitoring is performed in accordance with Regulatory Position 8. These guidelines are intended to ensure that leakage is effectively 7
monitored and that appropriate and timely action will be tt ken before a leaking tube exceeds the tube integrity performance criteria, including tubes undugoing rapidly increasing leak rates.
Regulatory Position 8.1 addresses development of monitoring programs. Regulatory Position 8.2 addresses development of limiting condition for operation (LCO) limits in the technical specifications for allowable operational leabge. Regulatory Position 8.3 addresses the development of procedural limits for owational limits to ensure the performance criteria are met.
Guidelines for evaluating the radiological consequences of SG tube leakage during postulated accidents relative to 10 CFR Part 100 guidelines for offsite doses, or some part thereof, and GDC-19 criteria (or control room operator doses are addressed in Regulatory Position 9.
Guidelines for submitting reports to the NRC conceming the results of inservice inspection and condition monitoring are addressed in Regulatory Position 10.
DEFINITIONS Accident leakage rate is the primary-to-secondary leakage rate occurring during postulated accidents other than a steam generator tube rupture. This includes the primary-to-secondary leakage rate existing immediately before the accident plus additional primary-to-secondary leakage induced during the accident.
Active degradation mechanisms and active defect types are new indications associated with these mechanisms and defect types that have been identified during inservice inspection or that were previously identified indications associated with these defect types that have exhibited growth since the previous inspection of the subject tubes.
Alternative repair criteria (ARC) are tube repair criteria that may be implemented for a specific defect type as part of an SGDSM program in lieu of the generally applicable depth-based criterion (which is 40% of the initial tube wall thickness at most plants).
Buffer zone is a zone extending radially from the critical region (see definition) for a specific defect type. A buffer zone includes a sufficient number of tubes and portions thereof to permit confirmation by inspection that the critical region does in fact bound the region where the subject defect type is active.
Burst is gross structural failure of the tube wall. Analytically this corresponds to a condition in which a critical parameter for unstable crack propagation, e.g., limit load, is exceeded.
Experimentally, it corresponds to unstable crack propagation limited only by testing considerations, e.g., loss of bladder or depletion of the pressure reservoir.
Cond! tion a 'onitoring is an assessment of the "as found" condition of the tubing with respect to l
the perforrnance criteria. The "as found" condition refers to the condition of the tubing during an SG inspection outage, as determined from the inservice inspection results or by other means, prior to the plugging or repair of tubes.
Critical region is a region of the tube bundle that can be demonstrated to bour:d the region where a specific defect type is active.
8
Defective tube (or tube that is defective) is a tube that exhibits an indication exceeding the applicable tube repair criteria.
Defect size is the actual physical dimensions of the defect. Frequently, defect size is expressed in terms of a single parameter (e.g., depth, length) when the applicable tube repair criterion is expressed in terms of only that parameter (as measured by NDE).
Defect size measurement (or measured defect size) is the defect size as measured during an l
NDE tube inspection.
i Defect type is a degradation mechanism and an associated set of general circumstances that affect the determination of appropriate NDE techniques for flaw detection and sizing, flaw growth rates, and calculational models for determining structural and leakage performance. General circumstances include the tube size, tube material, defect orientation, whether the defect initiates frem the tube primary side or secondary side, and the location of the defect within the tube (e.g.,
in straight freespan, in u-bend, at tube support plate, at expansion transition). A degradation mechanism may include several defect types.
Defined region for a specific defect type is a region of the tube bundle consisting of a critical region (see definition) for that defect type and a surrounding buffer zone (see definition).
Degradation mechanism is the general defect morphology and its associated causes, e.g.,
j wear-induced thinning of the tube wall caused by adjacent support structures, high cycle fatigue cracking caused by flow-induced vibration of the tube, intergranular stress corrosion cracking j
caused by stress, material susceptibility, and environment.
l Degraded tube is a tube containing an indication less than the applicable plugging limit measured by an NDE technique and NDE personnel validated for sizing for the subject defect type.
Error is the difference between measured defect depth or length and actual defect depth or length.
Indication is the NDE signal response to a defect or condition that is present in the tube. An indication may or may not be measurable relative to the applicable tube repair criteria.
Indication size or indication measurement is the measurement of the defect size or the voltage amplitude of the NDE signal response to a defect.
NDE personnel are personnelinvolved with data analysis.
NDE technique includes specific data acquisition equipment and instrumentation, data acquisition procedures, and data analysis methods and 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 and characterize possible indications found by the bobbin would
- constitute a single NDE technique for detection purposes.
Operational assessment is an assessment to ensure that the tubes will continue to satisfy the i
performance criteria until the next scheduled inspection.
9
Performance criteria are criteria approved by the NRC that, if satisfied, provide reasonable assurance that tube integrity is being maintained consistent with the licensing basis.
l Plugging limit is the tube repair limit.
Potential defect types are defect types that may affect the steam generator tubes at a given plant during the steam generator lifetime based on 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 defect type and been shown capable of reliably detecting flaws associated with the defect type before these flaws are of sufficient size to cause the performance criteria to be exceeded.
Rupture is perforation of the tube wall such that the primary-to-secondary leak rate exceeds the normal charging pump capacity of the primary coolant system.
Steam generator defect-specific management (SGDSM) is an integrated strategy applicable to a given defect type for ensuring that the performance criteria will be satisfied. SGDSM strategies include a specific program for conducting inservice inspection (including specified NDE technique and frequency and level of sampling) and specific methodologies for conducting condition monitoring and operational assessments. SGDSM strategies may also include attemative repair criteria.
Structural limit is the calculated maximum allowable flaw size or indication size consistent with the safety factor performance criteria in Regulatory Position 2.1.1.
Tube repair criterion is the NDE measured flaw depth or length, or indication voltage amplitude, at or beyond which the subject tube must be repaired or removed from service by plugging.
Validated for detection means that NDE techniques and personnel have undergone supplemental performance demonstration for a given defect type as necessary to quantify defect detection performance (e.g., probability of detection (POD) of a given defect) expected under field conditions.
Validated for sizing means that NDE techniques and personnel have undergone supplemental performance demonstration for a given defect type as necessary to quantify the potential error or variability of indication size measurements (e.g., measured defect depth, measured defect length, measured voltage response to defect) expected under field conditions.
Variability refers to the repeatability of indication size measurements for a given defect.
C. REGULATORY POSITION These guidelines provide an acceptable framework for the development of a program to l.
monitor and maintain the integrity of the SG tubes. This program should be documented in plant I
10 i
e
1 1
i procedures, should be auditable, and must conform to Appendix B of 10 CFR Part 50. Reporting should be in accordance with Regulatory Position 10 of this regulatory guide.
j
\\
11.
SG TUBE INSPECTION 1
\\
The objective of SG tube inspection is to provide sufficient information concerning the defect types present in the SGs, the tubes that contain defects, and the size of these defects such that when implemented in conjunction with the other programmatic elements of this regulatory guide, there is reasonable assurance that the tube integrity performance criteria in Regulatory Position 2 are being maintained throughout the time period between SG tube inspections.
Specifically, the information from SG tube inspections is used in conjunction with the other program elements of this regulatory guide to assess tube integrity performance relative to the performance criteria, to determine which tubes fail to satisfy the applicable tube repair criteria (and which must, therefore, be repaired or removed from service by plugging), and to assess needed improvements in measures being taken to mitigate active degradation mechanisms and defect types.
1.1 Inspection Scope and Frequency 1.1.1 Preservice inspection The preservice inspection should be performed after the field hydrostatic test for new plants and after tube installation for replacement steam generators, but prior to either initial power operation or plant startup after SG replacement. This inspection should be conducted on 100% of the tubes over their full length using a general purpose NDE technique (e.g., eddy current bobbin probe). The data acquisition and analysis should be performed in accordance with written procedures in accordance with Regulatory Position 1.2. The general purpose NDE technique and data analysis personnel should be qualified for detection in accordance with Regulatory Position 1.2.1 for volumetric defect types such as wall thinning.
4 Additional inspections should be conducted with specialized and more sensitive NDE techniques (e.g., eddy current rotating pancake coil) to establish a definitive baseline record against which inservice changes may be compared. These inspections should include a sample of expansion transition locations, small radius u-bends, and locations exhibiting abnormal conditions I
(e.g., dents, tube geometry abnormalities) or unusual signal responses during the general purpose examination.
1.1.2 Frequency of Inservice inspections inservice inspection of each steam generator should be performed at the first refueling outage (a duration not less than 6 effective full power months (EFPM) and not more than 24 EFPM). Subsequent inservice inspections of each steam generator should be performed at a frequency such that operational assessment in accordance with Regulatory Position 4 demonstrates that tube integrity performance criteria in Regulatory Position 2 will continue to be met until the next scheduled inspection of that steam generator. No steam generator should operate more than two fuel cycles between inservice inspections. Inservice inspections (unscheduled) should also be performed during plant shutdown subsequent to any of the following conditions:
11
e 2
l 1.
Primary-to-secondary leakage leading to plant shutdown for repair of the leaking
)
tubes, applicable only to leaks involving tube, plug, or sleeve flaws or sleeve-to-tube welds i
2.
Seismic occurrence greater than the Operating Basis Earthquake l
l 3.
Loss-of-coolant accident requiring actuation of the engineored safeguards h
4.
Main steam line or feedwater line break i
1.1.3 initial Inspectica Sample for Inservice inspections i
The initial tube sample for inservice inspection, schedulca and unscheduled, should include a minimum 20% sample of the total number of steam generator tubes that remain in service (i.e., tubes that have not been plugged). This 20% sample may be a random sample or a i
systematic, sequential, uniformly distributed sample. This sample should be divided equally among all SGs being inspected during a given plant outage. The initial inspection sample should be over the full length of the tube (hot leg tube end to cold leg tube end, including installed sleeve repairs).
The initial inspection sample should be conducted with NDE techniques and personnel that are appropriate and in accordance with Regulatory Position 1.2 to address all defect types that may affect the SGs over their lifetime (i.e., potential defect types). Potential defect types should be assessed prior to each inservice inspection. 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 appropriate.
The initial inspection sample in a SG should be supplemented to include tubes previously found to be degraded but left in service without repair. The inspection should include 100% of such tubes or, attematively, the operational assessment should demonstrate, in accordance with Regulatory Position 4, that the tube integrity performance criteria in Regulatory Position 2 will continue to be met until the next scheduled inspection of that steam generator. These supplemental inspections may be limited to a partial length of the tube containing the previously observed indication provided the subject defect type can be shown to be limited to that partial length.. These supplemental inspections should use appropriate NDE techniques and personnel for each of the subject defect types as discussed in Regulatory Position 1.2.
In general, the above guidance for initial sampling also applies for unscheduled inspections caused by primary-to-secondary leakage for the steam generator affected by the leak. However, if the defect type associated with the leak has been established to be confined to a critical region, the initial inspection sample may be limited to an associated defined region encompassing the critical region in the affected steam generator.
Indications ;ound during the initial sample should be evaluated as necessary to establish the active defect types present in the steam generators. The appearance of one or more new indications or growth in pre-existing indications indicate active defect types.
1.1.4 Expanded inspection Sample 12
For each active defect type identified during the initial sampling of a given steam generator, an expanded inspection sample should be performed in that steam generator and an initial sample inspection in accordance with Regulatory Position 1.1.3 should be performed in any steam generators not already scheduled for inspection. For unscheduled inspections caused by primary-to-secondary leakage, an expanded inspection sample in the affected steam generator and initial sample inspection of the other steam generators is performed only if nonleaking indications involving the subject defect type are found during the initial sample in the affected steam generator.
The expanded sample should apply to the entire tube bundle of the affected steam generator unless the defect type can be demonstrated to be confined to a critical region, in which case the expanded inspections for the subject defect type may be confined to a defined region consisting of the critical regions and a surrounding buffer zone. Technicaljustification to support identification of a critical region should be maintained as part of the inspection record. Technical justification should either (1) address the uniqueness of essential contributing factors (for the subject defect type) to the critical area or (2) demonstrate that the indications found during initial sampling are of sufficient number and spatial distribution to provide a strong empirical basis for the critical region.
The expanded sample should consist of 100% of the tubes within the tube bundle or defined region, whichever is applicable, or alternatively, should be as necessary to demonstrate by operational assessment in accordance with Regulatory Position 4 that the tube integrity performance criteria in Regulatory Position 2 will continue to be met until the next scheduled inspection of that steam generator.
The expanded inspection sample for each active defect type should be performed with appropriate NDE techniques and personnel for that defect type as discussed in Regulatory Position 1.2. When more sensitive and more accurate NDE techniques are employed compared to previous inspections, additional inspections conducted with the previous techniques may be used as a benchmark for determining flaw growth between inspections and the rate of new indications during the previous cycle.
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 acqrisition and analysis.
These procedures must be in accordance with Appendix B to 10 CFR Part 50. The objective of these procedures is to ensure the capability to reliably detect and, if practical, size tubing defects.
In the context of this regulatory guide, this objective has been satisfactorily achieved when implementation of these procedures in conjunction with the other programmatic elements of this regulatory guide ensures that the tube integrity performance criteria will be met until the next scheduled SG inservice inspection. The following guidelines should be followed to ensure that this objective is met.
(1)
The procedures should ensure that NDE techniques and personnel used to address each potential defect type are " qualified for detection"in accordance with Regulatory Position 1.2.1 with respect to that defect type. NDE technique refers to specific data acquisition equipment and instrumentation, data acquisition procedures, and data analysis methods and procedures. In this context,"NDE technique" includes the summation of techniques directed at each degradation 13
mechanism. For example, the use of bobbin probes for performing an initial screening inspection followed by a rotating pancake coil (RPC) inspection to confirm and characterize possible indications found by the bobbin would constitute a single NDE technique for detection purposes.
NDE personnel are personnel involved with data analysis.
(2)
The procedures should ensure that NDE techniques and personnel used to address each potential defect type are " validated for detection" and " validated for sizing" in accordance with Regulatory Position 1.2.2 for that defect type, assuming the availability of such techniques and personnel. For defect types for which validated techniques and personnel are not available, nonvaliJated NDE techniques and personnel may be used provided they are qualified for detection in accordance with Regulatory Position 1.2.1. A comparative evaluation should be performed for available nonvalidated techniques and the best of these techniques in terms of detection performance for the subject defect type should be employed.
(3)
The procedures should ensure that the above qualifications and validations are applicable to the specific plant to which they are being applied. This means that the plant-specific
]
circumstances (e.g., magnitude of dent, deposit, and geometric discontinuity signals; electrical noise, tube and calibration standard noise; and overall signal-to-noise ratio) associated with each defect type have been representatively included in the qualification and validation performance demonstration data set.
(4)
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. The technique specification should be consistent with what has been qualified and validated in accordance with Regulatory Positions 1.2.1 and 1.2.2. 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 SGDSM strategies being implemented in accordance with Regulatory Position 5.1 for specific defect types.
(5)
The procedures should ensure that NDE data analysis personnel are performing their duties within the limits of applicability, i.e., the specific NDE techniques and the application of these techniques for which the personnel have been qualified and validated. Application refers to the specific defect types to which the subject NDE technique is being applied.
(6)
The procedures should include site-spec data analysis guidelines to ensure that the most appropriate data analysis practices are used for each defect type and to ensure that the data are analyzed in a consistent and reliable manner. These procedures should include site-specific training and performance demonstration of the data analysts to be implemented prior to each inspection to ensure their knowledge of the site-specific guidelines and their application to defect types and accompanying circumstances (e.g., denting, deposits) expected at the site.
These procedures should include procedures for an independent two-party data analysis, including procedures for discrepancy resolution, to minimize the potential for missing or incorrectly characterizing and sizing an indication. The procedures should include process controls as necessary to ensure the quality of the inspection. Examples of needed process controls include a process to document changes in the procedures and their proper dissemination and data quality requirements (including acceptable noise levels).
1.2.1 Qualification for Detection 14
l l
Qualified for detection means that NDE techniques and personnel have been shown i
capable of reliably detecting flaws associated with a given defect type before these flaws are of sufficient size to cause the performance criteria to be exceeded. Implementation of NDE techniques and personnel that meet this criterion is a minimum acceptable approach that, in l
conjunction with implementation of the other programmatic elements of this regulatory guide, ensures that the tube integrity performance criteria will be met until the next scheduled inspection.
This qualification should be conducted in accordance with written procedures described or referenced in the data acquisition and analysis procedures maintained by the organization (utility or vendor) conducting the inspection. These procedures should address training and written examination requirements for data analysis personnel. In addition, these procedures should address performance demonstration requirements for NDE techniques and data analysis personnel.
A qualification record should be maintained for each NDE technique to be employed during the inservice inspection for each intended application (i.e., for each defect type to be addressed by that technique) by the organization that conducted the qualification. The qualification record should include:
A description of the pe;formance demonstration test specimen data set and the results of the perfonnance demonstration.
The limits of a technique's applicability to specific defect types and associated e
extraneous test variables (e.g., denting signals, electrical noise, tube noise, calibration standard noise, deposit noise), signal to noise ratios, and tube geometry and material. These limits should be consistent the conditions covered by the performance demonstration test specimen data set.
A technique specification defining all essential variables to which the qualification is e
applicable.
A qualification record should be maintained for each of the NDE personnel to be employed during the inservice inspection by the employer of these personnel. The qualification record should include:
Record of training, including training hours, dates attended, and training institution.
e Dates and pass / fail results of the written examination and of the performance e
demonstration test for each defect type tested.
NDE techniques and NDE personnel that have been qualified in accordance with Appendices G and H of the EPRI PWR Steam Generator Examination Guidelines (Ref. 9), for a given flaw type may be deemed qualified for detection with respect to that flaw type as defined in this section of the regulatory guide.
1.2.1 Validation for Detection / Sizing Validated for detection means that NDE techniques and NDE personnel have undergone supplemental performance demonstration for a given defect type as necessary to quantify defect detection performance (e.g., probability of detection (POD) of a given defect) expected under field 15 l
i
conditions. Validated for sizing means that NDE techniques and personnel have undergone supplemental performance demonstration for a given defect type as necessary to quantify the potential error or variability of indication size measurements (e.g., measured defect depth, measured defect length, measured voltage response to defect) expected under field conditions.
Error is the difference between the measured defect depth or length and the actual defect depth or length. Variability refers to the repeatability ofindication size measurements for a given defect. It is the error of an indication size measurement that is of interest when the applicable tube repair criterion is in terms of measured flaw size or when structural and leakage models used for condition monitoring and operational assessment express burst pressure and accident leakage as a function of actual flaw size. It is the variability of the indication size measurement that is of interest when the tube repair criterion is in terms of indication voltage amplitude or when structural and leakage models used for condition monitoring and operational assessment express burst pressure and accident leakage as a function of indication size measurement (e.g., voltage amplitude of defect signal, measured flaw depth).
Validation involves quantifying detection and sizing performance, not demonstrating that this performance satisfies a specific numerical criteria. The availability of this performance information (particularly indication size measurement performance) enables direct consideration of the NDE inspection results as part of condition monitoring and operational assessment (see i
Regulatory Positions 3 and 4) to ensure that the performance criteria will be met until the next scheduledinspection. Information on indication size measurement performance enables use of the NDE inspection results to discriminate between which degraded tubes are defective and which are not, in lieu of assuming all tubes with indications are defective (see Regulatory Position 5). This information is also needed when developing new alternate repair criteria (see Regulatory Position 5.1). Although this information is not necessary from the standpoint of ensuring that the performance criteria will be maintained, it affords the licensee much more flexibility in terms of how it ensures that this objective is met. Potential benefits from using validated NDE techniques and NDE personnel include reducing the number of tubes that must be plugged or repaired and facilitating justification for operating a full operating cycle between inservice inspections.
Supplemental performance demonstration for NDE techniques and NDE personnel should be performed in accordance with written procedures maintained by the organization (utility or vendor) conducting the inspection. This demonstration for both the technique and the data analysis personnel should be performed on a common set of test specimens so as to allow defect detection and defect size measurement performance to be evaluated against the actual presence of defects and actual defect size and should be consistent with the following guidelines:
(1)
Separate sets of test samples (i.e., separate data sets) should be employed for each potential defect type. The data sets should include extraneous signals (e.g., denting signals, deposit signals, electrical noise, tube noise, calibration standard noise, signal to noise ratio) representative of those experienced in the field for a given flaw type.
(2)
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. This performance demonstration test for data acquisition and analysis should be blind.
(3)
The total and partial data sets for each defect type should contain a statistically valid sample of flawed and unflawed grading units large enough to permit POD performance, 16
probability of false call performance, and indication size measurement performance to be i
evaluated at an appropriate confidence level for the range of defect sizes of interest (i.e., defect j
sizes ranging from less than one-half of the tube repair criteria to sizes that would not meet the structural performance criteria). The appropriate confidence level should be that necessary to 4
permit the overall results of the operational assessment to be evaluated at 95% confidence (see Regulatory Position 4).
(4)
Each data set for a given defect type should consist of service-degraded tube j
specimens (i.e., tube 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 i
defects fabricated using mechanical or chemical methods provided it is firmly established in written j
f 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 defect type and geometry. In particular, fabricated defects should exhibit signal responses of similar voltage 4
amplitude, complexity, and signal-to-noise ratio as defects in the field with the same defect type i
and geometry. For example, electric discharge machining notches should not be used to i
represent stress corrosio'n cracks since electric discharge machining notches exhibit a higher voltage, higher signal-to-noise ratio, and more simple signal pattems than cracks.
(5)-
The defect detection, false call, and defect size measurement performance of NDE l
technique and NDE personnel for each grading unit should be evaluated against the actual j
presence of the defect and actual defect size. When indication size measurement variability is of i
interest, both technique variability and personnel variability should be determined.
i (6)
Records of the supplemental performance demonstration r.hould be maintained by the organization (e.g., vendor, utility) conducting the demonstration. There records should include j
the information listed in Regulatory Position 1.2.1. In addition, these records should include the l
POD, probability of false call, and indication size measurement error or variability results as j
necessary to support the information needed to conduct condition monitoring and operational assessment.
2.
PERFORMANCE CRITERIA FOR SG TUBE INTEGRITY i
These performance criteria are the benchmarks against which the tubes should be j
monitored and maintained in accordance with this regulatory guide. Satisfaction of these criteria ensures tube integrity; namely, that the SG tubes are capable of performing their safety functions 4
consistent with the licensing basis. These performance criteria address three areas of tube integrity performance: structuralintegrity, operational leakage integrity, and accident-induced j
leakage integrity.
t 2.1 Structural Performance Criteria 4
j 2.1.1 Deterministic Structural Performance Criteria All tubes should retain margins of safety against burst consistent with the safety factor j
margins implicit in the stress limit criteria of Section ll1 of the ASME Code (Ref. 2), as referenced in j
10 CFR 50.55a, for all service level loadings. Satisfaction of these criteria means that all tubes j
have been determined to retain a margin of 3.0 against gross failure or burst under normal plant 4
operating conditions, including startup, operation in the power range, hot standby, and cooldown, i
e 17 I
4 i
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 consistent with the margin of safety determined by the stress limits in NB-3225 of Section 111 of the ASME Code under postulated accidents concurrent with a safe shutdown earthquake.
2.1.2 Probabilistic Structural Performance Criteria Probabilistic criteria may be used as an alternative to the use of deterministic criteria based on ASME Code margins as part of an SGDSM program for specific defect types. However, the use of such criteria for a specific defect type constitutes a change to the licensing basis, since it involves a change to the margins of safety to be maintained against burst. Thus any proposed use of such criteria for a specific defect type must be submitted for NRC review and approval. The staff encourages such proposals to be risk-informed following the guidance provided in Regulatory Guide 1.174 (Ref. 8).
Proposed probabilistic criteria should not exceed the following:
1.
The frequency of SG tube bursts that occur as spontaneous, initiating events under normal operating conditions should not exceed 2.5x105 per reactor-year.
2.
The conditional probability of burst of one or more tubes under postulated accident
(
conditions should not exceed 2.5x102, The above criteria apply to the total tube burst frequency per plant and the total conditional l
probability of burst associated with all defect types affecting each steam generator. Frequency and conditional probability criteria applicable to any one defect type should not exceed 40% of the above values.
2.2 Operational Leakage Performance Criteria Operational primary-to-secondary leak rate should not exceed the limiting condition for operation (LCO) limits for primary-to-secondary leakage rate for any SG.
2.3 Accident Leakage Criteria l
l Calculated potential primary-to-secondary leak rate during postulated design basis accidents other than a steam generator tube rupture (SGTR) should not exceed the LCO leakage rate limits (in terms of both total leakage for all SGs and leakage from an individual SG).
Altemative accident leakage performance criteria may be applied to the component of calculated accident leakage associated with implementation of SGDSM programs described or referenced in the technical specifications. The balance of the calculated leakage rate (i.e.,
calculated leakage rate for defect types not addressed by SGDSM programs described or referenced in the technical specifications) should not exceed the LCO leakage limits. The use of alternative accident leakage criteria when implementing the SGDSM programs must be submitted as a proposed licensing basis change. The staff encourages licensees to follow risk-informed approaches when submitting such proposals following the guidance provided in Reference 8.
Risk-informed proposals should address accident leakage associated with implementation of all SGDSM programs to which the alternative leakage criteria will be applied. As a maximum, the attemative criteria should not exceed the accident leakage rate assumed in the licensing basis 18
accident analyses, minus the LCO limits for operational leakage. To accommodate the proposed leakage criteria, licensees may submit updated licensing basis accident analyses as part of the proposed licensing basis change as necessary to accommodate the proposed accident leakage criteria. Such a proposal should include a radiological assessment in accordance with Regulatory Position 9 to demonstrate that the consequences of design basis accidents meet the guideline limits in 10 CFR Part 100 for offsite doses, or some fraction thereof as appropriate to the accident, and GDC-19 criteria for control room operator doses. 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 (FSAR). For SGDSM programs associated with certain defect types, risk considerations may prove more limiting than dose considerations for purposes of establishing alternative accident leakage criteria. Thus, more restrictive accident leakage criteria may be necessary for the component of accident leakage associated with implementation of certain SGDSM programs.
For plants with technical specifications incorporating the flex methodology described in Regulatory Position 9, the performance criteria should not exceed the value given in the flex plot (see example plots in Figures 2-4) as a function of RCS dose equivalent "'I. Performance criteria based on flex are only applicable to defect types and associated SGDSM programs that were submitted as part of the proposed change to incorporate flex into the technical specifications. To extend the applicability of flex to other defect types and associated SGDSM programs, licensees must submit a new proposed change to the licensing basis. Again, for SGDSM programs associated with certain defect types, risk considerations may prove more limiting than dose considerations for purposes of establishing alternative accident leakage criteria. Thus, more restrictive accident leakage criteria may be necessary for the component of accident leakage associated with implementation of certain SGDSM programs.
3.
CONDITION MONITORING ASSESSMENT Condition monitoring involves monitoring and assessing the as found condition of the tubing relative to the tube integrity performance criteria. The as found condition refers to the condition of the tubes during an SG inspection outage, prior to any plugging or repair of tubes.
Failure of one or more tubes to satisfy the performance criteria may be indicative of programmatic deficiencies in the licensee's program for monitoring and maintaining SG tube integrity. Failure of one or more tubes to satisfy the performance criteria should be reported to the NRC in accordance with 10 CFR 50.72 and corrective actions should be implemented in accordance with Regulatory Position 6 prior to plant restart.
For an unscheduled inspection that is due to primary-to-secondary leakage, the condition rnonitoring assessment need only address the defect type that caused the leak provided the interval betwun scheduled inspections is not lengthened. (However, it will be necessary to estimate the contribution of accident leakage from the other active defect types, as determined from the most recent operational assessment for these defect types, to demonstrate that performance criteria for accident leak rate is met.)
Specific considerations relative to monitoring tube structural integrity, op> rational leakage integrity, and accident leakage integrity are presented in Regulatory Positions 3. e,3.2, and 3.3, respectively. Additional details concerning specific topics in these sections are addressed in Regulatory Position 3.4. The condition monitoring assessment is subject to the reporting criteria in Regulatory Positions 10.1 and 10.2.
19
3.1 Structural Integrity 3.1.1 Assessment Vis-a Vis Deterministic Performance Criteria Tube structural integrity may be monitored against the deterministic structural performance criteria of Regulatory Position 2.1.1 by analysis, based on the results of inservice NDE inspection, or by altemative means (e.g., in situ pressure testing) for each defect type. Tube structural integrity may be demonstrated by analysis for a given defect type if the NDE technique and NDE personnel are validated for sizing with respect to that defect type in accordance with Regulatory Position 1.2.2. The analysis approach involves demonstrating that the most limiting defects associated with each defect type, as determined from inservice inspection, do not exceed the appropriate structural limit for each defect type. Structural limit refers to the calculated maximum allowable defect size consistent with the safety factor performance criteria in Regulatory Position 2.1.1. The analysis should account for all significant uncertainties so that an indication measured by inservice NDE inspection to be at the structural limit satisfies the performance criteria with a probability of 0.95 evaluated at 50% confidence. Conservative bounding models and assumptions should be employed to account for uncertainties not directly treated in the assessment.
Potential significant sources of uncertainty include error or variability of NDE indication size measurement, material properties, and structural models. Considerations for assessing NDE indication size measurement error or variability are addressed in Regulatory Position 4.3.5.
Structural models (i.e., models relating burst pressure to actual defect si:'e or to measured indication size) may be empirical or analytical (i.e., idealized models based on engineering mechanics). Empirical models should be in accordance with Regulatory Position 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 defect types, analytical approaches to demonstrating tube integrity may be ineppropriate or inefficient because of an inability to size certain flaw dimensions, large error or variability associated with indication size measurements, or large uncertainties of the structural models. These difficulties may necessitate bounding approaches to ensure a conservative analysis, but they may lead to unrealistic (overly conservative) results. Other approaches, such as in situ pressure testing, may provide a more realistic assessment and may be used as an attemative to, or as a supplement to, the above analytical approach for a given defect type to demonstrate structuralintegrity in accordance with the performance criteria of Regulatory Position 2.1.1. Guidance for in situ pressure testing to demonstrate the performance criteria are met is provided in Regulatory Position 3.4.3.
3.1.2 Assessment Vis-a-Vis Probabilistic Performance Criteria Considerations for monitoring tube structural integrity against the probabilistic performance criteria of Regulatory Position 2.1.2 should include the following for a given defect type, Probabilistic approach should only be used when inservice inspection techniques and e
personnel are validated for detection and sizing in accordance with Regulatory Position 1.2.2.
20
i l
i t '
The as-found frequency distribution of indications as a function of indication size should be e
established. The as-found distributior, should be adjusted to consider the percentage of j
t tube (ocations sampled to address the subject defect type. The uncertainty of the as-found frequency distribution is characterized by consideration of indication size measurement error or variability in accordance with Regulatory Position 4.3.5.
Empirical models for burst pressure as a function of flaw size or indication size should be established. These models for burst pressure or failure load should account for data scatter and model parameter uncertainties and should also satisfy criteria in Regulatory l
Position 3.4.2.
The probability of burst calculation should account for uncertainties in indication size e
measurement error or variability, material procerties, and in the burst pressure model with 1
rigorous statistical analyses. Statistical sampling methods such as Monte Carlo may be used.
The frequency of burst and conditional probability of burst estimates should be expected j
(mean) value estimates.
3.2 Operational Leakage Integrity 1
Operationalleakage integrity should be monitored during plant operation in accordance with Regulatory Position 8.1.
3.3 Accident Leakage Integrity The potential primary-to-secondary leakage rate for the most limiting postulated design basis accident other than SGTR should be assessed, based on the as-found condition of the SG tubing, to confirm that the performance criteria for accident-induced leakage (Regulatory Position l
l 2.3) were met immediately prior to the outage. The potential leak rate may be determined by analysis, based on the results of inservice NDE inspection, or by attemative measures (e.g., in situ 1
pressure testing). The potential leak rate may be determined by analysis for a given defect type provided the NDE technique and NDE personnel have been validated for sizing in accordance with Regulatory Position 1.2.2. The potential accident-induced totalleak rate should be an upper 95%
. quantile estimate (one-sided) evaluated at 50% confidence, based on quantitative consideration of uncertainties affecting the estimate. Conservative bounding models and assumptions should be employed to account for uncertainties not directly treated in the assessment.
Key elements of a condition monitoring accident leakage assessment by analysis should include the following for each defect type.
The as-found frequency distribution of indications for each active defect type is established as a function of indication size. The distribution should be adjusted statistically to consider the percentage of tubes sampled to address the subject defect type.
Models relating the magnitude of leakage rate as a function of nctual flaw size or NDE e
j indication size measurement for each flaw mechanism are established.
1-The leakage calculation for each flaw and for total SG leakage rate is performed l
deterministically or probabilistically (e.g., with statistical sampling methods such as Monte 21
Carlo), accounting for all significant uncertainties. Potential sources of uncertainty include NDE indication size measuremer,: arror or variability, material properties, and leakage models. Considerations for assessing NDE indication size measurement error or variabiliy are addressed in Regulatory Position 4.3.5. Leakage models may be empirical or analytical (i.e., idealized models based on engineering mechanics). Empirical models should be in accordance with Regulatory Position 3.4.2 and should quantify significant model uncertainties such as data scatter and the parameter oncertainty 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.
In situ pressure testing in accordance with the guidelines in Regulatory Position 3.4.3 may be used as part of, or as an attemative to, condition monitoring by analysis for a given defect type.
Estimates of totalleak rate from the results of the in situ tests should assume no functional relationship between leakage rate and the NDE indication size measurement, unless there are sufficient data and a rigorous statistical basis for doing so in accordance with Regulatory Position 3.4.2. These estimates should be adjusted to reflect indications involving the subject defect type that were not subjected to the pressure tests. In addition, these estimates should reflect the percentage of tube locations sampled by NDE to address the subject defect type. 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. Altematively, a bounding estimate should be performed based on the available data. Total leak rate may be assumed to equal zero if no leaking tubt;s are observed during in situ pressure testing, assuming a sufficient number of tubes have been tested in accordance with Regulatory Position 3.4.3.2.
3.4 Special Considerations for Condition Monitoring Assessment 3.4.1 Loadings The following types of loadings should be considered.
1.
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 offsite power) that are included in the design specifications for the plant.
2.
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 not necessarily be limited to, consideration of the following sources.
Pressure differentials associated with loss of secondary system pressure impulse loads caused by rarefaction waves during blow-down e
Loads caused by fluid friction from mass fluid accelerations e
Loads caused by centrifugal fMce on u-bends caused by high velocity fluid motion 22
Loads caused by dyn.amic structural response of the steam generator components and supports e
Seismic loads Flow-induced vibration during blow-down from main steam line break (MSLB) 3.4.2 Empirical Models 3.4.2.1 Statistical Modeling. Empirical models may be used to establish the relationship between a tube integrity parameter (e.g., burst pressure or accident leakage rate) and defect size or NDE indication size. Development of empirical models should conform to principles of good statistical practice for purposes of establishing mean correlations and for quantifying the uncertaintiec associated with the mean correlation.
Empirical correlations should reflect a statistically sigr: ant set of data such that uncertainties associated with the correlation can be quantified. Ideally, the data should be relatively uniform over the range of flaw sizes ofinterest. If the data set are 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 leakage 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 defect or indication size (e.g., a linear regression fit of the data can be shown valid at the P = 0.05 level), if such " significance of correlation" cannot be rigorously demonstrated for leakage rate models, the regression fit of the leak rate data as a function of defect or indication size should be assumed to be a constant valu Empirical models for probability of leakage (POL), if used, 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 should be selected with care to ensure a conservative leakage assessment.
3.4.2.2 Test Specimens. Test specimens should consist of pulled tube specimens, as practical, when the tube integrity parameter (e.g., burst strength, accident leakage rate) is being correlated with actual defect size (e.g., defect depth, defect length). However, laboratory specimens (i.e., specimens with defects induced in the laboratory by mechanical or chemical j
means simulating the defect type of interest) may be used in lieu of or to supplement pulled tube
'i specimens when the laboratory defect can be expected to yield representative or conservative values of the tube integrity parameter for a given defect size.
Tube specimens from the field should be included as part of the data base when the tube integrity parameter is being correlated with an NDE indication size measurement (e.g., measured depth, measured voltage amplitude). Field specimens may consist of pulled tube specimens or installed tubing that is tested in situ; at least two field specimens from a given plant should be included as part of the data base Defore 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 23
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, in terms of both the nominal correlation and the indicated uncertainties associated with the correlation.
3.4.2.3 Testing issues. Laboratory test systems, including the test apparatus, instrumentation, and procedures, for measuring burst pressure and leak rate must satisfy the requirements of Appendix B to 10 CFR Part 50. These systems should accommodate and permit measurement of as high a leak rate as may be practical, including leak rates that may be in the upper taii of the leak rate distribution for a given defect 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 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 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 that prevent further pressurization. The pressure at the defect location could then be significantly less than the pressure at the supply location.
The actions necessary to produce a prototypic or conservative stress state at the flawed location, in terms of the stress components that have a dominant effect on burst at that location, should be considered in the application of a test system for a specific defect type. The fact that primary membrane plus bending stress from sources other than the pressure differential across the tube (see Regulatory Position 3.4.1, " Loadings") may be present under the most limiting postulated accident plus SSE conditions should also be considered. 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.
Leakage rate data should be collected at temperature for the differential pressure loadings associated with the limiting postulated accident. Leakage tests at temperature should include pressure control to ensure single phase flow inside the tube prior to exiting through the defect.
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 fudher as necessary to account for material propedy differences at temperature. In addition, thermal-hydraulic adjustments to the leakage data should be performed to reflect at temperature conditions.
Leakage tests, when it is not possible to reach and maintain the desired test pressure because of leakage through the defect in excess of the 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 nonconservative bias in the empirical model. Additional testing and analysis of the test specimen should be performed as necessary to extrapolate the expected leakage rate at the desired test pressure. One approach is to place a bladder over the leaking flaw and then pressurize the specimen to the desired test pressure. A further adjustment to the test pressure may be necessary to account for strengthening of the test specimen provided by the bladder.
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1 (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 mesaurement 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 data and correlations should be adjusted as necessary to reflect material property values at temperature. Burst data and correlations should also be adjusted 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 Regulatory Position 3A.3.
3.4.2.4 Data Management issues. Each empirical model should be supported by a data management system that ensures data records are 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. When an empirical model for a specific defect type is based on pulled tube or laboratory flaw data, the relevant data include all such data obtained for each plant and for the range of defect sizes for which the empirical model will be applied.
Available in situ pressure test results need not be included as part of the data base. However, such data should be evaluated to ensure that they are statistically consistent with the data from the pulled tube orlaboratory flaw data.
Valid reasons for excluding relevant data are limited to the following:
1.
Data are associated with an invalid test. Note that this criterion does not apply when tests are systematically invalid for the most extreme data. For example, failure to attain the desired test pressure because of excessive specimen leakage is a " systematically" invalid test rather than a " 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.
2.
Data are associated with atypical morphology based on morphology criteria that are defined rigorously and applied to all data, and these criteria can be unambiguously applied by an independent observer provided (1) the model can be conservatively applied to flaws exhibiting th 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 criterion should not be applied when the supporting data base depends in part on in situ pressure test results.
3.
The 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.
3.4.3 in Situ Pressure Tests 25
The tollowing 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.
3.4.3.1 Methodology. Regulatory Position 3.4.2.3 provides general guidance concerning the conduct of leakage and burst testing. This section supplements the guidance in Regulatory Position 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 that the subject tubes satisfy the structural and accident-induced leak rate performance criteria in Regulatory Position 2. In situ pressure testing, including the test apparatus, instrumentation, and procedures are subject to the requirements of Appendix B to 10 CFR Part 50.
A structural assessment should be performed and maintained, or cited by reference, -
part of the test record for each application (i.e., defect type) demonstrating that the test is capar of producing a stress state at the flawed section of tubing that is equivalent to, or a conservative bound of, the actual stress state during normal operation and postulated accident conditions mult; plied by the appropriate factor of safety in accordance with Regulatory Position 2.1.1. When the actual limiting stress state includes bending stress (e.g., from loss-of-coolant accidents (LOCA) or a safe shutdown earthquake (SSE), the corresponding test pressure should be adjusted as j
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 actual temperature during postulated accidents. The design of the test apparatus and test pressures must also consider, as necessary, any fixity between the tubes and tube support plates caused by the buildup of corrosion products to ensure that the appropriate 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 Regulatory Position 3.4.2.3. If it is not possible to achieve the desired pressure level because of leakage through the flaw in excess of the makeup capacity of the test system, additional testing and analysis should be conducted in accordance with Regulatory Position 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 in Regulatory Position 3.4.2.3.
3.4.3.2 Tube Selection. The sample size and selection of tubes for in situ pressure testing should 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 of the inservice NDE inspection results in terms of the indication size measurements. The size of the sampie should be determined on the basis of the NDE sizing performance as demonstrated during the NDE validation so that there is reasonable assurance that the most limiting tubes are included in the sample. When NDE sizing performance has not been validated, the initial sample size should be at least 10 tubes, ast.uming there are at least 10 tubes identified as being affected by this mechanism. A second sample consisting of the second ten potentially most limiting tubes (assuming there are at least an additional 10 affected tubes involving this mechanism) should also be tested to confirm that the most limiting tubes from a burst and leakage standpoint were included in the first sample. If not confirmed by the second sample, a third sample, and if necessary 26
subsequent samples, should be tested until there is reasonable assurance that the most limiting tubes have been tested.
4.
OPERATIONAL ASSESSMENT An opr rational assessment thould be performed to demonstrate that the performance criteria of Regulatory Position 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 Regulatory Position 6 should also be performed as necessary to meet this objective. The operational assessment and implementation of the resulting corrective actions should be 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 l
to performing tube plugging or repairs to ensure that the tube repair criteria being implemented are i
sufficient to support operation for the planned operating interval preceding the next scheduled steam generator inspection.
j For an unscheduled inspection that is due to primary-to-secondary leakage, the operational assessment need only address the defect type that caused the leak provided the scheduled interval between inspections remains unchanged and provided the leakage was not caused by a factor that would affect prior operational assessments performed for the other defect types.
Specific considerations for performing an operational assessment of tube structural integrity and accident leakage integrity are provided in Regulatory Positions 4.1 and 4.2, respectively. The performance criteria in Regulatory Position 2.2 for operationalleakage inte;;Gy does not apply to the operational assessment of this section. Additional details conceming specific topics in these sections are addressed in Regulatory Position 4.3.
4.1 StructuralIntegrity 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 limiting tubes immediately prior to the next scheduled inspection satisfies the deterministic criteria of Regulatory Position 2.1.1 for each defect type. Conceptually, this involves demonstrating that the projected limiting defect sizes or indication sizes do not exceed the appropriate "structurallimit" for each degradation mechanism. Equivalently, this can involve demonstrating that the projected limiting defects for each defect type will exhibit burst-strength capacities consistent with the criteria of Regulatory Position 2.1.1. The assessment methodology should account for all significant uncertainties so that, should the most limiting projected defect or indication size be at the calculated structural limit immediately prior to the next scheduled inspection, the defect or indication satisfies the performance criteria with a probability of 0.95 evaluated at 95% confidence.
The assessment methodology may be performed deterministically or probabilistically (e.g., with statistical sampling methods such as Monte Carlo). Conservative bounding models and assumptions should be employed to account for uncertainties not directly treated in the assessment.
Potential sources of uncertainty include significant uncertainties associated with the projected limiting defect or indication size, material properties, and structural model. General 27
considerations for projecting the most limiting flaw sizes associated with each defect type, including the uncertainty associated with these projections, include the following.
The frequency distribution of indications left in service as a function of indication size e
The frequency distribution of indications (as a function of indication size) found during the mort recent past inspection of tubes that were not repaired or plugged at that time and that art not being inspected during the current inspection e
The frequency distribution of defect or indication growth rates determined in accordance with Regulatory Position 4.3.3 as a function of indication size e
The rate and size distribution function of new indications as a function of time between inspections in accordance with Regulatory Position 4.3.4 The probability distribution of NDE sizing error or variabi'ity determined in accordance with Regulatory Position 4.3.5 The level of sampling performed during the current inspection and date of last inspection e
for uninspected tubes.
i Note that the above considerations for projecting the limiting defect or indication size are based on the premise that NDE technique and personnel are validated for sizing in accordance with Regulatory Position 1.2.2 for the subject defect type. If this is not the case, altemative or conservative bounding approaches must be taken as discussed later in this Regulatory Position.
Specific details for projecting the maximum defect or indication size are to be developed by licensees. The evaluation of the performance of the predictive methodology in projecting the maximum defect or indication size should be 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 defect or indication size may be empirical or analytical (i.e., idealized models based on engineering mechanics). Empirical models should be in accordance with Regulatory Position 3.4.2 and should quantify significant model uncertainties such as burst pressure data scatter and the parameter uncertainty of the empirical frt.
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 because of an inability to size certain flaw dimensions, large error or variability associated with defect or indication size measurements, or large uncertainties of the structural models. These difficulties may necessitate bounding approaches to ensure a conservative analysis. Appropriate bench marking of the assessment against the results ofin situ pressure tests performed during condition monitoring may provide a means for mitigating excessive conservatism. However, the development of NDE techniques with good probability of detection and sizing performance and more precise structural models is key to ensuring a realistic operational assessment and avoiding unnecessary corrective actions (including operational res'trictions).
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_. _ ~ _ _ _ _ _ _. _ _ _ _ _ _ _ _.
4.1.2 Assessment Vis-a Vis Probabilistic Performance Criteria Considerations for performing the operational assessment against the probabilistic performance criteria of Regulatory Position 2.1.2 for structural integrity should include the following for a given defect type.
The probabilistic approach should only be used when inservice inspection techniques and personnel are validated for detection and sizing in accordance with Regulatory Position 1.2.2.
The calculation of the frequency distribution of defects or indications should be by the size projected to exist immediately prior to the next scheduled inspection based on the considerations identified in Regulatory Position 4.1.1. The specific details for projecting the distribution of defect or indication sizes are to be developed by licensees. The
{
performance of the predictive methodology that projects a distribution that results in a conservative estimate of conditional probability of burst 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.
The empirical burst pressure should be established as a function of defect or indication e
size. These empirical models should account for data scatter and model parameter uncertainties and are subject to the special considerations in Regulatory Position 3.4.
The projected distribution of defect or indication sizes, the calculated frequency of burst, and the calculated coreditional probability of burst during postulated accidents should I
include a rigorous statistical treatment of all significant sources of uncertainty affecting the calculation, including growth rate, indication size measurement, and burst-pressure model.
Statistical sampling methods such as Monte Carlo may be used.
j The frequency and conditional probability of burst should be evaluated at the one-sided, e
upper 95% confidence level.
j 4.2 Accident Leakage integrity The potential SG primary-to-secondary leakage rate during the most limiting postulated accident (other than SGTR) should be assessed relative to the performance criteria for accident leakage integrity in Regulatory Position 2.3, based on the frequency distribution of defects i
or indications as a function of defect or indication size projected to occur immediately prior to the next scheduled SG inspection outage. The calculated potential accident leakage rate should be
[
an upper 95% quantile estimate (one-sided) evaluated at 95% confidence, based on quantitative i
consideration of uncertainties affecting the estimate. Conservative bounding models or assumptions should be employed to account for uncertainties not directly treated in the assessment.
}
General considerations for projecting the frequency distribution of defects or indications as a function of defect or indication size, including the associated uncertainties, are the same as j
those identified in Regulatory Position 4.1.1 for projecting the most limiting defect or indica-i tion size. Considerations for establishing the magnitude of leakage for each defect type as a j
function of flaw or indication size are the same as those identified in Regulatory Position 3.3.
29
2 For certairi defect types, operational assessment methodologies may be in efficient because of an inability to size certain defect dimensions, large error or variability in the NDE defect or indication sizing measurements, or large uncertainties of the leakage models. These difficulties may necessitate bounding approaches to ensuru a conservative analysis. Appropriate bench marking of the assessment against the results of in situ pressure tests performed during condition monitoring may provide a mesas for mitigating excessive conservatism. However, the 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).
4.3 Special Considerations for Operational Assessment l
4.3.1 Loadings See Regulatory Position 3.4.1.
4.3.2 Empirical Models See Regulatory Position 3.4.2.
4.3;3 Defect Growth Rates Defect growth rates over the next inspection interval must be estimated for each defect type for purposes of projecting defect or indication sizes or size distributions expected to exist prior to the next scheduled inspection. These projections are used as part of operational assessments performed in accordance with Regulatory Position 4. The growth rate estimates can be based on
,~
inservice inspection results or on laboratory data and models. If the growth rate estimates are based on laboratory data and models, it should be shown that the test conditions for the laboratory tests are prototypical for the locations of interest or bound (i.e., are more aggressive) and for the conditions at the location of interest and that the models are conservative or bounding. The conditions that should be considered include primary and secondary water chemistry, crevice chemistry, residual and applied stresses, tube alloy microstructure, and operating temperature.
The models may describe the crack growth rates in terms of probability distributions provided that the model accounts for the upper tail of the measured or observed crack growth rates. Ifinservice i
inspection results are used, these growth rate estimates should be based on the inservice l
inspection results from the most recent inspection and the previous one or two inspections. The inservice inspection results for a given defect type may be used where the NDE techniques and personnel used to obtain these results were validated for sizing in accordance with Regulatory Position 1.2.2. If the NDE technique and personnel do not satisfy this provision, ladications 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 Regulatory Position 5 Under
. these circumstances, the projected flaw size distribution prior to the next scheduled inapection will be determined primarily on the basis of the observed " rate and size of new indications" (see Reguitory Position 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 indica ion size between inspections when there is a detectable indication during both inspections (growth l
implications of new indications are addressed in Regulatory Position 4.3.4). These growth rates should be adjusted as necessary to reflect any increase or decrease in the length of the time I
' interval between scheduled inservice inspections. For a given indication found during the latest 30 i.
L L
inspection, the previous inspection results for the subject location should be evaluated with the NDE data analysis guidelines for the defect type being evaluated. If the dat guidelines employed during the previous inspection differ from those employed during t 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 a procedures (including probes and equipment) to the extent there is a technical basis fo When this is not possible, the locations of the indications (or a large sample of thes should be reinspected using the previous data acquisition procedures so that results can be compared directly to the previous inspection results. It is desirable that the same analyst be u to evaluate the data from the latest and previous inspections for a given location for purp assessing incremental flaw growth.
It is acceptable to supplement plant-specific growth data with applicable data from other units when plant-specific data is scarce for a given degradation mechanism. The data ap from other units should be consistent w:th or conservative with respect to available plan data regarding average and bounding growth rates. Other considerations conceming the applicability of data from other plants include, for primary-side-initiated stress corrosion similarities in inconel microstructure, primary water chemistry, relevant design features (
residual stress levels associated with tube expansions cnd u-bends, sleeve design), level of denting, and operating temperature. Other considerations for secondary-side-initiated corros include similarities in secondary water chemistry, crevice chemistry, thermal and hydraulic environment, inconet 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 distribution, negativ growth rate samples should be treated as zero growth rate.
Probability distributions of growth rates constructed directly from comparative inspection results will tend to be contaminated by NDE indication size measurement error or variability, will tend to extend the tails of the distribution in both directions. It is conservative to ignore this contamination when the measurement error or variability is random. Altematively, appropriate statistical methods may be employed to separate out the contribution of measurement error or variability. However, the deconvolved distribution attributable to measurement error or vari should be evaluated to ensure that it is consistent and fully accounted for in what is being assumed for NDE measurement error in Regulatory Position 4.3.5.
4.3.4 Rate and Size of New Indications The frequency distribution of indications as a function of indication size projected to exist prior to the next scheduled inspection consists of two groups of indications. The first group consists of defects found by inservice inspection that are being permitted to remain in service to plant restart and that may grow. 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 indication growth rates. The second group of projected indications consists of defects that have not been detected by inservice inspection prior to pla restart. These indications have not been detected because either (1) defects are present but have not been detected by inservice inspection or (2) defects do not initiate until after plant restart.
31
- - - - - - - - - _ _ _ _ _ - - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ ~ - - - - - - - _ - _ _ _ _ _
Failure of inservice inspection to detect defects that are present can be due to eithe; ', the subject tube has not been inspected at the flaw location or (2) the tube has been inspected, but the defect has not been detected because of NDE technique or personnellimitations. Methodologies should be developed for each defect type for projecting the frequency distribution of indications associated with the second group of indications (i.e., indications not detected during the current inspection). 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 (i.e., number per inspection interval) 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 size distribution, on the NDE technique being validated for sizing with respect to the subject defect type. 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 indreig experience. The previously observed size distribution of new indications may be fitted with a statistical model that conservatively accounts for the upper tail of the distribution so that the distribution may be scaled to reflect the expected number of new indications.
When the NDE technique and NDE personnel are not validated for sizing, attemative approaches may be taken to project 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 may be used to estimate defect sizes equivalent to the observed burst pressures or to conservatively bound the defect sizes based on the maximum test pressures achieved where no burst was observed. The projected bounding values of defect 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.
4.3.5 NDE Indication Sizing Error or Variability The probability distribution of NDE indication size measurement error or variability may be determined from the performance demonstration data for NDE techniques and NDE personnel obtained during the validation process in accordance with Regulatory Position 1.2.1.
Consideration should be given to whether the indication sizing performance quantified during the validation process can be improved through 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 defect types, NDE technique, data analysis procedures, and procedures relating to how the independent analyses are performed and discrepancies resolved).
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 indications that fail to satisfy the applicable tube repair criteria for the subject defect type. All indications should be considered defective, unless these indications have been sized with NDE techniques and NDE personnel that have been validated for sizing. Guidelines for the development of tube repair criteria are given in Regulatory Position 5.1 below. Guidelines 32
concerning the development of plugging and repair methodologies are given in Regulatory Position 5.2.
5.1 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 plugging or repair will exhibit adequate tube structural and leakage integrity, consistent with the performance criteria of Regulatory Position 2, with appropriate allowance for NDE indication size measurement error or variability and for defect growth prior to the next scheduled inspection.
The tube repair criterion for each defect type should be 40% of the nominal tube wall thickness, subject to demonstrating by operational assessment in accordance with Regulatory Position 4 that the performance criteria in Regulatory Position 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.
Licensees may submit proposed changes to the technical specifications to permit implementation of alternative repair criteria (ARC) for specific defect types as part of an SGDSM strategy. Proposed changes should be risk-informed and give appropriate consideration to defense in depth (i.e., the containment function of steam generator tubes). SGDSM is an integrated approach aimed at ensuring that the performance criteria are met until the next scheduled inspection. SGDSM consists of a specific inservice inspection program (with specified frequency and level of sampling, specified qualified or validated NDE techniques) consistent with Regulatory Position 1 and specific condition monitoring and operational assessment methodologies consistent with Regulatory Positions 3 and 4. 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 that is consistent with ensuring tnat the performance criteria for tube integrity are met until the next scheduled inspection. Guidelines for submitting a proposed licensing basis change (including technical specification change) that is risk-informed are provided in Reference 8.
5.2 Tube Plugging and Repair Methods Plugging and repair methods must be developed, qualified, and implemented in accordance with the applicable provisions of the ASME Code (Ref. 2) and Appendices A and B to 10 CFR Part 50. 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 ' J included as part of the operational assessment of Regulatory Position 4. Plugs and repaired portions of tubing should be inspectable with appropriate NDE techniques and personnel as described in Regulatory Position 1.2.
6.
CORRECTIVE ACTIOb Failure of condition,
enng to confirm that the performance criteria have been satisfied should lead to the following actions pric to plant restart from the insrsection outage.
Assessment of causal factors such as I
33
New or unexpected degradation mechanism or defect type Insufficient sample sizes for tube inspection e
Unexpectedly high crack growth rates e
Performance of NDE techniques or NDE personnelis less than expected e
Deficiencies in predictive methodology for condition maintenance assessment (e.g.,
e inadequate treatment of uncertainties).
implementation of corrective actions such as e
e Shortened inspection interval e
Water chemistry enhancements e
Chemical cleaning e
Reduction of hot leg temperature Design modifications e
e Larger tube inspection samples improved inspection techniques (to enhance probability of detection and sizing e
performance)
Enhanced training of NDE personnel e
e More restrictive tube repair criteria Enhanced monitoring of operational leakage e
e Reduced coolant iodine activity limits Enhancements to predictive methodology for operational assessment e
Note that the adequacy of these corrective actions to ensure that the performance criteria will be maintained prior to the nr,xt scheduled inspection should be confirmed as part of the operational assessment in Regulatory Position 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 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 Regulatory Position 2, actions should be taken as necessary so that the operational assessment confirms that the performance criteria will be satisfied throughout the operating cycle until the next scheduled inspection.
7.
PREVENTIVE MEASURES Preventive measures should be developed and implemented to minimize the potential for tube degradation and to mitigate active degradation mechanisms and defect types in accordance with the guidelines 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 Regulatory Positions 3 and 4, respectively.
7.1 Secondary Water Chemistry Program Licensees should have a program for monitoring and control of secondary water chemistry to inhibit secondary side corrosion-induced degradation. This program should include e
identification of all critical variables 34
identification of a sampling schedule for the critical variables and control points for these e
variables Identification of the procedures used to measure the values of the critical variables Identification of process sampling points, which should include monitoring the discharge of the condensate pumps for evidence of condenser in-leakage Procedures for the recording and management of data t
Procedures for defining corrective actions for all off-control point chemistry conditions A procedure identifying the authority responsible for the interpretation of the data, and 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 10 when developing or updating their programs.
7.2 Loose Parts and Foreign Objects I
Licensees should have a program for monitoring and control of loose parts and foreign objects to inhibit fretting and wear degradation of the tubiry as follows.
7.2.1 Secondary Side Visualinspections The program should include secondarv :,ide visual inspections. 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 that are found should be removed from the SGs, unless it is shown by evaluation (to be maintained as part of the inspection record) that these objects pose no potential for darr.ging the SG tubing or any other part of the seconda'y system. Tubes found to have visible damage should be inspected i
i nondestructively and plugged or repaired if the tube repair criteria in Regulatory Position 5 are not satisfied.
7.2.2 Control of Loose Parts and Foreign Objects The program should include procedures that are effective in precluding the introduction of l
loose parts or foreign objects into either the primary or secondary side of the SG whenever it is l_
opened (e.g., for inspections, maintenance, repairs, modifications). Such procedures should include (1) detailed accountability procedures for all tools and equipment used during an operation, j
(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 i
intemals of major components (e.g., reassembly of cut and removed components).
7.3 Measures To Mitigate Active Degradation Mechanisms 4
Licensees should consider developing and implementing, at their discretion, additional measures to mitigate active degradation mechanisms and defect types. Examples of such measures include providing for improved condenser integrity, minimizing air in-leakage into the 1
1 l-35 l
secondary system, eliminating copper-bearing alloys from the feed train, chemical cleaning, boric acid treatments, and operating with a reduced hot leg temperature.
8.
OPERATIONAL PRIMARY-TO-SECONDARY LEAKAGE MONITORING AND LIMITS 8.1 Leakage Monitoring Primary-to-secondary operational leakage monitoring is an important defense-in-depth measure that can assist plant operators in monitoring tube integrity during operation. Leakage monitoring also gives operators information needed to safely respond to situations in which tube integrity becomes impaired and significant tube leakage, rupture, or burst occurs.
The objectives of leakage monitoring are (1) to provide clear, accurate, and timely information on operationalleakage to allow timely remedial actions to be taken to prevent tube rupture and burst and (2) to provide clear, accurate, and timely information to facilitate the mitigation of any tube rupture or burst 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 SG tube rupture and burst. 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 is the ability of operators to appropriately 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. The program elements considered by the NRC staff to contribute to meeting the stated leakage monitoring objectives are discussed below. These elements have been shown to be important by the corrective actions taken following tube leakage or rupture events.
8.1.1 Monitoring Strategy Each monitoring method has limitations, and therefore, no single means of detecting primary-to-secondary leakage nor single monitored pathway or 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, Nitrogen-16 monitor of leakage rates and change in leak rate over time) gives operators real-time information that 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 N-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 36
I 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 half-life 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.
Licensees should evaluate the monitoring methods available based on factors such as those in guidance provided by EPRI Report TR-104788, "PWR Primary-to-Secondary Leak Guidelines"(Ref.11). Detection capability and measurement unce tainties are discussed in the guidance, as well as the characteristics of certain monitoring methods. This is useful to licensees in determining 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 plant 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 ba limited or unavailable. For instance, the radionuclide mix is altered following a period of plant shutdown so that condenser offgas 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 time to respond to the situation before the plant reaches full power operation, when the conseq' ences of u
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 rupture or burst of the tubing.
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 (Ref.
- 11) 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 EPRI guidelines provide l
a framework that licensees can use to formulate preplanned 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 ofindications of slowing leak 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 j
37 o
)
i I
more than a single indication as the basis for concluding that leak rates have stabilized. A similar l
approach, of confirming leak rates prior to declaring a leakage condition, is applied to Action Level j
2 (i.e., leak rate requiring plant shutdown) in the EPRI guidelines (Ref.11).
i l
8.1.3 Operator Training i
As much as practicable, training scenarios should include various types of leakage progressions based on actualleakage events. The characteristics of specific plant monitorhg l
instrumentation should be considered when providing operator indications for training purposes.
The EPRI guidelines offer some assistance to licensees in formulating appropriate j
simulator scenarios. However, licensees should ensure that information gained throughout the i
industry by operation with primary-to-secondary leakage or from tube rupture events is used in training programs. Operator training should accurately reflect the expected indications and plant j
responses for the partlcular plant during a progressing tube leak that may develop into tube rupture or burst. Various plant conditions and failures of various key indicators should be j
considered when devising training scenarios.
4' 8.1.4 Program Updates and Self-assessment i
1 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.
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.
8.2 Technical Specification LCO Leakage Limits The technical specifications should include an LCO limit with respect to the allowable primary-to-secondary leakage rate through any one SG, beyond which prompt and controlled shutdown must be initiated. An acceptable LCO limit is 150 gallons per day. Altematively, this limit should be established so 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 Regulatory Position 2.1.1. Predictive models, including the treatment of uncertainties, for assessing structural integrity performance relative to the structural performance criteria should be in accordance with Regulatory Position 3.1.1. Sources of uncertainty that should be considered include burst pressure and leak rate as a function of crack length and material properties.
38
The technical specifications should include, if necessary, an LCO limit with respect to the L
j allowa' ole total primary-to-secondary leak rate through all SGs, beyond which prompt and I
controlled shutdown must be initiated. (Such a limit is not necessary if its value would exceed the l
maximum total leakage rate that is permitted by the LCO leakage limit for individual steam generators.) This limit should be established such that total leakage in all steam generators equa to this limit under normal operating conditions would be expected to satisfy the performance l
criteria for accident leakage integrity in Regulatory Position 2.3. Predictive models, including treatment of uncertaintes, should be in accordance with this Regulatory Position 8.2.
8.3 Procedural Limits on Operational Leakage Procedural limits for allowable leak rate and the allowable rate of increase in lea should be established to ensure that the performance criteria for operationalleakage are not exceeded. These limits, when used in conjunction with a leak rate monitoring program in accordance with Regulatory Position 8.1, are intended to ensure that appropriate and timely actio will be taken to ensure that leaking tubes, including tubes undergoing rapidly increasing leak ra satisfy the performance criteria for operationalleakage in Regulatory Position 2.2. The Action Level 1 and 2 criteria and recommended actions in the EPRI primary-to-secondary leak guideli (Reference 11) provide an acceptable approach with the exception that the >150 gallons per criterion in those action levels may need to be revised consistent with the above objectives.
l l
9.
RADIOLOGICAL ASSESSMENT l
A radiological assessment in accordance with the guidance of this Regulatory Position is i
necessary to support any change to the performance criteria in Regulatory Position 2.3 for i
accident leakage.
l The operational leakage and accident leakage performance criteria in Regulatory Position l
2.3 are intended, in part, to ensure that the plant is maintained in a condition consistent with what has been analyzed as part of the licensing basis. Consequences of postulated design basis accidents must be shown to satisfy two conditions. First, the offsite consequences of accidents must not result in doses that would exceed the guideline doses of 10 CFR Part 100, or fraction thereof, as defined in Table 1. Second, the accident must not resuit in releases that would cause l
the dose to control room operators to exceed the guidelines of GDC-19 of Appendix A to 10 CFR Part 50.
A steam generator tube rupture (SGTR) event is one of a number of the design basis accidents that are analyzed as part of a plant's licensing basis. In the analysis of a SGTR event, a bounding primary-to-secondary leakage rate equal to the operational leakage rate limits in the i
technical specifications plus the leakage rate associated with a double-ended rupture of a single tube is assumed. 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).
However, in all cases these analyses typically assume that the tubes will exhibit primary to-secondary leakage that is at the operational leakage limit allowed by technical specifications.
Limiting operational leakage to within the leakage limits in the technical specifications does not ensure that the total primary-to-secondary leakage will not exceed the operational limits during postulated accidents such as an MSLB. Under certain accident conditions, additional primary-to-secondary leakage beyond that of the operationallimits may be induced when tubes with deep or 39
~
entirely through-wall defects are present in the SGs. For example, a deep, part-through wall crack may propagate entirely through-wall under the increased pressure differential associated with a design basis MSLB, leading to leakage of the affected tube during the accident. As another example, an entirely through-wall crack that is leaking at a rate equal to the technical specification operational leakage rate limits may develop an increased crack opening area under the increased pressure differential associated with an MSLB, leading to leakage during the event in excess of the operationalleakage limits. The presence of such defects may occur inadvertently as a consequence of tubes not having been inspected during the most recent inspection, defects escaping detection during inspection, or of high defect growth rates. In addition, the presence of such defects may occur as a mader of policy by implementing attemative tube repair criteria.
Altemative repair criteria may permit up to entirely through-wall defects to remain in service provided (1) the tubes retain acceptable structural margins against burst, (2) leakage from the tubes during normal operation is not in excess of the technical specification operational leakage limits, and (3) the calculated potential accident leakage rate does not exceed that which was assumed in the accident analyses.
The consequences of design basis accidents such as MSLB, SGTR, rod ejection, and locked rotor are, in part, functions of the dose equivalent'8'l in the primary coolant and the accident primary-to-secondary leakage rates. Limits are included in the plant technical specifications for operational leakage and for dose equivalent'3'l in primary coolant to ensure the plant is operated within its analyzed condition. For most PWRs, the SGTR accident is usually the limiting design basis event that establishes techqical specification limits for the maximum instantaneous and the 48-hour values of dose equivalent' 'l in primary coolant and the operational leakage limit. The typical analysis of this accident and other accidents, such as the locked rotor, rod ejection, and MSLB, assumes that primary-to-secondary leakage is at the operational leakage limit of 1 gallon per minute, and that the reactor coolant activity levels of dose equivalent'3'l are at the technical specification values for maximum instantaneous, and the 48-hour levels are 60 Ci/g and 1 Ci/g for the pre-existing and accident-initiated spike cases, respectively.
Tubes must be plugged or sleeved when they are found by inspectioTto contain defects with a measured size that exceeds the applicable tube repair criteria. Either action, plugging or sleeving, results in a reduction in the heat removal capability of the SGs. If a sufficient number of tubes are plugged or sleeved, the unit will be dereted. Consequently, licensees have an incentive to maintain as many tubes in service as possible for as long as possible. The use of alternative tube repair criteria provides one strategy for allowing tubes with indications to remain in service, while maintaining structural and leakage integrity. However, the benefit that may be gained l
through implementation of attemative repair criteria is, in part, a function of the performance criteria against which accident leakage integrity of the tubing is evaluated. The higher the performance criteria associated with implementation of the attemative repair criteria, the more tubes that may be permitted to remain in service. Permitting such tubes to remain in service presents an opportunity for accident leakage to progress to a state that it exceeds the operational leakage limits assumed in the licensing basis for the previously referenced accidents. When this occurs, a new licensing basis analysis must be performed at the increased accident leakage rate. If reanalyses of these design basis accidents at these increased accident leak rates show that the offsite and control room operator doses would exceed the dose criteria of Part 100 (or some fraction thereof) or GDC-19, the licensee must take certain actions to reduce the potential consequences of accident.
Either the accident leakage or the maximum instantaneous or the 48-hour values of dose equivalent 1-131 in primary coolant can be reduced. However, since the actions being taken are focused on allowing accident leakage to increase, the preferred action taken by licensees is to 40
decrease the allowable activity levels of either or both maximum instantaneous or 48-hour values of dose equivalent 1-131 in reactor coolant, as appropriate.
The typical evaluation of design basis accidents, other than an SGTR, involving primary-to-secondary accident leakage assumes that the accident leakage rate is equal to the operational leakage limits in the technical specifications. Thus, the appropriate performance criteria for these units for accident leakage are value s equal to the operationalleakage limits. Increasing these performance criteria to allow for accident-induced leakage beyond the operational leakage rate limits in the technical specifications may provide licensees with added operational flexibility.
Licensees may submit a proposed change to the licensing basis updating the dose analysis to accommodate such an increase in the accident leakage performance criteria. This may necessitate including a proposed change to the LCO limits for dose equivalent I-131 in the primary coolant. The staff encourages licensees to follow risk-informed approaches when proposing such changes utilizing the guidance in Reference 8. The risk implications of implementing a higher accident leakage performance criteria are generally defect type and SGDSM-specific. Therefore, the risk-informed proposals should address each defect type and accompanying SGDSM approach to which the revised performance criteria will be applied.
For earlier-licensed plants, the licensing basis, as reviewed and approved by the NRC in its safety evaluation report (SER), does not include a radiological dose assessment of the consequences of a MSLB, SGTR, locked rotor, or control rod ejection accident. Instead, the reactors were given technical specifications for the maximum instantaneous activity level of dose equivalent I-131 and a 48-hour value of dose equivalent 1-131 in reactor coolant along with a maximum activity level for dose equivalent I-131 in the secondary coolant and a maximum primary-to-secondary leak rate. For these plants, the SER stated that it was the NRC's position that the establishment of these technical specification limits would ensure that the doses resulting from accidents involving SGs 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 calculated potential for accident leakage does not exceed values equal to the technical specification operational leakage limits during postulated accidents other than an SGTR. However, licensees must submit a proposed change to the licensing basis accident analyses to support increasing the accident leakage performance criteria above the operationalleakage limits for these plants. Such a proposed change should be supported by a radiological assessment. Risk-informed proposals should address each defect type and accompanying SGDSM approach to which the revised performance criteria will be applied.
Following NRC acceptance and approval of a licensing basis change involving a new radiological dose assessment, the description of the new accident and its consequences must be incorporated into the licensee's updated Final Safety Analysis Report (FSAR).
9.1 Dose Calculation Methodology Licensees may select one of two methodologies for performing a radiological assessment to support the use of increased performance criteria for accident leakage above values equal to the technical specification operational leakage limits. Both calculational methodologies are deterministic in nature. The first method is referred to as the default or SRP approach. This method utilizes the concepts presented in 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 i
15.6.3, Radiological Consequences of Steam Generator Tube Failure (PWR). These SRPs may 41
d be utilized for calculating the doses resulting from a MSLB, locked rotor, rod ejection, and an SGTR accident, respectively.
The second calculation method that may be used is referred to as the hex methodology. In this methodology a set of calculations are performed with both accident leakage and dose equivalent 1-131 varying, rather than being fixed. The flex methodology incorporates the same accident dose methodology as presented for the default approach, but a number of different cases are evaluated for each application, which allows licensees to establish a piot of maximum allowable primary-to-secondary accident leak rate as a function of the maximum instantaneous and the 48-hour values of reactor coolant activity levels of dose equivalent 1-131. These plots are based upon the limiting accident scenario. Based upon the projected accident leakage for the next operating cycle (as determined by operational assessment in accordance with Regulatory Position 4), licensees may choose to limit the maximum instantaneous reactor coolant activity level of dose equivalent 1-131 and the 48-hour value of dose equivalent 1-131 so that the accident leakage performance criterion can be met or licensees can limit leakage by choosing to sleeve or plug tubes. Further details on this methodology are provided below.
9.1.1 Default Methodology This methodology can be utilized for the various design basis accidents that are detailed in SRP Sections 15.1.5,15.3.3-15.3.4,15.4.8, and 15.6.3. This methodology assumes that the reactor coolant activity level of dose equivalent 1-131 is at the technical specification limit and the leak rate is equal to the proposed performance criterion value. The assumed accident leakage associated with this methodology is fixed and is usually intended to bound the accident leakage rate that may be calculated during operational assessments for future operating cycles. To date, the degradation mechanisms that have been identified in SGs are irreversible and no treatment has yet been identified which will prevent the mechanisms from continually propagating throughout the generator. Consequentially, licensees find that the number of degraded tubes in the steam generators increase witn each operating cycle. The degradation reaches a point at which, in the event of an accident, the anticipated primary-to-secondary leakage (accident leakage) from these tubes exceeds the licensing basis primary-to-secondary leakage. Usually, this leakage is limited to 1 gpm from all SGs. To accommodate the increased accident leakage, the licensee submits to the NRC staff, for review and approval, a revised accident analysis that incorporates this new value for accident leakage. To implement this increase in accident leakage, the licensee frequently decreases the technical specification allowable activity level of dose equivalent 1-131 in primary coolant. This is to demonstrate that the consequences of accidents do not result in doses that would exceed the guidelines of GDC-1g or 10 CFR Part 100 or some fraction thereof. After one or more operating cycles, the licensee may again find that it is necessary to modify the licensing basis for the facility because of to an increase in projected accident leakage because of the continual degradation of the SG tubes. This process may continue until the SGs are replaced.
The dose criteria for each of the design basis accidents noted above are presented in Table 1. Based upon these criteria, one accident scenario usually will be limiting with respect to the calculation of doses. Tnis scenario should be used in establishing the plant-specific technical specifications for operational leakage and maximum instantaneous and 48-hour values for dose equivalent 1-131. This scenario will likely remain the most limiting case until either a new, more limiting scenario is identified or the conditions associated with the scenario change. When a new scenario is identified as being the limiting case, a submittal to the NRC identifies the new scenario and the accident associated with the scenario. This submittal should also provide an assessment of the consequences of the accident and propose any licensing basis changes that are required as 42
a result of the new dose assessment (e.g., changes to the performance criteria for accident leakage integrity, technical specification coolant iodine activity levels). The staff encourages licensees to follow risk-informed approaches when proposing such changes. Risk-informed proposals should address each defect type and accompanying SGDSM approach to which the revised performance criteria will be applied. If a new scenario is identified that does not fallinto one of the accident categories presented in Table 1, a new category must be proposed and with it the licensee should propose a limiting dose criteria for the accident.
The staff has identified a potential pitfall in the performance of these dose assessments.
4 This involves calculating the curie content in primary and secondary coolant using one dose conversion factor while using a different dose conversion factor in the calculation of doses. Such an inconsistent application could result in either an underestimation or an overestimation of the i
dose consequences.
The activity level of dose equivalent 1-131 is calculated using the following Equation:
DE l-131 = EDCF,C/DCF,3, where DE l-131 =
the dose equivalent concentration of I-131, Ci/g DCF, =
the dose conversion factor for isotope I, rem /Cl C
=
the concentration of isotope I in the primary coolant, pCi/g i
DCF,3, the dose conversion factor for 1-131, rem /Ci
=
The dose conversion factors that are to be used are based on the plant specific technical specification definition of dose equivalent 1-131. Typical dose conversion factors contained in technical specifications are derived from Regulatory Guides 1.4 and 1.109 and ICRP 30. Some licensees may use the dose conversion factors from one source in the calculation of the curie content of dose equivalent 1-131 in reactor coolant but then use a different source in the calculation l
of doses. Based upon the predominant isotope,1-131, if the doses are calculated in this manner, 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 1-131. In some cases, licensees may wish to change their technical specifications to i
incorporate the use of a particular dose conversion factor.
l l
9.2.2 Flex Methodology in lieu of using the default methodology, the licensee may elect to use the doce calculation option that the NRC 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 l
licensing basis. The flex methodology is used to generate a plot of allowable primary-to-secondary accident leakage rates as a function of primary coolant activity level of dose equivalent 1-131. This l
plot is generated based upon a series of calculations for a number of different accident scenarios in which the accident leak rates vary with primary coolant activity level of dose equivalent 1 131.
l With such a plot, licensees are permitted to revise the accident leakage performance criteria for 43 l
applicable defect types and accompanying SGDSM programs to a desired allowable leakage value provided the primary coolant activity level of dose equivalent 1-131 is maintained below the corresponding value as determined from the plot. In the case of risk-informed proposals, applicable defect types and accompanying SGDSM programs are those for which accident leakage equal to the allowable leakage has been demonstrated not to lead to unacceptable risk and to maintain adequate defense in depth.
Risk assessment insights and considerations of maintaining defense in depth may result in upper bounds to the acceptable value for accident leakage, independent of the limitations imposed by the design basis accident calculations detailed in the SRP.
This flex methodology plot is based on the limiting accident scenario and conformance with the dose guidelines of Table 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-131 in primary coolant and the second would be for the 48-hour value of dose equivalent 1-131 in i
primary coolant. 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 1-131 while a different scenario may be more limiting for the 48-hour value.
The benefit of the plot is that it allows utilities to revise their performance criteria for accident-induced leakage integrity, without the frequent submittal of additional licensing basis changes or changes to the technical specification limits for dose equivalent 1-131 in the primary coolant, as necessary to accommodate increased levels of calcu!ated accident-induced leakage occurring as a result of increased levels of degradation in the SG or as a result of implementation of SGDSM programs that may include implementation of altemate repair criteria. Any such revision to the performance criteria must be within what has been evaluated in terms of defect type and accompanying SGDSM program and magnitude of accident leakage. Any such revision to the accident leakage performance criteria would result in more restrictive limits on primary coolant activity levels as determined from the plot that would be part of the technical specifications.
However, a resubmittal of the flex plot is required, along with NRC approval, if a new or a different limiting accident or scenario is identified. A resubmittal to the NRC is also required if the consequences of a previously analyzed accident changed or the assumptions, which were the basis for the plot, changed or if the licensee wishes to apply the flex methodology to accident leakage associated with defect types and accompanying SGDSM programs that are not addressed in the initial licensing basis change to incorporate flex into the technical specifications.
Under the default methodology, if operational assessment in accordance with Regulatory Position 4 reveals that the performance criteria for accident-induced leakage will be exceeded prior to the next scheduled SG inspection, the licensee either takes corrective action as necessary in accordance with Regulatory Position 6 such that the performance criteria is met or the licensee updates the radiological dose assessment to accommodate a higher performance criterion that meets or exceeds the accident leakage that may occur prior to the next scheduled inspection. In addition, the licensee may to havo to decrease the technical specification limits for the maximum instantaneous and 48-hour values of dose equivalent 1-131 in reactor coolant. Thus, NRC approval would be required prior to the licensee operating outside the accident leakage value assumed in the licensing basis accident analyses. With the flex program, the frequency at which NRC approval would be required in order to obtain approval for the increased accident leakage and the associated technical specifications changes would likely be reduced. NRC approvals would only be required if a new accident scenario is identified or if the licensee wished to apply the 44
t.
. - -.. ~ - _ - _.
l l
1 l
flex methodology to accident leakage accociated with defect types and accompanying i
approaches that are not addressed in the licensing basis change to incorporate flex into the
}
technical specifications.
The following is an illustration of how the flex methodology might be applied to devel plot.
l For purposes of illustration, it is assumed that risk and defer.se-in-depth considerations l
l have resulted in a maximum allowable accident leakage value of 100 gpm, independent i
the design basis accident analyses addressed by the flex methodology.
The licensee will select a primary coolant activity level based upon the maximum allowable instantaneous value for dose equivalent I-131. In addition, accident leakage, consisting t
the technical specification value of the normal operating primary to-secondary operatin leakage, plus additional accident leakage associated with implementation of SGDSM programs, will be assumed. Based on these values, for each of the potential accidents the licensee will calculate the doses for the control room operator, exclusion area boundary (EAB) and low population zone (LPZ). Using as an example the pre-existing spike case for a MSLB, the maximum allowable accident leakage rate at the assumed reactor coolant activity level for dose equivalent 1-131 is determined by multiplying the assumed accident leakage rate times the ratio of the dose criteria for the accident case ofinterest to the l
maximum calculated dose at the location. A second primary coolant activity level value for dose equivalent 1-131, smaller than the first, would be selected, the 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 1-131 until the allowable accident leakage exceeded 100 gpm. Then a plot would be made of maximum allowable primary-to secondary accident leakage as a function of primary coolant activity level of dose equivalent 1-131. Maximum allowable leakage is limited to 100 gpm. The primary coolant activity level of dose equivalent 1-131 is limited to a maximum of 60 pCi/g, which is the current maximum allowed value in technical specifications.
The second step of the process would have the execution of a similar calculation but for the primary coolant activity level of dose equivalent 1-131 at the 48-hour technical specification value for dose equivalent 1-131. Again, taking the MSLB accident as a representative case, it would be assumed that a MSLB occurs co-incident with an accident-initiated spike. The maximum allowed coolant activity level value for the 48-hour value for dose equivalent l-131 and an assumed accident primary-to-secondary accident leak rate would be selected.
Doses would be calculated at the EAB, LPZ, and control room operator locations based upon the spike following the accident. The maximum allowable primary-to-secondary accident leakage at the assumed prima:y coolant activity level for dcse equivalent 1-131 would be determined by multiplying the assumed accident leakage rate times the ratio of the dose criteria for the case of interest to the maximum calculated dose for the loca second smaller primary coolant activity level value for dose equivalent 1-131 would be L
selected, an accident leakage rate 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 100 gpm. These data points would be utilized to generate the plot in the technical specifications for the maximum allowable 45 i
primary-to secondary accident leakan as a function of the 48-hour value of dose equivalent 1-131. In no cases would the primary to-secondary leakage rate be allowed to exceed 100 gpm. The primary coolant activity level of dose equivalent 1-131 is limited to a maximum of 1 pCi/g, which is the maximum allowed by existing technical specifications.
Figures 2 through 4 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 would perform dose assessments for the locked rotor, rod j
ejection, MSLB, and SGTR events, as well as any other accident in which primary-to-secondary leakage impacts releases. The SRPs should be used in the performance of such assessments.
The EAB, LPZ, and control room operator doses would be compared to the dose guidelines of Table 1. The SGTR assessments would be performed at the maximum allowed instantaneous value for dose equivalent 1-131 and the maximum allowed 48-hour value of dose equivalent 1-131.
Such an evaluation would be performed to ensure that the most limiting scenario is obtained with respect to the determination of the maximum allowed technical specification values for dose equivalent 1-131 operational leakage and accident leakage.
Use 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 j
that should be used in the flex option are shown in Table 2. As noted from a review of this table, adoption of the flex program requires some changes from the parameters and assumptions in i
(
SRPs 15.1.5 and 15.6.3. Such changes include limitation of the dose consequences based upon the accident rather than the case, as well as use an iodine spiking factor of 500 for the MSLB and l
335 for the SGTR for the accident-initiated spike cases.
While the SRPs for the MSLB and SGTR accidents have the dose acceptance criteria as 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 l
accident. In the SRP approach, for the accident-initiated spike case for either a SGTR or a MSLB, the acceptance criteria are 10% of Part 100 guidelines. For the pre-existing spike case for either the SGTR or the MSLB, the acceptance criteria are the full Part 100 guidelines. With the adoption of the flex program, the dose acceptance criteria are no longer 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 will be 10% of Part 100 values for either case. This change in dose criteria would only be for those implementing l
(
the flex program.
The spiking factors that are to be used for the accident-initiated spike cases for the flex program are 335 for a SGTR and 500 for a MSLB. The value of 335 was obtained from the staff's assessment of release rate data collected by Adams and Atwood in a paper entitled, "The lodine Spike Release Rate During A Steam Generator Tube Rupture"(Ref.12). 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 are no data on an iodine spike associated with a MCLE, and the models that have been proposed do not justify a different value. Since there presently is no basis for using another value, the value of 500 will continue to be used for a MSLB.
With the selection of the flex option and the determination of the accident-induced primary-to-secondary leakage rate, licensees will be able to determine, from the previously generated plot l
46
_ _ _ _. _ _ _ _ _ _ _ _ _ _ _ _ _ _.-. _ _ _. _ _.m._ _
1 that has been incorporated into technical specifications, allowable reactor coolant activity levels maximum instantaneous dose equivalent 1-131 and the 48-hour value of dose equivalent 1-131.
As noted previously, the plot in technical specifications is good so long as a new or different accident or a new release pathway need not be considered. When such situations arise and result in a new limiting scenario, an 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. The plot in the technical specifications is applicable only to accident leakage associated with defect types addressed in the licensing basis change to incorporate flex into the technical specifications. This figure will be used to select an appropriate accident leakage performance criteria for applicable defect types and accompanying SGDSM programs and for corresponding primary coolant activity limits.
9.2.3 Technical Specifications The standard technical specifications (STS) and the improved STS (ISTS) contain specific values for the primary coolant maximum activity level of dose equivalent 1-131, a 48-hour value of dose equivalent 1 131, and a maximum primary-to-secondary leak rate during normal operations.
For licensees who chose to use 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, licensees who opt for the flex program must change their present technical specifications. A plant that incorporates the flex program will have a figure in its technical specifications that is a plot of allowable accident leakage as a function of the primary coolant activity level of dose equivalent I-131. Incorporation of this figure into the technical specifications will provide licensees the flexibility of operation to administratively limit themselves to either a lower accident leakage rate (i.e., a lower performance criteria for accident leakage) if the fuel is degraded such that primary coolant activity levels are high, or to permit higher accident leakage rates if the primary coolant activity level is low due to fuelintegrity being very good. The technical specification willindicate the defect types and accompanying SGDSM programs fo which the flex plot is acceptable.
With respect to the technical specifications, Table 3 presents the technical specifications required for the default case and for the flex program. The most limiting case for allowable l
leakage will also be the case that establishes the technical specification values.
l l
l 47
Table 1. Dose Criteria for Accidents involving Primary-to-Secondary Leakage Pathways Default Methodology Thyroid Whole Body Accident EAB/LPZ Control Room EAB/LPZ Control Room MSLB
- 1. Pre-existing spike case 300 30 25 5
- 2. Accident-initiated 30 30 2.5 5
spike case SGTR
- 1. Pre-existing spike case 300 30 25 5
- 2. Accidentinitiated 30 30 2.5 5
spike case Locked Rotor 33 30 2.5 5
i Control Rod Ejection 75 30 6
5 l
Flex Methodology Thyroid Whole Body Accident EAB/LPZ Control Room EAB/LPZ Control Room MSLB 300' 30 25" 5
SGTR' 30 30 2.5 5
l Locked Rotor 30 30 2.5 5
Control Rod Ejection 75 30 6
5
- 75 rem for the accident-initiated spike case
~ 6 rem for the accident-initiated spike case l
l 1
48
I L,
l Table 2. Sources of Parameters To Calculate Thyroid Doses for SGTR and MSLB Accidents Parameter Default /SRP Deterministic / Fig X/Q Site-specific @95%
Site-specific @95%
i Breathing Regulatory Guide 1.4 Value Regulatory Guide 1.4 Value Rate Dose Regu'atory Guides 1.4 and ICRP 30 Conversion 1.109, ICRP 30 Factor (DCF) 1 l
Reactor 60 pCl/g pre-existing spike Curve generated with a Coolant 1 pCilg accident-initiated spike maximum of 60 pCl/g for the pre-System existing spike
(
Activity (RCS) and 1 pCl/g for the accident-(
initiated spike Spiking Factor 500 500 MSLB/ 335 SGTR Dose Limit (Thyroid)
MSLB 300-rem pre-existing spike /30-300-rem pre-existing spike /75-rem accident-initiated spike rem accident-initiated spike SGTR 300-rem pre-existing spike /30-30 rem all cases rem accident initiated spike Maximum 1 gpm or 150 gpd per SG times Variable, function of limitations of Allowable the number of SGs plus 48-hour TS value for dose Leakage accident-induced leakage equivalent 1-131 and the maximum instantaneous value for dose equivalent 1-131 in the RCS and the limiting dose exposure pathway and the limiting accident scenario.
l t
l l
i 49
Table 3.
Technical Specifications for Dose Assessment Parameter Default Case Flex Case Maximum Activity Level Dose 60 Variable Equivalent 1-131, pCilg Maximum 48-hour Value for i
Variable Dose Equivalent 1-131, pCilg Normal Operating Leakage, Total 1 gpm or 150 150 gpd/SG gpd/SG Dose Conversion Factors for Regulatory ICRP-30 Defining Dose Equivalent 1-131 Guides 1.4 and 1.109, ICRP-30 Allowable Leakage, Event NA Variable, function of product of Induced, gpm leakage and dose equivalent l-131 activity level, limiting accident and scenario and 100 gpm limit 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 /> fc!!Owing a 15% power change in hours 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> 50
Plant A TS Plot of Allowable Primary Coolant Activity Level of Dose Equivalent lo Accident Leakage, gpm 10,000
- Pre-existing Spike Accident inttlated 1,000
~Mantmum Alfowable Leek
' ^ * " " " * '"*
Maximum Instantaneous 100 !~
=
x
=
~
x
~
~
5.
10
~ ~
i e
1 i,
0.1 1
10 100 RCS Activity Dose Equivalent 1-131, UCi/gm Figure 2
Plant B TS Plot of Allowable Primary Coolant Activity Level of Dose Equivalent lodine Accident Leakage, gpm 10,000
+ m =..
+w.,,i w
- w. t 1,000
~ ~ * "
- 1 a
100 i
4 e
~
j
~
1 10 I
1
- l 0.1 1
10 100
.l RCS Activity Dose Equivalent 1-131, uCi/g Figure 3 I
Plant C TS Plot of Allowable Primary Coolant Activity Level of Dose Equivalent loding Accident Leakage, gpm
{
10,000 t
1,000 l
100' 7
u e
=
- Pre-exleting spike YAce! dent infileted Maximum Alloweble Leek
- 4. wou, veive
- *Meximum Instantaneous 1
0.1 1
10 100 RCS Activity Dose Equivalent 1-131, uCi/g Figure 4
10.
REPORTS TO THE NRC 10.1 SG Tube Inservice inspection Licensees should submit the complete results of the SG 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., 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.
2.
The location and measured size of each indication found by inservice inspection and the type of NDE test probe used (e.g., eddy current bobbin coil, eddy current rotating pancake coil). The orientation of the indication (e.g., axial, circumferential) should be provided for linear-type indications such as cracks.
i 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 or repaired.
l 10.2 Failure of the Condition Monitoring Assessment Failure of the condition monitoring assessment to confirm that the performance criteria of Regulatory Position 2 have been met must be reported to the NRC in accordance with 10 CFR 50.72. In addition, a special report should be submitted prior to restart consisting of the information listed in Regulatory Positions 10.1.a.10.1.b, and 10.1.d as it pertains to the specific defect types for which the performance criteria were not met.
D. IMPLEMENTATION The purpose of this section is to provide information to applicants regarding the staff's plans for using this regulatory guide.
This draft guide has been released to encourage public participation in its development.
Except in those cases in which a licensee or applicant proposes an acceptable alternative method for complying with specified portions of the NRC's regulations, the method to be described in the active guide reflecting public comments will be used in the evaluation of applications for new licenses or license renewals and for evaluating compliance with regulations applicable to steam generator degradation.
54
REFERENCES 1.
" Standard Review Plan for the Review of Safety Analysis Reports or Nuclear Power Plants," LWR Edition, NUREG-0800, July 1981.
2.
American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code, Sections lil and XI, ASME. (Copies may be obtained from ASME,345 East 47th Street, New York, NY 10017.)
3.
" Standard Technical Specifications for Babcock and Wilcox Pressurized Water Reactors,"
NUREG-1430, Revision 1, April 7,1995 NUREG-1430.
4.
" Standard Technical Specifications for Combustion Engineering Pressurized Water Reactors," NUREG-1432, Revision 1, April 7,1995.
5.
" Standard Technical Specifications for Westinghouse Pressurized Water Reactors,"
NUREG-1431, Revision 1, April 7,1995.
6.
USNRC, " Inservice Inspection of Pressurized Water Reactor Steam Generator Tubes,"
Regulatory Guide 1.83, Revision 1, July 1975.
7.
USNRC, " Bases for Plugging Degraded PWR Steam Generator Tubes," Regulatory Guide 1.121, August 1976.
8.
USNRC, "An Approach for Using Probabilistic Risk Assessment in Risk-informed Decisions on Plant-Specific Changes to Licensing Basis," Regulatory Guide 1.174, July 1998.
9.
Electric Power Research Institute, "PWR Steam Generator Examination Guidelines," EPRI NP-6201, Revision 5, Appendices G and H, September 1997.
10.
Electric Power Research Institute, "PWR Secondary Water Chemistry Guidelines," EPRI NP-102134, Revision 3, May 1993.
11.
Electric Power Research Institute, "PWR Primary-to-Secondary Leak Guidelines," EPRI Report TR-104788, May 1995.
12.
J.P. Adams and C.L. Atwood,"The lodine Spike Release Rate During a Steam Generator Tube Rupture, Nuclear Technology, Volume 4, PP. 361-371, June 1991.
j 55
REGULATORY ANALYSIS J
' A separate regulatory analysis was not prepared for this regulatory guide. The regulatory analysis prepared to support revising the current regulatory framework addressing steam generator tube integrity provides the regulatory basis for this guide and related documents and examines the costs and benefits as implemented by this guide. A copy of" Regulatory Analysis:
Regulatory Approach for Steam Generator Tube Integrity," May 1997, is available for inspection and copying for a fee at the NRC Public Document Room,2120 L Street NW, Washington, DC.
e 1
i I
l l
t 56
Differing Professional Opinion Consideration Document I. INTRODUCTION AND EXECUTIVE
SUMMARY
The staff has considered the differing professional opinion (DPO) views, as they have been presented, during past regulatory activities such as development of Generic Letter (GL) 95-05 and in more recent development of the regulatory framework as described in SECY-97-013 and proposed in draft GL 98-xx " Steam Generator Tube integrity" (currently being delayed for three months while the staff works with industry on resolving concerns associated with NEl 97-06).
The purpose of this document is to provide an integrated report on how the DPO issues have been considered in ongoing regulatory activities and how they have been addressed in development of the proposed regulatory framework for steam generators (SG). In preparing this document, the staff reviewed all available documentation discussing the DPO (see section IV list of references) and grouped the concems into five broad issued: (1) limitations of nondestructive examination.(NDE) methods, (2) primary-to-secondary SG tube leakage during postulated main steam line break (MSLB) conditions, (3) increased risk due to SG tube degradation and implementation of altemate repair criteria, (4) iodine spiking assumptions for radiological analyses and (5) SG tube integrity under severe accident conditions. By letter dated April 9, 1998 from the deputy EDO to the DPO author, the DPO author was requested to provide any additional concerns that he may have regarding the DPO consideration document (this document), or the proposed GL package. In a memo dated April 21,1998, the DPO author indicated that he did not have any new concerns regarding this document. Some specific comments were provided on the proposed GL and DG-1074. The additional comments will be addressed as part of the public comment process.
It should also be noted that the staff is currently working with industry to resolve issues associated with the industry initiative entitled NEl 97-06 " Steam Generator Program Guidelines."
As a result, the staff may not issue a generic letter on SG tube integrity if sufficient progress is achieved with industry in resolving staff concems. Regardless of whether the staff issues a generic letter on SG tube integrity or chooses to endorse the industry initiative, the revised regulatory framework will still address the significant issues associated with maintaining and monitoring SG tube integrity consistent with goveming regulations and plant licensing bases. In the mean time, the staff continues its ad hoc approach to monitoring licensees actions in this regard.
The staff's assessment of each of the above issues is discussed in the following sections. It should be noted that some elements of the issues raised have merit and the staff was, in fact, addressing many of these issues before they were raised in various stages of the DPO.
5 The ACRS letter to the EDO dated October 10,1997 " Resolution of the Differing Professional Opinion Related to Steam Generator Tube Integrity" stated tha ACRS conclusion that the DPO issues were accurately summarized by the DPO document. The same ACRS letter also indicated that the DPO author thought the issues were adequately summarized.
ATTACHMENT 2
2 The subject of limitations in NDE was specifically evaluated in NUREG-1477 and in the methodology developed in GL 95-05. Further, a major component of any acceptable revised regulatory approach (whether that ultimately is a generic letter or the NEl initiative) will be on providing the necessary guidance on how to assure that NDE methods are property qualified and NDE uncertainties accounted for in assessing tube integrity.
The issue of primary-to-secondary SG tube leakage under postulated design basis conditions (e.g., MSLB conditions) was (1) specifically evaluated in NUREG-1477, (2) is addressed by the analysis methods developed in GL 95-05, and (3) is specifically controlled by one of the performance criteria established under the new regulatory framework (note that the performance criteria may be implemented via the NEl 97-06 initiative instead of being implemented via a generic letter).
The risk assessment performed by the staff in support of the effort to revise the regulatory framework considered the issues raised in the DPO. A major conclusion of the risk assessment and associated regulatory impact analysis was that a generic backfit requiring licensees to take action to reduce risk associated with SG tube degradation could not be supported per the criteria of 10 CFR 50.109. However, the risk evaluation also concluded that (1) the conclusion regarding inability to support a generic backfit was based on licensees taking action beyond those required by the current technical specifications, (2) further assessments are necessary to determine if plant-specific vulnerabilities require additional action, and (3) certain forms of alternate repair criteria could potentially have an adverse impact on risk. It is the staff's intent to include assessment of plant-specific vulnerabilities as part of the individual plant examination (IPE) followup program. Also, since some forms of alternate repair criteria could introduce new vulnerabilities and contributions to risk, under any acceptable regulatory approach (whether a generic letter or the NEl 97-06 initiative) the staff will encourage licensees to follow risk-informed approaches when proposing new ARC as an alternative to compliance with existing deterministic requirements. The staff will not approve new ARC that unacceptably increase the risk associated with SG tube integnty.
As part of assessing the issue of iodine spiking, the staff has reviewed the industry models and performed independent analyses of available data and models. Based on these assessments, the staff has concluded that although there are no data corresponding directly to the rapid depressurization conditions associated with a postulated MSLB, the spiking factors assumed in the existing dose assessment methodologies provide a reasonable level of conservatism for calculation of doses against the 10 CFR Part 100 guideline limits.
Regarding severe accidents, the staff has concluded that core damage conditions, particularly those cssociated with high primary pressure, dry steam generator secondary side events, can introduce vulnerabilities that have not been previously considered. These vulnerabilities are the result of challenges to tube integrity from the high reactor coolant system (RCS) temperatures predicted during these events. The staff considered high temperature effects in its risk assessment and also assessed the potential for plant-specific vulnerabilities due to particular forms of degradation. As a r'sult of these assessments, the staff has concluded that certain vulnerabilities will be considered along with results of the previously mentioned IPE followup program.
l 3
II.
SUMMARY
OF ISSUES RAISED Based on a review of all available documentation discussing the DPO issues (the documentation reviewed is referenced at the end of the main body of this report), the concerns raised are summarized into the following five issues:
- 1. NDE Issue: The concem was identified that nondestructive examination (NDE) techniques are not capable of adequately detecting and sizing intergranular stress corrosion cracking (IGSCC) and that cc,rrelations of leakage versus an NDE parameter such as bobbin coit voltage
)
cannot be reliably used to calculate leakage for design basis events such as a main steam line break (MSLB). Additionally, it was stated that the complex morphology of IGSCC cracks and the limitations of current NDE technology make it impossible to construct such correlations.
- 2. MSLB Leakage issue: The concern is that elevated tube differential pressure caused by design basis secondary depressurization transients (including MSLB) can cause primary-to-secondary leakage that could be greater than the leakage from a steam generator tube rupture (SGTR). The leakage may be sufficient to deplete the refueling water storage tank (RWST) inventory via ECCS injection lost to the secondary side of the SGs (and therefore not available for recirculation from the containment sump) thereby leading to core damage.
- 3. Risk Increase issue: The concem is that the frequency of core damage with containment bypass may be approximately 3.4 X 10-4 per reactor year. This risk value was initially attributed to the increased risk resulting from the increased potential for RWST depletion as a result of large postulated primary-to-secondary tube leakages as discussed in issue 2 above. More recently, this concern has included references to station blackout sequences, and it has been implied that severe accident leakage and failures of degraded tubes under such conditions could lead to higher risk.
- 4. lodine Spiking issue: The concem is that the iodine spike (i.e., the release of radioactive fission products into the RCS from the fuel through cladding perforations) following a large depressurization transient such as a MSLB, may be greater than the value of 500 assumed in the standard review plan (SRP) dose assessment methodology. Additionally, the concern is raised that the iodine spike (i.e., 500) could increase to higher multipliers as initial RCS coolant activity is decreased so that simply reducing initial RCS activity (via a technical specification change) may not result in a one-for-one reduction in calculated accident doses.
- 5. Severe Accident Issues: The concern is that the SG tubes may fait prior to other portions of the reactor coolant pressure boundary (RCPB) due to (1) inadequate NDE characterization (leaving in service potentially large numbers of through-wall flaws or flaws that grow through-wall during the operating cycle and which subsequently fail under severe accident conditions prior to other portions of the RCPB), (2) increased flow through the tube cracks (as small as pin-hole leaks) resulting in increased heat transfer to the tubes and a change in the thermal-hydraulic regime analyzed during this portion of the severe accident, (3) the cracks in tubes opening and unplugging c'ue to increased pressure, and (4) the potential forjets from the cracks to erode and fail adjacent tubes leading to a large release.
l
4 Ill. CONSIDERATION OF DPO ISSUES IN SG GENERIC LETTER DEVELOPMENT The staff considered each of the preceding issues during the effort to revise the regulatory approach on SG tube integrity including the development of supporting regulatory guidance and performance of a supporting risk assessment. The following sections discuss the staff's consideration of each issue.
Response to issue 1. "NDE lssue".
Regarding whether current NDE techniques are capable of detecting and sizing IGSCC, it is recognized that current NDE systems (equipment, procedures, and personnel) have limitations with respect to their capabilities to accurately detect and size flaws, particularly IGSCC flaws.
Industry and the NRC staff have been aware of these limitations and have taken action as necessary to ensure tube integrity is maintained.
Technology improvements have significantly increased eddy current testing (ECT) sensitivity to IGSCC. Industry guidelines have been developed which have gained widespread acceptance j
among licensees and which have led to improved procedures and improved qualification of the equipment and procedures and improved training and qualification of personnel with respect to i
IGSCC detection. The improved ECT technology, procedures, and qualification exceed minimum technical specification requirements, but have received widespread application throughout the industry.
Licensees have performed extensive metallographic examinations of IGSCC degradcd tube specimens rerm d from the field and in-situ pressure tests to verify that ECT detection performance in cmunction with other licensee actions is adequate to ensure that tube integrity is being maintained. ECT capabilities to accurately measure IGSCC depth ceritinues to be poor and, thus, it is general industry practice to conservatively assume that all IGSCC indications fail
'o satisfy the 40% depth-based plugging limit, where applicable, and to plug all such indications (i.e., " plug on detection"). In addition, licensees have implemented more frequent inspections, reduced hot leg temperatures, more effective monitoring of operational leakage, and more stringent operational leakage limits, beyond minimum TS requirements, as necessary to ensure tube integrity is maintained between scheduled inspections.
The accumulated evidence from operating experience, including metallogrcphic examinations of removed tube specimens from tne field and in situ pressure tests, support the conclusion that ECT detection capability for IGSCC in conjunction with implementation of other measures (discussed above), when and as appropriate, is adequate to ensure that tube integrity is maintained. Licensee actions to manage IGSCC to this effect have been somewhat ad-hoc, in view of shortcomings in existing TS requirements. The effort to revise the regulatory approach on SG tube integrity has as its key objective identifying those additional actions that are needed (in addition to the current minimum TS requirements) to maintain and monitor SG tube integrity consistent with goveming regulations and plant licensing bases. In the meantime, the staff monitors licensee actions to ensure that tube integrity is being maintained. In addition, the staff issues generic communications as warranted in response to problems experienced in the field.
Recent examples of generic letters addressing problems in the field include GL 95-03 "Circumferential Cracking of Steam Generator Tubes", GL 97-05 " Steam Generator Tube Inspection Techniques", and GL 97-06 " Degradation of Steam Generator Internals".
1
=
5 Regarding the development and use of empirical correlstions for the calculation of leakage during design basis events, the staff has approved the use of one such approach to date (i.e.,
empirical correlations for the calculation of both accident-induced leakage and the potential for tube failure under design basis conditions) through the issuance of GL 95-05 (voltage-based repair criteria for outside diameter stress cor osion cracking (ODSCC) at tube support plates (TSPs) in Westinghouse-designed SGs). It was GL 95-05 which led the DPO author to file the DPO in July 1994. The DPO issues are related to issues identified earlier in a differing professional view (December 1991). For the voltage-based repair criteria, the DPO issues were considered by the staff during the development of the GL 95-05 guidance, as well as being considered by Advisory Committee for Reactor Safeguards (ACRS) and the Committee to Review Generic Requirements (CRGR) during the review process for the GL. The staff, ACRS, and CRGR all concluded that GL 95-05 was acceptable in light of the issues raised and as a result the GL was issued. As a result, to date, this issue has been addressed appropriately. It should be noted that GL 95-05 explicitly addressed the need to conservatively consider, through rigorous statistical analyses, the uncertainties associated with voltage-based correlations and required licensees to explicitly incorporate into the assessment model consideration of the probability of nondetection.
Ten plants currently (March 1998) implement a voltage-based steam generator (SG) tube repair criteria per Generic Letter (GL) 95-05. At this time, the staff has completed eight reviews of the 90-day reports submitted by licensees (five of the reviews were performed by Pacific Northwest National Laboratories (PNNL); the remaining three were performed by EMCB staff). Copies of the evaluations that document these reviews have been provided to the author of the DPO.
Several other 90-day reports are currently being reviewed. Table 1 summarizes the status of the 90-day report reviews for the plants implementing voltage-based tube repair criteria.
Based on the reviews of 90-day reports, the GL 95-05 methodology for most of the plants has reasonably predicted the end-of-cycle (EOC) voltage distribution of outside diameter stress corrosion cracking (ODSCC) indications located at the tube support plates (TSPs). Predictions of EOC volb.je distributions that are reasonably comparable to actualinspection results have led to conservative predictions of leakage during a postulated main steam line break (MSLB) event. However, recent experiences at Braidwood and Farley warrant further staff review and assessment.
Braidwood Unit 1 (Braidwood-1)
Braidwood Unit 1 and Byron Unit 1 have plant-specific license amendments that allow higher voltage-based repair criteria than allowed under the 95-05 methodology. These higher voltage repair limits were based on stabilization of the tube support plates by expansion of selected tubes at the support plate intersections so that the tube support plates could be credited as staying in place under postulated main steam line break conditions (see safety evaluation in htter from M.D. Lynch (NRC) to D.L. Farrar (Commonwealth Edison) dated November 9,1995).
At the EOC-6 at Braidwood-1, the licensee compared the actual bobbin coil eddy current voltage distribution of its ODSCC TSP indications with the projected voltage distribution obtained during the previous outage. The licensee found the predicted voltage distribution was nonconservative with respect to the actual voltage distribution. As a result, the predicted leakage during a postulated MSLB event significantly underestimated the leakage calculated based on actual
=
i l
6 l
EOC conditions (6.99 gpm versus 11.5 gpm) although the latter value was still well within the site allowable leakage limit (19.0 gpm). The licensee attributed the nonconservative prediction of the EOC voltage distribution to a voltage-dependent growth rate that appears to haye occurred, in part, due to the higher voltage repair criteria in effect at Braidwood-1 For the current operating cycle (cycle 7), the licensee applied a voltage-dependent growth rate to predict the EOC-7 conditions. The licensee also reassessed the EOC-8 predictions for Byron-1 since a similar voltage-dependent growth rate may exist (Byron-1 also implements higher voltage repair criteria). Based on EOC predictions that incorporated voltage-dependent growth rates, both plants concluc'ad the reactor coolant system dose equivalent iodine (del) levels should be reduced.. The staff will review the license amendment request to reduce DEI in the coming weeks.
The staff is reviewing the most recent Braidwood-190-day report. The review will focus on the possible generic implications of the voltage-dependent growth rate phenomena as well as the plant-specific actions taken at Braidwood-1 and Byron-1 with respect to current operating cycle predictions. Our assessment at this time is that the modification to include a voltage-dependent growth rate is reasonable and appropriate.-
Earlev Unit i (Farlev-1)
Both Farley units have been under predicting the maximum ODSCC voltage indications.
However, the overall distribution of predicted voltages has been conservative enough to result in generally conservative predictions of the limiting leakage. For example, at the most recent outage at the EOC-14, Farley.1 compared actual ODSCC indication vokges with predictions made during the previous outage. In all three SGs, the total number of indications of any size, the number of indications greater than 1.0 volt, and the number of indications greater than 2.0 volt was usually significantly over predicted. In terms of maximum voltages, SG "A" was predicted to have a maximum voltage as high as 6.9 volt; the actual maximum voltage was 6.4 volt. SG "B" was predicted to have a maximum voltage as high as 6.7 volt; the actual maximum voltage was 3.1 volt. SG "C" was predicted to have a maximum voltage of 7.6 volt; the actual maximum voltage was 13.7 volt. The limiting MSLB leakage was predicted for SG "C" to be 10.2 gpm. Using the actual voltage distributions from the EOC-14 inspection, the limiting MSLB leakage was calculated for SG "C" at 7.6 gpm. Thus, the MSLB leakage was conservatively predicted and remained within the Farley-1 licensing basis despite the signNicant under prediction of the maximum voltage in SG "C." Based on EOC-15 predictions that incorporated the high voltage growth found in SG "C " Farley-1 concluded the plant cannot complete its current operating cycle without taking additional action to remain within its site allowable leakage limit. At this time, the licensee has not yet determined what specific action will be taken (e.g.,
mid-cycle inspection or reduced RCS dose equivalent iodine levels),
The staff is reviewing the most recent Farley 90-day reports. The methodology has continued to conservatively predict leakage at Farley. The lack of conservatively predicted maximum voltage indications in all cases was not unexpected at the time the staff approved the voltage-based repair criteria. However, it may indicate a need for Farley to reassess and possibly adjust the calculational approach for the predictions. Staff conclusions on this matter will be provided when we complete our review of the Farley 90-day reports.
Y
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.. ~. -. - - -.. - - -.. -.. - -. - - - -. - - -... -.... - - -. -. -..
7 The NRC staff has been informed that a potential discrepancy exists in the assessment of the radiological consequences of a MSLB due to primary-to-secondary leakage from SG tube indications (see meeting summary issued August 25,1997). In correspondence dated July 30, 1997, Nuclear Energy Institute (NEI) stated all pressurized water reactor licensees would be informed of the potential error associated with performing leak rate and dose consequence calculations.
In summary, the staff has been monitoring and continues to monitor the performance of the voltage-based repair criteria. Based on reviews to date (up to March 1998), although the GL 95-05 methodologies may not predict the maximum voltage amplitude, the predicted EOC leakage rates under postulated accident conditions have been conservative when compared to the actual EOC conditions. (The Braidwood and Byron experience is related to plant-specific criteria and is being pursued on a plant-specific basis.) Furthermore, application of the voltage-based criteria (including Braidwood and Byron) has not resulted in any plant being outside its licensing basis, it also should be noted that several conservatism exist in the methodology used to calculate leakage and radiological doses under the voltage-based methodology. In particular, the leakage rates are calculated so as to be conservative 95 out of 100 times and the radiological doses associated with the projected leakage rate are conservatively calculated consistent with Standard Review Plan Section 15.1.5.
~ _ _.. _ _ _ _ _. _ _ -. _ _ _ _ _. _ _ _ _
Table 1:
Plants implementing Voltage-Based Steam Generator Tube Repair Criteria per the Guidance of Generic Letter 95-05 PLANT STATUS OF 90-DAY REPORTS AND ASSOCIATED REVIEWS Beaver Valley 1 90-day report: EOC-11/BOC-12 (Reviewed by EMCB)
Braidwood 1 90-day report: EOC-5A/BOC-6 (Reviewed by PNNL) 90-day report: EOC-5B/BOC-6 (Reviewed by EMCB) 90-day report: EOC-6/BOC-7 (ur$ der review)
Byron 1 90-day report: EOC-6/BOC-7 (PNNL reviewed) 90-day report: EOC-7B/BOC-8 (under review)
Cook 1 90-day report: EOC-13/BOC-14 (PNNL reviewed) 90-day report: EOC-15/BOC-16 (EMCB preliminary review complete)
Farley 1 90-day report: EOC-13/BOC-14 (PNNL reviewed) 90-day report: EOC-14/BOC-15 (under review)
Farley 2 90-day report: EOC-10/BOC-11 (PNNL reviewed) 90-day report: EOC-11/BOC-12 (under review)
Kewaunee 90-day report: EOC-21/BOC-22 (EMCB preliminary review complete) 7 Sequoyah 1 90-day report: EOC-8/BOC-9 (under review) l Sequoyah 2 90-day report: EOC-7/BOC-8 (EMCB preliminary review l
complete)
South Texas 1 90-day report: EOC-6/BOC-7 (EMCB reviewed)
Regarding how NDE issues will be addressed in the future, the stars regulatory initiative with respect to steam generator tube integrity is intended to ensure that a systematic approach for ensuring that tube integrity is maintained rather than continuing to rely on an ad-hoc approach.
This regulatory initiative has as its key objective identifying those additional actions that are needed (in addition to the current minimum TS requirements) to maintain and monitor SG tube integrity consistent with governing regulations and plant licensing bases. The staff developed draft Regulatory Guide DG-1074 to provide guidance on one acceptable means for ensuring SG tube integrity consistent with governing regulations and plant licensing bases.
i
}
Inservice inspection NDE issues are among the key issues addressed in the DG-1074 guidance (refer to section C.1 of DG-1074). The guidelines identify measures that the staff finds i
acceptable for the nondestructive examination of SG tubing and specifically states that NDE I
l
9 l
l systems should undergo a formal qualification process for each degradation mechanism in accordance with the Electric Power Research institute (EPRI) Steam Generator Guideline This guidance states that only NDE systems satisfying flaw detection performance criteria specified in the EPRI guidelines may be used for inservice inspection. In addition, flaw size measurement performance should be established for each degradation mechanism through performance demonstration and must be accounted for in the applicable repair limit. NDE systems whose measurement performsace has been characterized in this manner are termed
" validated for sizing." Alternatively, if validated NDE techniques are not available for a given degradation mechanism, allindications associated with that mechanism should be plugged or repaired, irrespective of the measured flaw size.
I l
The guidance developed by the staff to support the new regulatory initiative (i.e., DG-1074) also addresses leakage induced by postulated accidents such as a main steam line break (MSLB),
the use of empirical correlations between leakage and an eddy current response parameter for calculating this potential leakage, and the treatment of eddy current limitations as they affect the leakage calculation. The guidelines provide that the tubes should be monitored with respect to performance criteria and that actions be taken as necessary to ensure that the performance criteria will c.ontinue to be met. The performance criteria are defined in DG 1074 so as to ensure compliance with plant licensing bases.. Monitoring consists of inspection and/or test methods and analysis methods that provide high confidence in the assessment of the tubing relative to the performance criteria. DG-1074 states that it is acceptable to utilize flaw measurements from the NDE inspections as part of the assessment provided NDE measurement error / variability has been quantified by an acceptable performance demonstration. Where NDE measurement performance has not been quantified, this guidance provides that alternative methods (e.g. in situ pressure testing) should be employed in lieu of the NDE flaw measurements to monitor the condition of the tubing.
NDE flaw measurements, where appropriate in accordance with the guidelines accompanying 1
the generic letter, provide a convenient means for assessing potential accident-induced leakage l
in cases where a relationship has been established between leakage and measured flaw size or other NDE parameter. These relationships (models) generally relate leakage to a single flaw parameter (e.g., flaw length) and to material properties. However, other flaw parameters (e.g.,
profile of crack depth over crack length, ligaments between crack segments, tortuosity of leakage path) also tend to affect the leakage value for a given flaw. Because these parameters I
may not be specifically accounted for in the models, the model estimates may incorporate significant uncertainty, depending on the complexity of the flaw morphology. Leakage data as a function of the flaw size parameter will therefore tend to exhibit scatter. To ensure conservative leakage estimates, the guidelines provide that the models should account for this uncertainty.
The guidance provides that the tubing be assessed to provide high confidence that the tubing condition satisfies the performance criteria. Accordingly, this guidance states that all significant uncertainties affecting the outcome of the assessment should be accounted for, and provides guidelines for accomplishing this objective.
OG-1074 indicates that leakage models may be empirically-based or analytically-based.
inalytical models typically do not explicitly quantify uncertainties in the model estimates, and, tisus, the regulatory guide provides that the models should be developed to produce bounding estimates as confirmed by test. Empirical models often provide the most convenient and
10 realistic treatment of the leakage potential of complex flaw morphologies. The supporting data set should cover the range of flaw morphologies and flaw sizes to which the correlation is to be applied. These guidelines state that empirical models should satisfy standard statistical
" goodness-of-fit" and " significance-of-correlation" criteria and should quantify significant uncertainties including model parameter uncertainties and uncertainties indicated by data scatter. These uncertainties, the variability of material properties, and eddy current measurement error / variability should be considered in the leakage assessment such as to ensure an upper bound estimate of the total leak rate from all indications in the faulted steam generator with a probability of 0.95. The subject of crack size and severe accident evaluatio addressed in the response to issue 5 and in the appendix to this report.
Consistent with the staff position taken in GL 95-05 with respect to IGSCC at the tube to tube support plate intersections, the DG-1074 guidance provides that burst and leakage behavier may be correlated with the NDE voltage response to tubing flaws in lieu of direct NDE measurements of flaw depth or flaw length. Such correlations with the NDE voltage response are subject to the same criteria as those with respect to measured flaw depth and length; namely, such correlations must be supported by statistically significant number of data covering the spectrum, of flaw morphologies being addressed by the correlation, satisfy standard statistical tests, and that model uncertainties be quantified and considered in the tube integrity assessments. Tube integrity assessments must account for the variability (repeatability) of voltage response to a given flaw and the variability among analysts in measuring the voltage
- response, in conclusion, the staff understands the limitations of current NDE techniques in terms of both detection and sizing of IGSCC as well as the potential pitfalls of following empirical approaches for ensuring SG tube integrity. The staff has adequately accounted for these NDE limitations in the manner in which it has regulated the SG tube integrity issue to date. Future alternative strategies for managing SG degradation are adequately addressed in the DG-1074 guidance.
Response to issue 2. "MSLB Leakage issue":
NUREG-1477, " Voltage-Based interim Plugging Criteria for Steam Generator Tubes" documented the staff's consideration of proposed voltage-based repair criteria (which subsequently developed into GL 95-05). In this report, the staff explicitly analyzed steam generator tube leakage during secondary side depressurization events, including main steam line breaks (MSLB). Thermal-hydraulic analyses were performed using the RELAP code to assess plant response to MSLB events involving a range of primary-to-secondary leakage.
Calculations were performed over a range of leak rates from a few hundred gpm to over one thousand gpm. For these calculations, tube leakage was not assumed to begin until the differential pressure increased to above normal operating levels.
The results indicate that the primary-to-secondary pressure differential remains relatively constant immediately following the break, since primary as v ell as secondary pressures are decreasing. This is due to the cooling effects on the RCS c,aused by the high steam flow rates resulting from the secondary side break. Following depletion of the secondary inventory in th affected generator, the RCS pressure begins to increase as the cooling effect ceases and the emergency core cooling system (ECCS) injection increases the reactor coolant inventory. T causes the pressure differential across the tubes to exceed the normal operating differential
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11 pressure. The pressure differential would increase to approximately 2230 psid assuming no l
tube leakage and normal operator actions.
If cracks in the tubes begin to leak substantially, the increased leakage will counteract the l
pressure increase from ECCS injection. The increased pressure differential across the tubes is expected to open cracks somewhat, leading to higher leakage, but at some point, an equilibrium will be reached when tube leakage and ECCS injection match. The RCS pressure will then stop rising and the leak rate will stabilize. At this equilibrium point, tube differential pressure will essentially equal the RCS pressure, since the secondary is. depressurized. The resulting tube differential pressure is expected to be greater than the differential pressure during normal operation (i.e., about 1400 psi) because some additional pressure differential is required to start the leakage.
Since the tube leakage is equal to the ECCS injection rate once the equilibrium is reached, the tube leakage is limited by ECCS pump capacity. A characteristic of pumps used in ECCS l
applications is that their capacity decreases with increasing discharge pressure. Since the RCS pressure is above the normal operating primary-to-secondary differential pressure, ECCS flow rate is less than that corresponding to an RCS pressure of 1400 psi. This flow rate is in the l
range of 500 to 1000 gpm (depending on plant design) which established the leakage range used in the thermal-hydraulic studies. The analyses concluded that provided several key operator actions are assumed, RWST capacity is expected to be sufficient to cool down the plant in the event of MSLB accompanied by tube leakage.
In conjunction with recent activities to revise the regulatory appaach for maintaining SG tube integrity, the staff, through its contractor, arrived at the same conclusion regarding RWST capacity in INEL-95/0641, " Steam Generator Tube Rupture Induced from Operational Transients, Design Basis Accidents, and Severe Accidents." In these calculations, the primary-to-secondary leakage was assumed to commence coincident with start of the secondary depressurization. Provided operator action was taken to throttle ECCS injection, depressurize the RCS to allow placing the residual heat removal (RHR) system in service and achieving cooldown on RHR, the event could be mitigated before exhausting RWST inventory. In these analyses, RWST inventory was considered insufficient only if no operator actions were taken or
. if a large number of tubes (on the order of 10) simultaneously ruptured.
From the assessments documented in these reports, the staff concluded that if primary-to-secondary leakage occurred during a secondary depressurization (leak rates as great as that of a tube rupture), that sufficient margin in RWST capacity existed to mitigate the event before core damage occurred. The risk associated with the potential for cool down not being accomplished promptly in accordance with plant procedures is discussed in the response to issue 3.
Response to issue 3. " Risk increase issue":
This issue was or;ginally raised with respect to the core damage frequency (CDF) associated
~
with steam generator tube leakage induced by MSLB events. More recently, it was expanded to l-include other issues identified by the staff involving the behav;or of steam generator tubes under high temperature conditions that are associated with the core oxidation phase of severe accidents. These are two separate sets of sequences involving tube behavior under different f
l s
i 12 conditions with different effects on the results of a probabilistic risk assessment (PRA).
Therefore, they are addressed separately.
The risk associated with MSLB-induced tube rupture or leakage involves tube pressure differentials above normal conditions at nearly normal operating temperatures. The consequences affect both the CDF and containment bypass release frequency (CBRF)
(releases of radioactive materials from the damaged core). In contrast, the risk of tube rupture or extensive leakage induced by core damage conditions involves significantly elevated temperatures, and impacts only the CBRF because it simply shifts some of the previously calculated CDF into the CBRF from other release categories.
Risk from MSLB Induced Tube Leakage:
In staff assessments of risk associated with tube leakage induced by steam generator secondary side depressurization, the impacts on CDF and CBRF were found to be much smaller than the value proposed in the DPO. NUREG-1477 evaluated the risk associated with tube leakage induced by depressurization of steam generator eacondary sides by stuck-open steam line relief valves and feedwater line breaks in addition to main steam line breaks. It concluded that the frequency of the initiating depressurization events was dominated by stuck-open relief valves, with a frequency in the range of 108/ reactor year (RY), which was estimated from operational event data. Steam line breaks and feedwater line breaks also contributed to the initiating event frequency when estimated on a conservative basis. The probability of tube leakage on the order of 500 to 1000 gpm was assu.ned to be 1.0 for this analysis, although existing repair criteria and future proposed criteria are directed at maintaining induced leakage at significantly lower values. Further, none of the actual depressurization events have demonstrated significantly increased leakage. The resulting risk estimate was an increase in CDF and CBRF of about 2x104/RY, Human error was the dominant failure to mitigate the event, with some contributions from failures of auxiliary feedwater and high pressure ECCS. Human error probabilities were estimated as 10 / cool down under the conditions resulting from these sequences. Other 8
analyses, documented in draft INEL-0641, used a higher initiating event frequency of 7.6x10/RY, which is dominated by stuck-open valves. Considerations of leak-before-break in the short sections of the steam and feed lines that are not isolable resulted in insignificant contributions to the initiating event frequency. The human error probability estimated in draft INEL 95/0641 is also higher, at 10 /cooldown. A very conservative approach is to substitute 2
these values in the NUREG-1477 analyses. The results would be an increase in CDF and CBRF of about 2xiO /RY if the probability of extensive leakage is still assumed to be 1.0. Note 5
that even following this conservative analysis, the value of containment bypass with core damage given in the DPO is not approached.
At lower leak rates, there is more time for operator actions, so the corresponding human error rate is expected to be much lower than the INEL estimate. Also, since any acceptable regulatory approach (whether it is ultimately a generic letter or the NEl initiative) would limit the allowed leakage under depressurized secondary conditions to much lower values, the results discussed above are considered to be very conservative.
5 L
i i
13 Risk from Station Blackout (SBO) Core Damage Sequence Induced Leakage and Ruptures:
4 When considering interim plugging criteria fur SG tubes under NUREG-1477 and GL 95-05, the staff did not have the benefit of the PRA policy statement to focus its attention on severe accident risk. Nonetheless, the staff assessed the need to consider severe accident effects
]
under IPC, and judged that the amount of allowed tube leakage under IPC was low enough that the existing analyses for tube response under high pressure severe accidents would remain j
valid. The staff assessment was based on the nature of the degradation involved, cracking (ODSCC) that is confined within the tube support plates. The staff reasoned that leakage from confined cracks would be limited and that confined cracks would have low probability of burst.
Cracks were assumed to remain confined since the secondary depressurization involved does
{
not exert the forces on steam generator secondary compor'ents which are postulated during a MSLB. Therefore, tube support plate displacement is not expected. Since the leakage I
calculation detailed in GL 95-05 is based on leakage rates measured from free-span cracks, the staff reasoned that actual leakage would be less. Further, if a confined crack did leak, the jet j
would be deflected by the tube support plate in a direction parallel to adjacent tubes, so that 1
impingement effects could be neglected.
4 Since GL 95-05 was issued, related analysis of MSLB blowdown effects on TSP position relative to the tubes supports the initial staff conclusion that the severe accident risk is not significantly affected under voltage-based repair criteria. Since the dynamic forces during an SBO are less than in a MSLB, the assumption that the cracks will remain within the TSP appears reasonable.
NUREG-1570 addresses the risk of tube failures induced by the high temperature conditions associated with core damage induced by SBO and other similar events. These events are already included in the CDF. Therefore, the consideration of inducing extensive tube leakage or ruptures increases risk only by increasing the frequency of releases that bypass containment.
The CDF remains unchanged. For this study, it was necessary to estimate the distribution of flaw sizes that occur in currently operating plants or that would exist in plants meeting the criteria in the proposed generic letter and draft regulatory guide. This is a very uncertain and sensitive parameter in the risk assessment process. Therefore, the staff considered a range of flaw distributions in its risk assessment. The results of a demonstration calculation for a Surry-like plant indiMe that the CBRF from tube failures during the SBO core damage sequences is approxim.
y 3.9x10/RY. About 39% (i.e.,1.5x105) of this comes from failure of mflawed tubes in sequences where reactor coolant pump seals have failed and the coolant loop water seal has cleared on a loop where a steam generator secondary has become depressurized. Of the 61% (i.e., 2.4x10'/RY)that comes from failure of flawed tubes, about 1.5x108/RY is induced by the elevated differential pressure before temperatures increase, and about 9x1Cf/RY is induced by the high temperatures that occur later in the sequence. Specific issues associated with the relationship of tube flaws and high temperature conditions, specifically the effects of tube leakage, are further addressed in the response to issue 5 below.
Response to Issue 4. " lodine Spiking Issue":
DPO Author's Premise
l 14 In the July 13,1994 memorandum to the Executive Director for Operations (EDO) regarding the use of voltage-based interim repair enteria for SG tubes (GL 95-05), the DPO author stated that the use of the iodine spiking factor of 500 cannot be supported for the assessment of MSLB accidents for those plants which implement the voltage-based repair criteria. The DPO author postulated that, should such plants experience a MSLB, the large differential pressure between the primary side coolant and the broken steam line would initiate an iodine spike (increase in release rate of iodine from the fuel to the reactor coolant) response which would be larger than the spiking value of 500 commonly assumed by the staff and licensees in their accident I
analyses.
The spiking factor of 500 originates from the SRP Sections for the MSLB and SGTR and is a common assumption in the analysis of the consequences of such accidents. In the performance of typical SRP evaluation, it is usually assumed that the reactor coolant is at the technical specification (TS) allowable 48 hour5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> value for dose equivalent"'l, typically 1 pCi/g. When a plant implements the voltage-based criteria, the DPO author postulated that the consequences of a MSLB accident would be exasperated by the event-induced leakage from the tubes to which GL 95-05 criteria was applied. The author postulated that for these circumstances the iodine spiking factor would be greater than 500.
The DPO author also indicated that steps taken by licensees to reduce the TS allowable 48 hour5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> l
value for dose equivalent l in primary coolant to offset the increase in doses resulting from the primary to secondary leakage emanating from the event-induced leakage is inappropriate and l
can result in Part 100 doses being exceeded. The basis for this premise was at lower primary coolant activity levels, e.g.,0.01 pCi/g, a MSLB accident could induce a spiking factor greater I
than 500, e.g. 750. Consequently, if this premise is correct, reducing the 48 hour5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> TS value for dose equivalent l could have a detrimentr.'. effect on the capability of the plant to meet Part i
100 doses if the amount of activity available for release would actually increase.
Thus, the essence of the DPO author's position is that if the voltage-based criteria is applied to a plant's SG tubes and that plant experiences a MSLB, the result could be an lodine spike greater than the value of 500 commonly applied in present consequence assessments. Licensee's actions to lower the 48 hour5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> value for dose equivalentl in primary coolant does not ensure that doses would be maintained below Part 100 doses guidelines since spiking factors greater than the value of 500 could be experienced at reduced primary coolant activity levels. Thus, the quantity of dose equivalent l actually available for release could increase from the activity which was available for release when the primary coolant activity of dose equivalent'8'l was at 1 pCl/g and the spiking factor was 500. Therefore, Part 100 doses could be exceeded.
Staff Reassessment of Spiking Factor I
in the development of the radiological dose calculation portion of the staff effort to revise the regulatory approach on SG tube integrity, the staff re-assessed the manner in which dose calculations are performed for both SGTR and MSLB accidents involving degraded steam l
generator tubes. One of the principle aspects of the re-assessment was the iodine spiking factor. Differing views of iodine spiking were presented to the staff. On the one hand industry representatives claimed that the iodine spiking factor of 500 was unrealistic and too conservative. On the other hand, the DPO author claims that the iodine spiking factor of 500 is
15 non-conservative when a plant, which has utilized the voltage based criteria, experiences a MSLB. The DPO author claims that this ic particularly true when the primary coolant activity levels of dose equivalent *l are below 0.35 pCi/g. It was necessary that the staff address these two divergent views.
The staff participated in several meetings in which NRC licensees and representatives from EPRI and Nuclear Energy Institute (NEI) discussed iodine spiking. At these meetings, industry representatives indicated that they considered the iodine spiking factor of 500, which is referenced in SRP Sections 15.1.5 and 15.6.3, as too high and unrepresentative of the actual spiking data. To support that position, industry submitted for staff review two reports, one by A.
K. Postma entitled, " Empirical Study of lodine Spiking in PWR Power Plants, TR-103680, Rev.1 and a second by Lewis and Iglesias entitled, "An lodine Spiking Model for Pressurized Water Analysis".
Postma performed an empirical study of the iodine spiking phenomenon in PWRs. The intent of Postma's study was to quantify iodine spiking in postulated MSLB/SGTR sequences. The study included iodine spiking data from over 200 normal operational reactor transients and 2 SGTR events. From these data, Postma developed an empirical model to relate iodine activity levels in the primary coolant to the magnitude of power and pressure transients imposed upon the reactor. The staff had a contractor assess Postma's model. The contractor concluded that, since most of the data utilized by Postma originate from conditions approximating a SGTR rather than a MSLB, these data could be utilized to draw conclusions on iodine spiking for SGTR events. However, absent additionaljustification, these data could not be extrapolated to support an iodine transport analysis for a MSLB event. The staffs contractor concluded that an appropriate justification might be the "first principles" iodine spiking model of Lewis and Iglesias that relates the iodine release from the fuel rods to the primary coolant thermal / hydraulic conditions. However, in order to provide such justification, validation and verification of the Lewis and Iglesias computer code, which implements the model, was necessary. The staff had the contractor proceed with such a validation and verification.
When the contractor performed the validation and verification of the Lewis and Iglesias code, they concluded that the code was insufficiently mature for use. It appeared that the code had not undergone any quality assurance. In addition, the code appeared to have large uncertainties when it was used to predict iodine spiking behavior a priori. This was particularly true when default input parameters were used to predict spiking response. Consequently, the staff concluded that the Lewis and Iglesias code could not be utilized to predict the spiking behavior in the event of a MSLB. Since these conclusions were drawn, industry had not provided any additional insights or information to address the staffs concerns on this model.
In the DPO author's July 13,1994 memorandum to the EDO, it was indicated that iodine spikes as high as 10,000 had been observed. A figure was attached to that memorandum to demonstrate that point. The figure contained the iodine spiking factor as a function of initial l
iodine activity level. The memorandum indicated that the figure was obtained from LER-009/03L-0.
The staff has reviewed existing iodine spiking data. An article by Adams and Atwood published in Nuclear Technology in June 1991 and an earlier article by Adams and Sattison published in a l
l
16 May 1990 issue of Nuclear Technology were reviewed. The Adams and Sattison article was entitled," Consequences of a SGTR Event" and it presented the iodine release rate ratio (spiking factor) for 58 events. The spiking factors ranged from a low of 1.7 to a high of 908. The initial iodine activity level at the time of the event ranged from 0.004 pCi/g to 0.943 pCi/g. The data included three cases where the spiking factor exceeded the SRP value of 500. For each of these cases, the large spiking factors were associated with low initial activity levels of iodine, 0.013,0.014 and 0.02 pCi/g, respectively. For these three cases, the maximum iodine activity level never exceeded 3.5 pCi/g. Concequently, Adams concluded that events in which large spiking factors occurred tended to be associated with moderately small iodine concentrations and, therefore, smalliodine release rates. Adams and Sattison concluded that use of the iodine spiking factor of 500 resulted in an overly conservative analysis for a SGTR with a coincident iodine spike. They recommended that the data base be expanded to include more operational data to reduce the uncertainties associated with their assessment. It should be noted that the data which Adams and Sattison reviewed were only representative of SGTR type of events and not MSLB events.
In an article entitled, "The lodine Spike Release Rate During a Steam Generator Tube Rupture,"
Adams and Atwood performed an analysis to bound the actual maximum iodine activity level for each iodine spiking event. They considered such an analysis necessary because primary coolant samples are not taken continuously in the event of a transient. Samples are typically taken once every four hours. The bounding analysis performed by Adams and Atwood was obtained from data in LERs. Adams and Atwood postulated that the maximum activity level of dose equivalent *l resulting from a reactor trip was no more than a factor of three greater than any value measured 2 to 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> after the trip. Therefore, they bounded the maximum values by taking the actual measured values of primary coolant activity and multiplying them by a factor of 3. Adams and Atwood presented data in a figure which includes not only the bounding value of 3 noted above but also an adjustment to the data based upon the assumption that the maximum activity level will occur two hours after the trip. It is only when the actual measurements have been increased by this factor of three and adjusted to assume that the maximum occurs at two hours after the transient that there arises an instance where one spiking factor is approximately 10,000.
Adams and Atwood concluded that the spiking factor could be reduced. In their article they stated,"... the iodine release rate assumed in the calculation of a SGTR event could be reduced substantially, (e.g., by a factor of 15) and still result in a conservative analysis."
It seemed appropriate for the staff to utilize the existing spiking data to reassess the suitability of me spiking factor. Figure 1, which includes Adams data without the bounding factor of three, presents data on spiking factor as a function of initial primary coolant activity level.
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FIGURE 1 I
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18 The staff had initially anticipated that these data might demonstrate that the spiking factor was a function of initial primary coolant activity level of iodine and that an expression could be developed demonstrating such a correlation. However, no such expression could be developed from the data. The best that could be done was to envelope the data and to state that the spiking factor could be no higher than a given value, independent of the activity of iodine in the primary coolant. Assessing the spiking data independent of the primary coolant activity level, the staff determined the 95% value. This value was 335 for a SGTR event.
Drawing conclusions for the spiking factor for a MSLB is a much more difficult issue to address.
The existing spiking data is representative of a SGTR type of event and not a MSLB event. It is j
not possible to extrapolate the iodine spiking data base for a SGTR event to that for a MSLB in a manner that is rigorously defendable. As an example, if it is the pressure drop rate that dominates the primary coolant iodine behavior, and there is a linear relationship between this l
rate and the resultant iodine activity level or release rate, then one could judge that a MSLB would result in an iodine activity levelincrease of two or three over that of a SGTR event. If the relationship between the pressure drop rate and the iodine release is quadrature, the overall increase would be four to nine. In discussions with Adams, he indicated that the actual mathematical relation between the pressure drop / drop rate and iodine activity level / release rate is not known, however it is reasonable to expect that the relation is probably not of a higher order than a quadrature. In fact, it could be even less, e.g., a square root relation.
Consequently, one could estimate the primary coolant iodine activity level / release rate j
magnitude for a MSLB to be within a factor of 10 times that for a SGTR based upon pressure 1
drops and pressure drop rates being within a factor of three.
As previously noted, Adams indicated that the SGTR spiking factor may be conservative by an order of magnitude. Given that order of magnitude conservatism and the estimation of the increase in an order of magnitude of the MSLB over the SGTR, the staff determined that the two factors tend to offset each other. Absent data from operating plants which demonstrate the effect of a MSLB on iodine spiking, the only means for determining the potential consequences on the fuel of such a break would involve the performance of laboratory tests. Because the MSLB event is an event of much lower probability than a SGTR event, the staff has concluded that there appears to be insufficient justification for performing such tests. Therefore, based upon the above discussion, the staff concluded that a change to the current SRP value of 500 used in the MSLB analysis is inappropriate at this time.
Assessment of DPO Concern To assess the DPO author's concem, the staff performed a parametric analysis to determine the impact of an increase in spiking factor on the acceptability of the consequences of a MSLB event when reductions in reactor coolant activity levels of dose equivalent *l are allowed. The staff performed this parametric assessment utilizing data from a plant which recently received a GL 95-05 repair criteria amendment. This plant was a 3-loop Westinghouse reactor.
In the parametric analysis the staff performed an assessment for a base case. This case was based upon the SRP conditions. For this assessment the staff assumed that reactor coolant activity level of dose equivalent *l was at its 48 hour5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> TS value of 1 pCi/g. Total primary to secondary leakage was at the TS value of 1 gpm with an assumed 150 gpd/SG primary to
19 seconde.iy leak for the intact SGs and the remainder of the 1 gpm primary to secondary leak assumed to be to the faulted SG. Consistent with the SRP for the MSLB accident, a spiking fac'.or of 500 was assumed. Releases were calculated for two time periods,0-2 hours and 0-8 hours, which are representative of the exclusion area boundary (EAB) and low population zone (LPZj doses.
In the amendment which was processed for this particular GL 95-05 repair criteria application, the licensee assumed that it took 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> following the MSLB before the faulted SG was isolated. The staff assumed the same for the base case. it should be noted that eight hours is the maximum time that would be anticipated to elapse before the faulted SG would be isolated and for the reactor coolant system to be depressurized thereby halting any primary to secondary leakage. If the period of time in which the faulted SG was isolated was reduced to less than 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />, a reduction in the release quantities to the environment would occur since the major pathway to the environment is through the faulted SG.
In the parametric assessment the staff assumed that any primary to secondary leakage, even to the intact SGs, was released immediately to the environment. The staff took no credit for partitioning in the intact SGs. While this was a conservative assumption, the staff concluded that, if releases occur for 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> from the faulted SG, the overall impac; of this assumption results in a small contribution to the overall release because of the dominance of the release from the faulted SG.
Because of the variability of meteorology associated with the reactor sites it was decided that the parametric assessment would not calculate doses. Rather it was assumed that the 0-2 and the 0-8 hour releases of'2'l would be calculated for the base case. The parametric analysis would then determine the value for the spiking factor in order to limit the total release of 8'l for any case to the quantity which had been calculated for the base case. For example, if the base case calculated a release of 111 Ci of' 'l for the 0-8 hour period, then the parametric analysis 1
calculated how large the spiking factor could be at a given primary to secondary leak rate and at a given reactor coolant activity level before it resulted in a release of 111 Ci.
Having established the '3'l releases for the SRP case as the basis for the acceptability of a reduced reactor coolant activity level and the primary to secondary leak rate, the parametric analysis was performed for reactor coolant activity levels of 0.5,0.1,0.05,0.01, and 0.005 pCi/g of dose equivalent '*'l. The total primary to secondary leakage rate was allowed to vary.
Calculations were performed at 10,35 and 100 gpm for each of these reactor coolant activity levels. For each case, a determination was made as to how large the spiking factor could be before the releases would be equal to those calculated for the base case. The result of this parametric analysis are presented in Table 2.
l To place into proper perspective the information contained in Table 2, the following example is provided. Table 2 demonstrates that, at certain reactor coolant activity levels, the spiking factor must be less than a value of 500 before the release will be equivalent to that of the base case.
For example, it can be seen in Table 2 that where the primary coolant activity level of dose l
equivalent '8'l is 0.5 pCi/g and the primary to secondary leak rate is 35 gpm, if the spiking factor is above 12.5, the releases of 3'l will be greater than the base case. The standard assumption I
is that the spiking factor is a value of 500. Consequently, for this particular example, if it is 1
I
20 assumed that the base case resulted in a dose which was at the SRP acceptance criteria, in this case 30 rem thyroid, then the dose criteria for this particular case has been exceeded because the spiking factor would have needed to be 12.5 or less. Otherwise, the releases would be greater than the base case. This example from Table 2 clearly demonstrates that, if the desire is to maintain the primary to secondary leak rate at a given value, the primary coolant activity level must be reduced until the spiking factor of 500 or greater is reached. For the above noted example, Table 2 indicates that a primary coolant activity level between 0.01 pCi/g and 0.05 pCi/g would be required.
Summarizing, from Table 2, it can be observed that for some combinations of the primary to secondary leak rates and reactor coolant activity levels, a spiking factor of less than 500 would be required to maintain releases equivalent to those for the base case. This infers that the dose criteria of 30 rem thyroid would be exceeded with the assumed spiking factor of 500. To compensate for the unacceptable releases (doses) necessitates a reduction in either the TS I
i allowable values for primary to secondary leakage or reactor coolant activity level of dose equivalent '*'l. Because the purpose of GL 95-05 amendments is to allow tubes to remain in service and thus, maintain a given primary to secondary leak rate, the item most likely to be reduced would be the reactor coolant activity level of dose equivalent'8'l. The reactor coolant activity would continue to be reduced until the spiking factor was at least 500 thereby assuring that the 30 rem criteria was met for the assumed leak rate. It should be noted that the spiking factor would have to reach at least a value of 5000 (300 rem /30 rem x 500) before a dose would ever reach a Part 100 guideline. In Table 2, at and below 0.01pCi/g, the spiking factors would need to be in the range of 5200-51,800 before the dose guidelines of Part 100 would be exceeded. This is not a likely case. For activity levels above 0.01 pCi/g but less than 1.0 pCi/g the consequences of the analysis push the primary coolant activity level continually down until a spiking factor of 500 is achieved thus, assuring that Part 100 doses could only be exceeded for j
spiking factors greater than 5000. There exists no data to suggest that the spiking factor is likely to be >5000 nor is there data for the SGTR spiking conditions to suggest that even with a factor of 10 increase in the spiking factor, the spiking factor will be greater than 5000. Therefore, the staff concluded that adequate margins exist with present spiking factor of 500 to maintain doses below Part 100 guidelines in the event of a MSLB even at lower reactor coolant activity levels.
I l
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- _ _ _ _ _ _ _ ~
Table 2 Spiking Factors Which Would Result in Releases Equal to Those of the MSLB SRP Case' Spiking Factors" RCS Activity Level fuCi/o Primary to Secur:dary Leak 0-2 Releases '
0-8 hour Releases Dose Eauivalent ll Rate (aom total) s 0.5 100 8.18 35 12.5 26.6 10 86.3 98.6 l
0.1 100 37 57 35 133 150 10 502 511 0.05 100 91 118 t
35-283 305 J
10 1020 1030 l
0.01 100 526 606 35 1490 1540 l
10 5180 5150 l
0.005 100 1070 1220 35 2999 3090 10 10400 10300 I
i
- SRP Case based upon reactor coolant activity level of 1 pCi/g of dose equivalent'8'l, a spiking factor of 500 and 1 gpm total primary to secondary leak rate.
- Spiking factors would need to be multiplied by a factor of 10 in order to equate to a dose of 300 rem thyroid.
- Maximum allowable leak rate would be limited to approximately 60 gpm.
l i
j
V 22 Response to issue S. " Severe Accident issues":
The assessment of the CBRF due to thermally induced failures of flawed tubes, referenced the response to issue 3 above, is based on a probabilistic treatment of the creep behav surge line, hot legs, and steam generator tubes with various flaw sizes. These ana the probabilities of whether axially cracked tubes would fail before other portions of t under the temperature and pressure conditior.s predicted in different SBO core. damage sequences. Those results were then combined with estimated flaw size frequency d to calculate the probability that one or more tubes would fail before another part of the each accident sequence. In these analyses, the staff recognized that through-wall flaws are too short to burst at normal temperatures may burst later when temperatures increas staff also assumed that the effects of impingement of a hot steam jet from one burst tube may l
lead to rapid failure of an adjacent tube due to erosion. So, if a tube was calculated to b t
first RCPB failure, then no credit was taken for later depressurization of the RCS by a subsequent failure of some other component.
Imoact of Small Cracks At tube temperatures before surge line failure, critice.aw lengths for axial cracks (i.e., thos flaws that would burst) were usually in the range of 0.4 to 0.6 inch. In the staff analysis, fla short as 0.26 inch that propagated through-wall during the challenge were assumed to lea severely at high temperatures that they would be equivalent to ruptures. Staff estimat opening of a 0.25 inch long crack at elevated temperatures resulting from erosion and deformation could lead to adjacent tube effects in a short time (minutes to an hour). Howeve the degree of erosion of small cracks due to the high velocity passage of superheated ste has not been directly assessed. Further, the nature of other contributing factors, such as duration of peak temperature conditions, and possible effects of differential thermal ex make an explicit determination of crack opening rate difficult.
The staff acknowledges that under certain conditions of tube degradation and sustained RCS temperature and pressure conditions, crack opening could be a concem. As indic above, the model used in the staff's risk assessment assumed that through-wall crac inches in length would lead to tube failure. The.25 inch length was based on conside corrosion cracking mechanisms and typical aspect ratios observed for cracking mech order to assess the potential for the existence of shorter through-wall cracks, the staff available data from destructive examination of tubes removed from service due to a v typical degradation mechanisms. The evaluation of depth / length ratios of crac appendix, concludes that one type of tube degradation (e.g., primary water stres cracking in the hard roll transition at the top of the tube sheet) presented a concem th small through-wall cracks could be present at a limited number of plants. The staff doe have data to conclusively demonstrate the behavior of very small through-wall cracks un damage conditions. However, based on evaluation of erosion data at similar conditio similar types of materials, the staff has assumed that such defects could induce tube Therefore, consideration of alternate repair criteria will need to include assessment of the accident risk contribution from all degradation in a plant, including possible crack op leakage effects.
1
Leakaoe Effects on SG Inlet Plenum Mixing At the March 5,1997 meeting of the ACRS Materials and Metallurgy / Severe Accidents Subcommittee, the DPO author made a presentation that disputed conclusions reached in NUREG-1570, " Risk Assessment of Severe Accident induced Steam Generator Tube Ruptu A basis of the discussion was that the impact of tube leakage on steam generator inlet plenum mixing during the course of a high pressure core damage event was not considered.
The criteria used in the staff analysis reasonably accounts for the risk that may be contrib tubes leaking during severe accidents, in NUREG-1570, tube rupture was considered the failure criterion contributing to risk, since a large release of fission products could then be anticipated Tube leakage was not considered to have a significant impact since leakage of sufficient magnitude to disrupt natural circulation flows would not be expected unless a tube rupture had occurred. The basis for this can be seen by examining the thermal-hydraulic analyses documented in NUREG/CR 5214 " Analyses of Natural Circulation During a Surry Station Blackout Using SCDAP/RELAP5." The results indicate that hot leg flows of approximately 3 kg/sec can be expected. Using a tube bundle to hot leg flow ratio of 2 (approximation from test results), a tube bundle flow (rn) of about 6 kg/sec can be anticipated. To disrupt the tube bundle natural circulation flow pattem, a leaking tube would need to divert a sizeable fraction of this flow.
To estimat5 the magnituda of leak flow that could be anticipated during the accident, an anticipated crack size was first determined. Under steam generator degradation specific management (SGDSM), accident-induced leak rates of about 100 gpm are conceivable during design basis accidents (DBAs) that result in elevated tube differential pressure. Equations from Appendix I of NUREG/CR-4483, " Reactor Pressure Vessel Failure Probability Following Through-wall Cracks due to Pressurized Thermal Shock Events"(see equations for sub-cooled conditions, below) were used to find the crack size that would result in a leak rate of 100 gpm under elevated differential pressure conditions associated with a DBA. This leakage model is the same as that used in NUREG-1477, ' Voltage-Based Interim Plugging Criteria for Steam Generator Tubes. Using the model, a crack size of approximately 0.12 id was found to correspond to 100 gpm leakage.
During the core degradation phase of the SBO progression, superheated steam will be enter the steam generator from the hot leg. In the analyses forNUREG-1570, tube differential pressures resulting from secondary system depressurization were considered. Thus, the flow through a crack in a tube can be computed assuming choked orifice flow (the choked flow assumption holds since secondary side pressure is below the critical pressure of approximately 1300 psi).
Using the equation for superheated conditions (see below), leak rates for m,nerheated steam under the conditions calculated by SCDAP/RELAPS can be estimated for various crack sizes.
The table below gives estimated leak rates for different crack sizes corresponding to: (1) a 0.25 in long,0.01 in wide opening, (2) a crack corresponding to a 100 gpm leak under design basis accident (DBA) conditions, and (3) a crack equal in size to the open end of a tube (7/8 in. diam.)
24 2
Leak Crack Size (in )
at 0.0025 0.12 0.47 kg/sec 0.027 1.3 5.13 lbm/sec 0.06 2.8 11.31
% of n; 0.5 22 86 Equations for sub-cooled conditions:
m = c A f2 g,p(P, - P,,))
P, = P, - P, P, = 0.5 f1 I*#^
D,,
gap D
f =(2in(
) + 1.74)~2 Equation for super-heated conditions:
**')(*I g*
2 k
m = c A P")RT k+1, r
where A
= crack opening a;ea c
a coefficient of discharge (0.6)
D, a hydraulic diameter f
= friction factor g,
a conversion (32.2 lbm-ft/lbf-sed) k a specific heat ratio (q,/c ) = 1.26 L
= crack length m
a mass flow rate P.
= saturation pressure at RCS conditions P
= RCS pressure o
P, e frictional pressure drop R
= gas constant (85.8 ft-Ibf/lbm-R)
T
= steam temperature in Rankine 5
e roughness height in crack (2x10' in. from NUREG 4483)
25 p
= liquid density @ P.
The first crack size shown in the table,0.0025 irf, would yield about 2 gpm leakage under DBA conditions. In the analysis, this is the smallest size crack that the staff assumed to fail by rupture under the predicted conditions during a severe accident. The steam leakage through this crack is a very small fraction of the total tube bundle flow,0.5% of n; and is not expected to have an impact on inlet plenum mixing. As mentioned previously, small through wall cracks are expected to be present in only a few cases involving one type of degradation.
2 The 0.12 in crack (1 inch long,0.12 inch wide), which corresponds to 100 gpm leakage under DBA conditions, would leak under severe accident conditions at a significant rate compared to the total tube bundle flow. This size flaw is considered equivalent to a tube burst if it is located in a single tube. It is 4 times as long and more than 10 times the area of the crack the staff assumed would burst under severe accident conditions. The largest tube opening shown in the table would divert a very significant portion of the tube bundle flow. These two flaws, which would both be assumed to rupture in the staff's analysis, could be expected to change the mixing conditions. Only the largest leak rate of 11.31 lbm/sec associated with this size opening is in the range of leakage cited in the DPO presentation (10 - 250 lbm/sec). Under the criteria used by the staff in the NUREG 1570 analysis, a tube would be considered failed upon rupture, which could result in crack openings on the order of a tube diameter. Once failed, further analysis of the thermal-nydraulic effects of this magnitude of leakage is not required to assess the risk impact.
Operating experience has shown that the occurrence of tube leakage is often associated with a series of flaws; that there is not only a single flawed tube (e.g., ANO Unit 2,1992; McGuire, Unit 1,1992; Maine Yankee,1990 and 1994). The accident leakage that would be permitted under SGDSM is an aggregate value from all flaws that would leak. Thus, it would be reasonable to expect that in a severe accident situation, the leakage from flaws would be distributed throughout var;ous locations in the tube bundle, and not necessarily confined to one tube or location. Therefore, the leakage effects on inlet plenum flow patterns, and mixing which is expected to occur, should be impacted to an even smaller degree than is indicated by the comparison of leak flow to bundle flow shown in the table above.
Uncertain factors in this discussion are the potential for cracks to open while they leak under severe accident conditions, and for leaking tubes to cause cascading failures. Preliminary staff estimates conclude that through-wall cracks could oWn at a significant rate if the high temperature and differential pressure conditions are sustained. However, the duration of very high tube temperatures is on the order of minutes. Also, the rate of cascading failure predicted in the DPO seems overestimated based on preliminary staff estimates which show only a modest erosion rate for tubes adjacent to a leak.
For analysis of severe accident risk, the staff chose 0.25 inch as the crack length at wnu, a assume tube failure during severe accident thermal challenge. Based on a subsequent staff assessment of data from destructive examination of degraded tubes removed from operating piants as well as its assessment of leakage effects from cracks, this criterion is reasonable. The staff believes that there is a potential for through-wall cracks shorter than the staff's threshold of
26 0.25 inch to exist in a small number of plants. However, the risk significance of such defects requires further understanding of the frequency and nature of the plant specific sequences that could challenge tube integrity. The staff plans to investigate sequences in conjunction with the IPE follow up program.
Fission Product Deoosition and Heatina By letter dated May 20,1998, the DPO author forwarded to the ACRS slides from a presentation given by a Japan Atomic Energy Research Institute (JAERI) representative at the May 1998 Cooperative Severe Accident Research Program (CSARP) meeting. The JAERI analysis addressed the additional heating of steam generator tubes, during a station blackout sequence with secondary side depressurization, caused by the deposition of fission products on the inner tube surface.
The JAERI analysis, while it predicted the steam generator tubes would survive the transient, with a small margin, also predicted substantial fission product heating of the steam generator tubes due to the deposition of fission products. This is in contradiction to the NRC conclusion, based on analysis, that the effect of deposited fission products in tube heating is trivial. The staff, therefore, evaluated the JAERI analysis to understand why it produced substantially different results concerning fission product deposition, from corresponding NRC calculations.
A review of the JAERI analysis revealed several differences from the NRC evaluation. First, it was learned that the JAERI analysis assumed the temperature of the steam entering the tube bundle was equal to the temperature of the unmixed vapor in the steam generator inlet plenum (from the hot leg). Assuming the temperature of the steam entering the tube bundle is equal to that of unmixed vapor from the hot leg is a severe conservatism; in contrast, the NRC analysis includes mixing of steam in the inlet plenum based on experimental data. (Use of unmixed vapor temperatures would produce excessively high tube temperatures irrespective of fission product deposition.) Use of the temperature of the unmixed vapor in the steam generator inlet plenum as the temperature of the vapor in the tube in the JAERI analysis apparently resulted in a temperature difference between the vapor and the steam generator tube wall of up to 250K inside the first section of the tube. It is this high temperature difference that is responsible for a large thermophoretic fission product deposition in the JAERI calculation. It is unrealistic to assume such a large temperature difference in this region without water on the secondary side of the steam generator given the heat transfer across the thin tube wall. The NRC's analysis showed a temperature difference of about 15K in this region, which results in minimal deposition by thermophoresis.
The NRC's VICTORIA code analysis of this sequence showed that the dominant mechanism for deposition was settling inside of the steam generator u-tubes onto the upward facing surfaces in the bends of the u-tubes. This is reasonable given the recirculatory flow patterns in the RCS and the lack of other driving forces for deposition other than settling. The JAERI analysis did not appear to model settling on upward facing surfaces inside of the steam generator u-tubes.
Finally,in another area, the JAERI analysis did not explicitly consider the primary source of heat (i.e., cladding oxidation)in their calculation of heat up of the steam generator tube wall. The relative importance of deposited fission product heating was determined by JAERI by comparison against the heat carried to the tubes by superheated steam heated only by decay
27 heat in the core. Because of their thermal hydraulic assumptions and analytical treatment, the staff concludes that the finding of the JAERI analysis, relative to the significance of fission product heating, is not relevant to our evaluation of this matter. As a result, the staff's previous conclusions regarding the severe accident risk implications of degraded steam generator tubes remain unchanged.
Conclusion The staff recognizes that alternate repair criteria could be proposed that might lead to the presence of short through-wall cracks. As mentioned previously in this document, the staff is encouraging licensees who propose alternate repair criteria to follow risk-informed approaches which may mean that licensees will need to address the issues discussed in this section as appropriate dependent on the nature of the proposal. Currently, with the exception of accident leakage rates associated with GL 95-05 repair criteria (which represent a different risk concem j
due to the confined nature of the cracks), accident leak rates for all other forms of degradation are limited to current licensing basis values (typically 1 gpm or less) which is well below the leakage rates contemplated above (i.e., on the order of 100 gpm). The staff will not approve any proposed repair criteria as an alternative to compliance with existing deterministic requirements if it unacceptably increases risk.
i Appendix STEAM GENERATOR TUBE FLAW GEOMETRY 2 The assessment of steam generator tube degradation identified during eddy current examinations has historically focussed on tubes with indications that could potentially challenge the structural and leakage integrity of the tube under postulated secondary side depressurization events. However, only a limited amount of information is available on the number of tubes that contain degradation smaller in size relative to the larger, more significant flaws that are readily detected during eddy current examinations. Under severe accident conditions, elevated pressures and temperatures may induce steam generator tube failure by a time-dependent failure mechanism of short, through-wall flaws that exhibit no or marginal signal response during nondestructive examinations (NDE). Because of the limitations in inspection technology, it has been postulated that the existence of these flaws could lead to steam generator tube failure l
under severe accident conditions, in order to have the potential for failure, these undetected flaws must have a through-wall or near through-wall morphology to introduce a primary-to-secondary leak path that will eventually lead to ablation of the flaw surfaces and expand the dimensions of the defect. This could then lead to increased primary-to-secondary leakage of hot gases through the defective tube and subsequent failure of surrounding tubes by jet impingement.
The risk from the failure of longer, through-wall steam generator tube defects (length >0.25 inches) under severe accident conditions has been examined in previous work and is conservatively included in the risk assessment model. In order to address the issue of short crack failures under severe accident conditions, a scoping study was completed that included a review of metallurgical data obtained from steam generator tube destructive examinations and correlations developed relating flaw depth and length. The focus of the study was to attempt to determine if there is a significant population of tube defects in steam generator tubes characterized by short lengths (<0.25 inches) with through-wall or near through-wall depths that could develop primary-to-secondary leaks in the freespan tube areas under severe accident conditions.
Backaround Utilities occasionally submit to the NRC distributions of steam generator tube flaws as a function of some NDE parameter. These can be used to explain the overall significance of the I
degradation identified during an inspection in terms of the total number of degraded tubes identified and the r.ature of the indications in terms of NDE measurements (e.g., voltage, et'.imated length, depth). Figure 1 represents the typical form for an end-of-cycle voltage distribution of outside diameter stress corrosion cracking (ODSCC) indications at tube support plate (TSP) intersections. As seen in the figure, the number in some cases, the figures discussed in this report contained proprietary information and have therefore been removed from this report to enable this document to be made publicly available.
2 of indications is low within each voltage bin for low voltages but increases rapidly for slightly larger voltages. At higher voltages the number of indications gradually tails off toward zero.
Figure 1: Voltage Distribution 120 100 l
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3 s
j40 i
2 20
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0_
0.1 OJ 03 04 0.5 94 0.7 08 0.0 1
1.1 12 1.3 1.4 1.5 1.6 1.7 1.8 von..
These characteristics are consistent with voltage distributions reported to the NRC for indications detected at drilled tube support plate intersections. In addition, this observation is consistent with other reported distributions such as that depicted in Figure 2. This figure shows the number of flaws as a function of the estimated average crack depth. Again, the number of indications increases, peaks at some value, and then decreases toward the tail of the distribution.
Figure 2: Crack Distribution 25 l
2 0 --
i g15 --l I
I
)10 5-I 7,
o 0
10 20 30 40 50 60 70 80 90 100 Average Crack Depth (%TW)
Although these distributions could lead one to conclude that flaws with low voltages or limited through-wall depth occur less frequently than those with slightly higher voltages or depths, this would not be a valid conclusion for several reasons. First, the above figures are representative data derived from eddy current inspections. Although sensitive to small flaws, eddy current technology has limitations. Steam generator tube defects that exhibit lower voltages will, by
3 definition, have only a smallinfluence on the eddy current signal. Since degradation generally occurs in crevice locations or in areas where the tube geometry is changing, other signals may overwhelm the defect response and mask its detection. Data analysts will also influence the threshold of detection for tube degradation. Although the inspection system may display a distortion due to the presence of a flaw, an analyst may not be as sensitive to these small signal changes compared with the signals from more obvious indications. A true flaw size distribution cannot be obtained from eddy current inspection data for smaller flaws (length, depth, voltage) because of the limitations of the analysts and the sensitivity of the technology used for steam generator tube examinations.
In order to better understand the distribution of cracks below the threshold of detection for eddy current inspection techniques, examining data in figures similar to that in Figures 1 and 2 is of little value due to the limitations of NDE. An estimate of the number of flaws below the NDE threshold could be ot'tained by extrapolating the distribution to fewer voltages and depths.
However, extrapolating the data may introduce additional errors and incorrectly model the actual population of flaws over the range of the extrapolation. Although it may be reasonable to conclude that there is a larger number of much smaller tube defects than shown in flaw 4
distributions obtained from eddy current inspection data, based on NDE data, little can be said for the morphology of these flaws.
To determine if a significant population of short, through-wall flaws exist within operating steam generators, metallographic examination data from tubes removed from inservice steam generators (i.e., pulled tubes) were reviewed. The pulled tube data assessment included a review of data for several different modes of steam generator tube degradation: (1) axial primary-water stress corrosion cracking (PWSCC) at dented tube support plate (TSP) intersections, (2) outside-diameter stress corrosion cracking (ODSCC) at TSP intersections and tubesheet expansion-transitions, (3) PWSCC at tubesheet expansion-transitions, and (4) pit-like intergranular attack (IGA) indications. Considering that the focus of most tube steam generator pulls is obtaining information on larger, more potentially significant defects, the amcunt of metallurgical data on short flaws is limited and sometimes biased. Nevertheless, some data have been reported to the NRC that include details on the shorter, less significant steam generator tube degradation.
One set of data examined in this study included lengths for PWSCC flaws at tubesheet roll transitions. The focus of the report from which the data were obtained was to quantify the leakage through axial PWSCC flaws [1]. Therefore, the data presented in the report only included flaw lengths associated with through-wall cracks that leaked during testing. It is likely that a number of short, part through-wall flaws existed in the tube sections examined in the PWSCC leakage study. However, because these cracks did not leak, these data would not normally be reported in such a study.
4 Discussion The threshold of detection for eddy current inspection methods is particularly sensitive to the volume of material affected [2]. That is, if a sample of flaws has similar electrical and geometric properties (i.e., orientation), then the eddy current response will largely be a function of the relative size of each indication. Results from actualinservice inspections of steam generator tubes indicate that eddy current inspection techniques are very capable of detecting part through-wall defects in steam generator tubes with lengths on the order of 0.25 inches.
Although eddy current techniques can detect shorter flaws, it is assumed for this investigation that all through-wall flaws exceeding 0.25 inches in length would have a high degree of detectability.
Surface flaws can take on an infinite number of geometries with varying lengths and depths.
One approach used in fracture r chanics to simplify the description of flaw geometry is to assume a semi-elliptical flaw shape [3]. With this assumption, a surface breaking flaw can be described by two parameters, the length along the surface and the through-wall depth. Given that the longest flaw length considered here is 0.25 inches and assuming a maximum tube wall thickness of 0.050 inches, the bounding flaw aspect ratio (length-to-depth ratio) is five. Since the focus of this assessment is on short, through-wall cracks, such flaws would have aspect ratios less than this bound.
Many data were available from destructive examinations of tubes containing ODSCC indications at TSP intersections. Although this mode of degradation is confined within the TSP and leakage from these flaws could not impinge on neighboring tubes, this mode of degradation is similar that found in other areas of the tube. ODSCC at TSPs and cracking that develops above the tubesheet in the sludge pile both develop in low stress, tight crevice tube areas. The morphology of the flaws that develop in these areas is expected to be similar. Therefore, it is assumed that conclusions can be drawn for sludge pile cracking based on an examination of the data that exists for cracking within TSPs.
Evalustion of Pulled Tube Data Data shown in Figure 3 represent the results obtained from destructive examinations of tubes removed from Diablo Canyon, Unit 1, in 1995 [4]. The tubes contained OD and ID axial and OD circumferential defects located at dented and non-dented drilled tube support plate intersections.
The tube pulls targeted the larger, more significant indications of degradation. However, not all of the flaws presented in Figure 3 were detected by eddy current inspection techniques prior to pulling. With one exception, all of the flaws had lengths on the order of 0.2 inches and maximum crack depths significantly less than through-wall. The only flaw that penetrated through the entire tube wall was the long axial indication that was easily identified with bobbin coil and rotating pancake coil probes.
.-..m.
5 i
4 Figure 3. Diablo Canyon Tube Pull Summary (contains proprietary information]
The licensee characterized the data in Figure 3 as the macrocrack analysis results. Additional flaws were identified in the destructive examinations; however, the level of detail was less than i
that provided for the above data. Some useful information was provided on the overall number and depth of less significant flaws identified from the destructive examination. For instance, at one TSP intersection an estimated 33 OD cracks were observed at the mid-TSP level.
Additional cracks were seen at other locations as well. The maximum and average crack depths determined from transverse sectioning of the tube specimens were 24 and 11-percent through-wall, respectively. Therefore, although a sizable number of flaws were seen in the metallographic analyses, all of these were shallow. A similar observation regarding flaw depths was made at one other TSP intersection. Four other TSP intersections were either defect free or found to have only a small number of shallow OD defects.
The Steam Generator Degradation Specific Management (SGDSM) database contains a substantial amount of pulled tube data on ODSCC at TSP intersections. The data in this database are classified by tube diameter, either 3/4-inch or 7/8-inch. Figure 4 contains the j
information available in the database on flaws that leaked during leak rate testing (5). The ID/OD flaw ratio represents the total length of crack on the ID surface divided by the OD length.
Since the flaws originated from the OD, these values are generally less than unity. As seen from j
the figure, many of the data were obtained from laboratory grown cracks from model boiler tests.
In addition, these flaws appear to have more extensive through-wall degradation than that observed in the pulled tube samples. As seen from the data no through-wall cracks were identified with OD lengths less than approximately 0.25-inches. Therefore, the 7/8-inch pulled tube data in the SGDSM database does not support the assertion that short through-wall flaws j
exist in large numbers. In fact, based on the available data, no short through-wall flaws were present. One note, the data in this figure represents only those tubes that leaked during testing.
Therefore, the samples used in the SGDSM database may contain through-wall cracks that did not leek at elevated pressures.
e Figure 4 Geometry of ODSCC TSP Flaws (7/8" Diameter Tubes)
(contains proprietary information)
Figure 5 represents a similar set of data for 3/4-inch diameter tubes (5]. The 3/4-inch database is more extensive than that for 7/8-inch tubing. However, the conclusions that can be drawn from the data are similar. Once again through-wall cracks were only observed for those flaws that were longer in length, and with one exception for the pulled tube samples, leakage was not observed except for axial defects exceeding 0.45 inches in length.
Figure 5 Geometry of ODSCC TSP Flaws (3/4" Diameter Tubes)
(contains proprietary information]
4
6 Pulled tube destructive examinations of ODSCC samples removed from the Trojan steam generators included a detailed assessment of microcracks in a number of the samples. Figu shows some of the length-depth flaw data reported for these tubes [6]. Although Trojan data are included in the SGDSM database, data shown in Figure 6 are not included in Figure 4. One observation from Figure 6 is that the metallographic examinations identified numerous short, part-through-wall cracks. Despite that large number of flaws present, no cracks penetrated through to the ID surface.
Figure 6 Trojan Microcrack Data
[contains proprietary information)
The examination of Trojan microcrack data is a conservative approach to verify the likelihood of occurrence of short, through-wall flaws. Specifically, since these microcracks are generally part of a larger network of cracks, these flaw networks are much more detectable by NDE techniques. If the flaws shown in Figure 6 are representative of the population of TSP cracks and other flaws that develop in low stress crevice locations, then it appears unlikely that there is a significant number of short (i.e., < 0.25 inch) flaws that have the potential for leakage.
Figure 7 includes the same data as Figure 6 with the through-wall depth shown in absolute dimensions rather than as a percentage of tne wall thickness. What becomes more apparent in examining Figure 7 is that most of the flaws had an aspect ratio greater than one. This suggests that ODSCC at TSPs is more likely to grow in length than in depth. Therefore, comp %
through-wall flaw penetration is not expected except for longer (i.e., >0.25 inch) defects.
Figure 7 Trojan Microcrack Data
[contains proprietary information)
Most of the data presented to this point have come from degradation located at TSP intersections. Although these flaws may not be a significant consideration during severe accident conditions due to the restraint provided by the surrounding TSP, it is assumed that the morphologies observed for these defects is representative of degradation in crevice locations with no elevated stresses. Such degradation could exist in the sludge pile region above the tubesheet secondary face remote from the expansion-transition or within the crevice of a partially expanded tubesheet. Based on data shown in Figures 4,5, and 6, it appears unlik that short, through-wall flaws exist in TSP crevices. Given the similarity between the flaws develop in TSP crevices and within the sludge pile region, there is a low likelihood that short, through-wall cracks exist in the sludge pile area of steam generator tubes.
IGA degradation in the freespan areas has recently become an issue of increased attention.
Although a relatively small number of tubes have been identified with these indications, pull tube data suggest that many of these indications may go ur, detected with current NDE technology. Tubes were removed from the Crystal River, Unit 3 (CR-3), steam generators to assess the burst and leakage integrity of IGA degradation indications located above the lower tubesheet. Some of these data are shown in Figure 8 [7]. Tube defects were identified in the destructive examinations by visualinspection of the OD tube surface. Therefore, all potentially significant degraded areas should have been located in the metallographic examinations l
I
7 of these flaws were not identified by eddy current inspections completed prior to or after the tube pulls.
Figure 8 Patch IGA Indication Geometry Crystal River 3 Pulled Tube Data (contains proprietary information]
One observation from the data in Figure 8 is that IGA defect length and depth appear related.
By extrapolating a regression to these data, a through-wall defect would not be expected until the length of the defect is approximately 0.16 inches. Although this value falls below the 0.25 inch threshold established for this investigation, what does remain clear is that the depth of IGA is related to length. Hence, one would not expect to identify a sizable population of similar IGA degradation exhibiting short lengths and extensive through-wall penetration. Since IGA is essentially three-dimensional degradation (i.e., volumetric versus crack-like), the detectability of these indications willincraase significantly with increasing length, depth, and width. Some of the indications detected by eddy current during the CR-3 inspections were found to have axial lengths as low as 0.02 inches. Despite the short lengths of some of the degraded areas, the bobbin coil probe was able to detect some of these indications. In addition, the large volume associated with deeper defects facilitates thsir detection during eddy current examinations.
Based on previous experiences with IGA degradation, this mode of degradation appears more resistant to development of a leak path than other forms of tube wall damage (e.g., ODSCC).
Although the licensee for CR-3 has identified a several hundred of these IGA patches in its steam generators, primary-to-secondary leakage has not been attributed to these indications. In addition, a number of tubes that recently underwent in-situ pressure testing did not leak. Pulled tube specimens obtained from CR-3 were burst tested to assess their structural and leakage integrity. The tubes were able to retain internal pressures on the order of 10000 psi without any measurable leakage prior to burst. Therefore, the IGA degradation in the tubes removed from CR-3 would not challenge the structuralintegrity of these tubes during design basis depressurization events.
Figure 9 presents data obtained from a report by the Electric Power Research Institute (EPRI) on axially oriented PWSCC degradation located in the roll transition zone (RTZ) [1]. The data only include through-wall cracks from pulled tube samples to assess leak rates. The ID flaw lengths ranged from 0.06" up to 0.3". However, most of the data are located in the interval between 0.1 to 0.2 inches. Given that this is the area of interest for this assessment, the PWSCC data from the EPRI report is a useful resource. The vertical axis in the figure represents the ratio of the OD to ID crack length as measured from destructive examinations.
Figure 9 PWSCC Flaws at Roll Transitions (contains proprietary information]
One notable difference between the data presented in Figure 9 and that shown in the previous figures is that it is widely scattered with no apparent relationship between the crack length measured on the OD of the tube to that on the tube ID. In the previous figures, the flaw depths generally increased as the crack length on the surface increased. In general, this behavior is typical for surface initiated flaws. However, the data in Figure 9 do not follow this convention. If
-~ __ _._
8 flaw depth is dependent on the length, or vice-versa, one would expect to find an increasing length ratio with increasing ID length, but this is not the case with the PWSCC data repor EPRI. Since the data were obtained from only nine pulled tube samples, it is reasonable to conclude that there is the potential for short, through-wall cracks to exist in the RTZ. Also, given
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that leakage was observed from each of the pulled tube samples, one cannot rule out the possibility that the leakage odginated from some of the shorter cracks.
Crackina in Exoansion-Transition Zones Some steam generator designs secure the tubes in the tubesheet with a partial depth roll expansion. This is a hard roll that begins at the primary face of the tubesheet and extends several inches along the tube before terminating within the tubesheet bore. B&W once-through steam generators (OTSGs) and a small number of Westinghouse models have partial depth expanded tubes. Because the hard roll terminates within the tubesheet, primary jet impingement of hot gases on adjacent tubing during severe accident conditions is precluded, incidently, axial cracking at RTZs is a significant mode of tube degradation for Westinghouse steam generators with partial depth expansions. Inspections of roll expansions in B&W OTSGs and pulled tube destructive examination results have identified only a small number of cracks in the RTZ to dat'e.
The geometry of RTZ cracking appears different from the ODSCC at TSPs and IGA degradation discussed previously. Further discussion on the differences between the cracking in these areas is warranted to address the potential existence of short, through-wall flaws. Steam generator tube RTZs are highly stressed areas of the tube. Analytical calculations and experimental measurements have concluded that the stresses in these areas are greater than in other stressed areas of the tube such as dents and tight radius U-bends. The residual stress field in the transition zone introduced from the rolling process produces stress levels much greater than that from primary-to secondary differential pressures.
In order to eliminate the crevice areas of partial depth roll expanded tubes, steam generators later utilized a full depth hard roll expansion. The primary difference between these two types of expansion joints is that the RTZ exists at the top of the tubesheet in full roll designs. Despite the elimination of the crevice region, a dominant mode of tube degradation in RTZs continues to be axial cracking. EPRI completed one investigation into RTZ cracking for tubes removed from the Ringhals 2 steam generators [1]. The Ringhals 2 steam generators were the Westinghouse Model 51 design with a partial depth hard roll expansion. Destructive examinations of pulled tubes concluded that most of the axial PWSCC was located within the transition zone extending up toward the upper transition region. Since the RTZ for full depth expanded plants exists at the top of the tubesheet, it is reasonable to conclude that RTZ cracking is similar to cracking in the freespan area of the tube with regard to primary-to-secondary leakage. Therefore, the existence of many short, through-wall axial cracks that could be a factor under severe accident conditions is possible for steam generators with full depth hard roll expansions.
There are currently nine plants in operation (33 steam generators) with full depth hard roll expansions. However, the utilities for five of these plants (19 steam generators) will replace the steam generators within the next four years with designs that incorporate more corrosion resistant materials and tubes with expansion-transitions that are less susceptible to stress
9 corrosion cracking. Although roll transitions have the most severe state of stress with respect to the development SCC for all methods of expanding tubes into tubesheets, a closer investigation of the mechanisms of cracking within explosive and hydraulic expansions is warranted.
Axial cracking in explosively-expanded steam generator tubesheet joints has been identified by a number of utilities. This applies to steam generators designed by Westinghouse and Combustion Engineering. Limited data are available on the location of axial cracking relative to the top of the tubesheet for these steam generators. However, a recent assessment of inspection findings in the Salem, Unit 1, steam generators concluded that all but nine of 177 axial flaws (ID and OD) were located below the top of the tubesheet [8). Although this conclusion is based on NDE insisction results and not pulled tube destructive examinations, it is clear that the axial cracking in the explosively expanded tubes at Salem favors an area of the expansion-transition that is located below the tubesheet secondary face. Therefore, if short, through-wall cracking similar to that found in RTZs develops in explosively expanded tubesheet I
joints, then it is most likely to occur in an area of the tube where primary to-secondary leakage l
would not impinge on neighboring tubes.
i l
The current method of forming the tubesheet expansion joint is to hydraulically expand the j
tubing into an interference fit within the tubesheet bore. The majority of steam generators that entered into service since the early 1980's were fabricated with hydraulic tubesheet expansion l
joints. Cracking experience in hydraulically expanded tubing has been limited to date. There are no operating plants with these expansion joints that have identified significant levels (i.e.,
large numbers) of flaws in the transition zone. This is believed to be a reflection of the lower much stresses introduced from the hydraulic expansion process (9]. Nevertheless, given enough time, these tubesheet expansion joints could develop cracking similar to degradation presently observed in steam generators with rolled or explosively-expanded tubesheets. By design, however, the expansion-transition in hydraulically expanded tube terminates below the top of the tubesheet. Therefore, primary-to-secondary leakage from short, through-wall cracks in a hydraulic expansion-transition should impinge on the bore of the tubesheet and not an adjacent tube.
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i 10 Circumferentially-oriented SCC in tubesheet expansion-transitions affects a number of steam generators. Because this mode of degradation cannot be adequately detected using bobbin coil eddy current probes, utilities employ more sensitive inspection probes to assess the condition of tubesheet expansions, in addition, numerous tubes have been removed from steam generators in order to assess structural and leakage integrity as well as eddy current sizing capabilities.
Entergy, the licensee for Arkansas Nuclear One, Unit 2, (ANO-2) submitted a report that included a correlation relating the cracked percentage of tube wall (percent degraded area (PDA)) to the nominal through-wall crack length [10]. Although the NRC staff has not evaluated the validity of the data supporting the correlation, the relationship indicates that a through-wall crack would be expected when PDA is on the order of 10-percent. Using this data along with the dimensions of the tubes at ANO-2, ar.d assuming a single, semi-elliptical flaw geometry, a through-wall crack would be anticipaid when the overall crack length exceeds approximately 0.28-inches. Circumferential flaws with such lengths should be detected with present day inspection technology.
It has been noted in many instances that circumferentially-oriented cracks in expansion-transitions are actually a series of shorter length flaws separated by smallligaments. However, due to limitations in eddy current inspection technology and for additional conservatism in i
assessing structuralintegrity, smallligaments are often ignored. If these ligaments are l
accounted for in determining the actual crack lengths, the nominal flaw aspect ratio i
corresponding to a through-wall crack should decrease. Destructive exarnination results of l
pulled tubes containing circumferential cracking do not show evidence of a large number of short and deep cracks, but these examinations have identified networks of circumferentially oriented l
flaws. The presence of multiple flaws at the same axial tube location improves the chances of l
detecting this mode of degradation. Therefore, it is unlikely that numerous tubes are left in service with undetected, short, through-wall, circumferential flaws.
Crackino in Other Hiah Stress Locations Cracking in tubesheet expansion joints has been responsible for a large number of tubes removed from service due to corrosive degradation. This is primarily due to the higher susceptibility to SCC at this location because of the elevated residual tube stresses and temperatures. Tube small radius U-bends and TSP denting are other locations where high stresses favor the initiation of SCC [9]. In fact, early operating experience indicates that cracking in short radius U-bends and RTZ cracking appear after a similar length of service. This would indicate that stress levels (although not necessarily stress distribution) in these two regions are comparable. Several studies have concluded that residual stresses in the U-bend l
region are similar in magnitude to those in expansion-transitions. Although dented locations l
also exhibit elevated residual stresses, the potential existence of short, through-wall flaws at l
these locations will not be addressed here because primary-to-secondary leakage from these l
flaws would impinge on the adjacent structure partially responsible for the development of the dent.
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11 Cracking in low radius U-bends has been primarily associated with Westinghouse designed steam generators wit' Sw temperature mill annealed (LTMA) alloy 600 tubing. This mode of l
cracking has causer e utilities to take preventative measures in an attempt to mitigate the l
problems from U-bc..id degradation. Preventative plugging of low row tubing and additional heat treatments are two examples of these measures. Historically, U-bend cracking has been a difficult mode of degradation to detect. Despite the problems associated with managing this mode of degradation, only limited pulled data is available. Because cracking in the U-bend cannot be extracted by removing the tube from the primary inlet plenum (i.e., bbe pull),
i specimens must be " harvested" from the secondary side of the steam generatoi. Due to the complexity of this operation, the removal of U-bend tube sections has been attempted only on a few occasions.
Portland General Electric Company, the licensee for the Trojan Nuclear Plant, completed an effort to evaluate U-bend cracking in the early 1980's. Twenty-six row one tubes and three row two tubes were removed for metallographic analysis.. The destructive examination of the row 2 l
tubes did not reveal the presence of any cracking. Although the Trojan study did not include the lengths and depths of U-bend flaws, it did discuss some of the findings on crack geometry identified from tubes removed from Surry 1 and Turkey Point 4. PWSCC found in tubes removed from these units were characterized as "intergranular and extended halfway through I
the tube wall (aspect ratio of -4)." This observation leads one to the conclusion that, on average, through-wall cracking would not be expected until the flaws have lengths on the order t
- of 0.2 inches. Therefore, U-bend flaw aspect ratios would seem to be greater than cracks l
observed at other high stress locations such as roll transitions. Thus, the potential for short, through-wall cracks in tube U-bends appears unlikely based on these findings.
j One additional note on low radius tube U-bend cracking is that only a limited number of plants are currently affected by this mode of degradation. Recirculating steam generators fabricated by l
l Combustion Engineering have not experienced U-bend cracking similar to that observed in i
Westinghouse designed steam generators. With one exception, U-bend cracks have only been found in LTMA alloy 600 tubing. Once-through steam generators are a single pass design that do not have U-tubes. Therefore, this mode of degradation cannot occur in these steam generators. These observations further narrow the population of plants that are affected by U-bend cracking.
l Other Forms of Steam GeneratorTube Crackina l
Recently, indications of freespan cracking have been identified in both Combustion Engineering l
and Babcock & Wilcox designed steam generators. The industry has generally described the mode of degradation as long indications of lGA. Pulled tube destructive examinations have confirmed that the depths of detected indications are generally less than 50-percent of the total wall thickness. In order to assess the structural and leakage integrity of freespan cracking, l
licensees have removed several tubes with indications and completed burst and leakage testing.
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The data indicate that short, through-wall freespan cracks are not present for this mode of degradation. In addition, burst test results have demonstrated that these tubes have considerable margins for tube structural integrity. Burst pressures for axial freespan cracks in j
tubes removed from the Calvert Cliffs steam generators (CE) were measured on the order of 4
12 undegraded tubing [11]. Leakage has not been attributed to these flaws during operation, during in-situ pressure testing, or observed in testing conducted after tube removal.
Conditions Necessarv for Short. Throuch-wall Cracks This assessment identified one location susceptible to short, deep steam generator tube flaws.
Tubes with hard roll expansions have the conditions suitable for the development of this mode of cracking. The unique geometry of RTZ cracking is likely a consequence of the elevated stresses introduced into the tube by the rolling process. No other locations in a steam tube will have stress levels resulting from the steam generator fabrication processes equal to or greater than those in RTZs. Although the development of RTZ flaws is result of a combination of susceptible materials, environmental conditions, and residua! tube stresses, the uniqueness of the morphology of the cracking originates primarily from the state of stress in the material. It may be reasonable to assume that extremes in the other factors for stress corrosion cracking could also lead to flaws with atypical geometries.
With respect to material susceptibility to stress corrosion cracking, steam generator tube materials are relatively homogeneous. It is unlikely that extremes in tube material chemistry would be isolated to areas less than a fraction of an inch giving rise to short, through-wall cracks.
Crevices, favorable for the development of stress corrosion cracking, can exist at several locations along a steam generator tube: (1) tubesheet crevices, (2) TSPs, (3) U-bend supports, (4) in the preheater region for certain steam generator designs, and (5) above the tubesheet in the sludge pile. Deposit buildup on tube surfaces has also created freespan crevices that led to cracking, but the number of reported occurrences for this type of degradation has been limited to date. Crevice conditions could potentially exist over a very short length of tubing. However,in general, each of the tube crevice examples given above have length scales larger than the 0.25 inch threshold considered in this study. In addition, crevices primarily result from the tube lying adjacent to a support structure on the secondary side of the steam generator. Potentialleakage through any defects originating within the crevice should impact the structure responsible for creating the crevice rather than a neighboring tube. Therefore, it is likely that short, deep flaws with the potential for freespan leakage will only initiate in areas of the tubing where elevated residual stresses exist.
Conclusion in order to evaluate the plausibility of the existence of a significant population of short (i.e., <
0.25 inch), through-wall steam generator tube cracks destructive examination data were reviewed to assess flaw geometries. The purpose of this assessment was to determine if undetected cracking could lead to primary-to-secondary leakage and subsequent hot gas jet impingement on adjacent undefected tubes under the high temperature and pressure conditions postulated for severe accident conditions. Pulled tube destructive examination results were reviewed for: (1) axial ODSCC at TSP intersections, (2) circumferential cracking at expansion-transitions, (3) pit-like IGA indications in the freespan region, (4) PWSCC, and (5) axial freespan cracking in CE and B&W designed units.
Based on the data presented herein, the existence of short, through-wall cracks that could become significant during severe accident conditions does not appear likely for all modes of
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13 steam generator tube degradation with the exception of PWSCC in roll transitions. However, the presence of the tubesheet in partial depth roll expanded tubing and the scheduled replacement of a number of steam generators with rolled tubes susceptible to these cracks limit the number of tubes that could lead to primary-to-secondary leakage affecting surrounding tubes under severe accident conditions. Furthermore, current practice is to remove defects of this type from
)
service upon detection and the detection sensitivity has increased significantly in the last few years.
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14 References 1.
"PWR Steam Generator Tube Repair Limits: Technical Support Documentation For Expansion Zone PWSCC in Roll Transitions - Revision 2," EPRI NP-6864-L, August 1993.
2.
- PWR Steam Generator Examination Guidelines: Revision 3," EPRI NP-6201, November 1992.
3.
Ernst, H. A., Rush, P. J., McCabe, D. E., " Resistance Curve Analysis of Surface Cracks,"
l Fracture Mechanics: Twenty-Foudh Symposium, ASTM STP 1207, J. A. M. Boulet, D. E.
McCabe, and J. D. Landes, Eds., American Society of Testing and Materials, Philadelphia, 1994.
4.
"Diablo Canyon-1 '95 Pulled Tubes - Destructive Examination Results," Presented at NRC/PG&E Meeting on February 23,1996.
5.
" Steam Generator Tubing Outside Diameter Stress Corrosion Cracking at Tube Support Plates Database for Alternate Repair Limits - 1996 Database Update," EPRI NP-7480-L, Addendum 1, November 1996.
1 6.
- Examination of Trojan Steam Generator Tubes - Volume 1: Examination Results," EPRI TR-101427, November 1992.
7.
Letter from P.M. Beard Jr. (Florida Power Corporation) to NRC, " Refuel 9 Inspection Plan for Once Through Steam Generators," Docket No. 50-302, April 19,1994.
8.
Submittal from PSE&G to NRC, " Reg. Guide 1.121 Assessment of Indications at Salem Unit 2,* Docket No. 50-311, August 19,1996.
9.
" Steam Generator Reference Book, Revision 1," EPRI TR-103824, Volume 1, December 1994.
- 10. Letter from Entergy Operations, Inc. to NRC, " Repair Limits for Circumferential Cracks,"
Docket No. 50-368, August 28,1995,
- 11. Letter from P.E. Katz (Baltimore Gas & Electric Company) to NRC, ' Steam Generator Tube Inspection Results," Docket No. 50-317, August 30,1996.
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Commissioner McGaff n A
l FROM penf I ask Manager l
p Generic Safety ssues Branch Division of Regulatory Research Office of Nuclear Regulatory Research
SUBJECT:
J. HOPENFELD'S DIFFERING PROFESSIONAL OPINION CONCERNING VOLTAGE-BASED REPAIR CRITERIA FOR STEAM GENERATOR TUBES: RELEASE OF DPO CONSIDERATION DOCUMENT FOR PUBLIC COMMENT The attached ~ document " Differing Professional Opinion (DPO) Regarding NRC Approach to Steam Generator Aging" addresses the issue of primary to secondary leakage of aging stcam generators during design basis and severe accidents. This issue was originally raised in 1991. It is still unresolved. The documents which are being released for public comment, Regulatory Guide DG-1074 and staff's responses to the DPO, are based on flawed premises. Until the staff l
can demonstrate that methods for measuring the safety performance of degraded steam generator exist, the present 40% plugging rule should not be relaxed.
The attached document was originally prepared as an appendix to GL-98-xx which was scheduled to be released in late 1997. The driving forces for its preparation were: (1) to inform the public that GL-98-xx and GL-95-05 silow plants to exceed Commission safety guidelines by wide margins and (2), provide the public with a perspective on NRC's readiness to institute risk-informed, performance-based regulations for steam generators.
Like its predecessor SG Tube Integrity Rulemaking, GL-98-xx has now been withdrawn; GL,
l 05 is still in effect despite the fact that major safety issues remain unresolved. The information document, DG-1074 and the responses to the DPO are being issued instead. The Advisory Committee on Reactor Safety (ACRS) would not endorse the responses to the DPO without the staff providing furtherjustifications.
i The attached document provides an insight as to how the staff has addressed steam generator related issues during the past G years. The staff's approach was not based on science; key assumptions were neither stated norjustified, sensitivity studies were limited to a narrow range, justification for selection of models was not provided even though the models contradict known physical phenomena, opposing technical views (staff, ACRS )were ignored. A systematic adaptation of models to attain a desired outcome was used.
l ATTACHMENT 3
2 The move from prescriptive regulation towards risk-informed, performance-based regulation has the potential of significantly improving the cost effectiveness of nuclear power. However, if not accompanied by adequate controls to insure that proper data is used in risk assessments, this move may compromise public safety.
A true test of the agency's readiness to institute performance based regulation is the existence of a methodology for measuring safety performance of major components. In case of aging steam generators, there is very little data to allow suen measurements. The attached document indicates that data is needed to baseline the level of safety of degraded steam generator tubes.
The recent reduction in tube ruptures during normal reactor operations is unrelated to accident I
leakage.
The operation of major reactor systems with degraded components raises very difficult issues because of lack of data. Steam line breaks occur very infrequently and therefore it is virtually impossible to demonstrate the benefits of a risk informed approach over a relatively short period of time. Innovative solutions to this problem are badly needed. The staff cannot be faulted for failing to produce specific guidance to the industry on how to deal with aging steam generators after 6 years of extensive efforts. What is disturbing, however, is the complete lack of planning f6r collecting data in this regard.
Attachment:
As stated.
cc: EDO J. Mitchell E
j 1
Regulatory Guide DG-1074 Package Attachment i
i i
DIFFERING PROFESSIONAL OPINION REGARDING NRC APPROACH
^
TO STEAM GENERATOR AGING.
i j
U. S. Nuclear Regulatory Commission j
J. Hopenfeld September 25,1998 i
1 1
J NOTICE: This document was originally prepared in response to staff considerations of the DPO that were attached to draft GL-98-xx. This week the staff decided to delay the decision whether the GL should be issued.
Instead, Draft DG-1074 and the DPO consideration document are being issued to support a technical interchange with the industry. The content of the enclosed document is not affected by the revised staff position.
J s
{
2 l
l DIFFERING PROFESSIONAL OPINION REGARDING NRC APPROACH TO STEAM GENERATOR AGING.
f
SUMMARY
Even though the proposed Generic Letter, (GL) 98-XX has been in preparation for more than 5 years it is not ready yet for public comments it is too complex, it is difficult to read, and it has no scientific basis. Unlike previous drafts requiring changes to technical specifications, the proposed actions are mostly voluntary in nature. Nevertheless, it is important to realize that staff's conclusions are not supported by science.
The key role that steam generators play in the safety and economics of nuclear plants presents an opportunity to define a risk-informed approach to steam generator repairs, which could serve as a platform regarding ciner aging components. The GL missed this opportunity; it uses untested models and treats uncertainties entirely inadequately. This memo discusses the technical weakness of GL-98 XX.
By suggesting that licensees may want to change their technical specifications (TS) or submit proposals for alternate repair criteria (ARC) the GL attempts to address several unresolved safety issues that have been documented in a series of Differing Professional Opinion (DPO) documents starting in 1991. To maintain Accident Leakage integrity, licensees will have to address the DPO-related issues without having the slightest idea what would be acceptable to the staff. The Advisory Committee on Reactor Safety (ACRS) strongly urged the staff to resolve the DPO before implementing new steam
3 i
i generator guidelines. The staff's latest attempt in resolving the DPO, which is being Issued for public comment, is unacceptable to the DPO originator. The ACRS also refused to endorse the staff reply to the DPO.
j The staff rationale for the need to change the TS is that stress corrosion cracking (SCC)
L and not wastage, is the dominant mode of tube failures. Because it is universally accepted that the initiation and propagation of SCC is difficult to predict, this very argument is a reason why it will also be difficult to implement the proposed TS changes without an accepted methodology of predicting crack size at the end of cycle. The GL l
. allows pla~nts to replace the present 40 percent plugging criteria with ARC provided the L
licensees submit risk assessments with their application. The staff, however, already made such assessments, and even after using non conservative assumptions, found that certain plants will not be able to meet Commission safety goals. This conclusion is in agreement with the DPO estimates that the large early, release frequency (LERF) may exceed 10E-4 (i.e an order of magnitude larger than Commission guidelines).
l i
. Aging steam generators in nuclear power plants are a source of radioactive release to the environment. A small leak from any one of thousands of corroded tubes can propagate, o
from tube to tube, and open a gate for radionuclide escape. Leakage propagation is of concem because it was not considered when the plants were designed.
l l
In response to unexpectedly fast degradation of steam generator tubes, the industry, in I'
the early 90s, proposed a new approach to repairing tubes. The U.S. Nuclear Regulatory Commission (NRC), a' apted the industry approach and issued GL-95, which relaxes d
l
4 plugging criteria. Opposing technical views including a formal DPO were ignored. GL-95 was originally intended as an interim measure; now, GL-98 gives it permanent status even though the DPO and the related hinh mlority Generic Safety issue, (GSI)-163,
" Multiple Steam Generator Leakage", remain unresolved.
- 1. BACKGROUND The Differing Professional View and Differing Professional Opinion (DPV/ DPO) was initiated in December 1991 (Ref.1) in a response to staff's approach in dealing with the degradations of the Trojan Steam Generators. Trojan was shut down permanently following steam generator leaks in late 1992. A formal DPO was filed in July 1995 (Ref.
- 2) when the staff was about to relax plugging criteria, GL-95, without properly addressing the issue of accident induced leakage. The Executive Director for Operation (EDO) responded, (Ref. 3) that the DPO would be resolved as part of the steam generator rulemaking activities. After many delays, the staff proposed a rule methodology ( Ref.
4,5).This methodology was discarded when the ACRS refused to provide its endorsement (Ref.6). The documents that were issued at the termination of the rulemaking activities (Refs.4,5) did not properly address the DPO issues. At the ACRS request ( Ref. 6) the staff issued, in October 1997, a more detailed discussion of the DPO which is attached to GL-98-XX. This third attempt to resolve the DPO issue also failed.
An important issued raised early by the DPO ( Ref. 7) was the potential increase in severe accident risk from the relaxation of the 40 percent plugging criteria. The staff ignored the DPO and in 1995 relaxed plugging criteria (GL-95) without informing the public during the comment period that there is a potential for risk increase during station blackout i
1 1
5 accidents. It was only recently (Ref.8), that the staff informed the Commission that severe accidents risk may significantly be increased if alternate repair criteria are used.
The relaxation of the 40 percent plugging criteria for certain types of tube degradations, under GL-95, was intended as an interim measure to be incorporated under the new l
steam generator rule. Since the introduction of the interim measures: (a) field experience revealed that the voltage methodology is non-conservative; (b) staff found that altemate plugging rules may increase severe accident risk; (c ) the staff was not able to l
resolve the DPO issues; (d) the staff dM not complete the resolution of GSI -163,
" Multiple Steam Generator Tube Leakage". Consequently, several plants are now operating at safety levels below Commission guidelines.
- 2. ANALYSIS 2.1 The Problem The nuclear industry has a large investment in steam generators whose ages vary from several months to more than 25 years. The aging units increasingly develop a variety of cracks that mostly show up as small leaks; these leaks do not pose major safety problems because the affected plant can be shut-down in a timely manner. The real concern arises when plants are subjected to accidents such as main steam line break (MSLB). Can the 1
leaks become larger during such accidents and propagate from tube to tube? It is generally agreed that leaks will enlarge during accidents, but there is no agreement how large they can become. The ultimate size of the leak is very important because it determines whether design basis accidents can be brought under control and whether l
l l
_ _ _ - ' - - - - ~ - ' -
6 dose releases can meet 10 CFR PART 100 requirements.
Staff's response to the DPO claims that leaks during design basis accidents will not enlarge sufficiently to lead to a core melt. These differences between the staff and the DPO reside in the calculations of radioactivity leakage through the defective tubes.
2.2 Staff's Assumptions.
To support their claim that accident induced leakage remains small and can be controlled by the operator, the staff postulated a set of assumptions which are listed below. They neither discuss nor explain the reasons for their selection; decision makers, nevertheless, appear to accept the staffs' final conclusions.
Leakage is a unique function of voltage as measured by eddy current probes.
Historical plant data allows for predicting crack growth rates during each cycle.
Leakage dunng MSLB accidents depends only on the pressure across the crack.
The steam generator is filled with water throughout the MSLB accident.
Support plates will prevent cracks enlargement during SBOs Westinghouse 1/7 test data allows mixing predictions during SBO accidents All the above assumplons minimize the magnitude of accident induced leakage.
2.3 Comments on Staff's Assumptions A. Why Voltage Measurements Are Not Related to Leakage The voltage produced by the eddy current probe is related to crack volume in its field of f
i 7
view. In contrast, leakage depends on the cross sectional area of those cracks that penetrate the tube surface. If many cracks are present below the surface of a given tube, the probe will detect a large voltage, but there will be no leakage unless the cracks penetrate the surface. Conversely, a very small voltage may produce a large leakage if a single crack penetrates the surface. In other words, voltage is not a ur.ique function of leakage. The initiation of cracks and their growth is such that one will not expect a correlation between voltage and flow; the understanding of this point is important in the analysis and interpretation of laboratory data. If a sufficiently large number of samples is tested in a laboratory, a certain number of samples may exhibit correlation between voltage and leakage. However, because of the non-unique relation between voltage and leakage, the use of the data beyond the laboratory environment introduces uncertainties.
The space between the tube and tube support structure forms a crevice, a flow-starved region, for the accumulation of chemicals that are left behind when the water in the crevice evaporates. Wetting and un-wetting inside the crevice lead to highly concentrated water solutions. Variations in crevice size and tube-to-tubo heat transfer cause large variations in crevice-to-crevice chemistry. Since stress corrosion cracking is controlled by the specific chemistry / surface stress of the tube and &ce it is not possible to measure this parameter, laboratory tests inherently contain large uncertainties that cannot be defined by statistical means. The laboratory-generated database includes some samples of failed tubes that were remove from service. The chemical environment and degree of deformation that these samples have undergone on removal are unknown. When real world environments can not be simulated in the laboratory, it is a common engineering practice to exercise conservatism.
B. Why Historical Statistical Crack Behavior Cannot be Used to Predict Future
8 Crack Growth.
It is commonly accepted (Ref. 9) that stress corrosion cracking is a complex process, defying predictions. Laboratory tests can be used only to screen different materials because crack formation and growth are controlled by numerous electrochemical, metallurgical, and stress variables. At a given stress level, crack growth depends on the conductivity and therefore on the concentration of the various species within the crack.
Since local flow and chemical transients, vary in service in an unpredictable manner, it cannot be expected that crack growth and topography will remain the same for all cycles.
Operating experience (Ref.10 ) clearly demonstrates that relying on the above procedure for predicting crack growth rates is nonconservative. For example, Farley's data show that crack growth rates for cycle 14 were higher than those for the two previous cycles--
13.7 volts were measured, significantly above the predicted peak of 7.6 volts. During MSLB accidents, the presence of even one through-the-wall crack can cascade the accident, leading to a core melt.
Stress corrosion can be characterized as a two-step process--initiation and growth. Once a crack has been initiated, its mode and rate of propagation are governed by local stress and chemistry. Even when cracks propagate slowly or are in arrest, other cracks are being initiated and then interact with previous cracks to form a complex network of cracks.
Cycle-to-cycle voltage measurement reveals nothing about crack arrest / growth cycles.
Because of considerable industrial experience in stress corrosion the common engineering practice ( Ref.9) is not to operate with components susceptible to stress corrosion cracking. By allowing operations through the wall cracks the NRC is setting a new precedent in material sciences.
I 9
C. Why Leakage Guidelines are Not Conservative: Leakage During MSLB Accidents Does Not Depend Only on Pressure.
l The staff approach to setting limits on accident induced leakage is based on selecting a failure scenario and then showing that the resultant leakage is limited by Emergency Core Cooling (ECC) pump capability (Ref.11). The leakage is assumed to coincide with crack enlargement from pressure loads during the MSLB accident and its magnitude depends only on the number of pre-existing defects, their size, and the maximum pressure during the accident.
The assumption that the flow area is enlarged during the accident by pressure alone leads to low accidental leakage ( < 100 gpm). Industrial experience, however, indicates that there are other sources for enlarging cracks beside pressure. Damage from jet erosion and sudden unplugging of cracks during transients are two mechanisms for crack enlargement and leakage increase.
Jet Erosion. During MSLB and SBO accidents leakage can be increased by jet erosion.
The jets emerging from pre-existing through-the-wall cracks contain small water droplets and micron size particles which impact the adjacent tubes at velocities exceeding 2500 ft/sec. Abrasive steam jets are kr own to initiate and propagate large leaks in Kraft boilers, leading sometimes to large steam explosions. Damage to turbine blades is another example where wet steam causes erosion damage. Abrasive water-jet machining and abrasive water-jet pipe cleaning technologies also indicate the potential for damage propagation, during accidents from jet erosion. Using jet-erosion data, the staff agreed (
Ref.4) that a steam generator tube can fail in less than 1 minute from water jet erosion.
~
10 Effect of Deposits. Cracks are normally filled with salt deposits that may plug and therby limit or prevent leakage under steady operating conditions. Pressure or thermal transients, however, may dislodge these deposits, causing an abrupt change in leakage.
The Pacific Northwest Laboratory (PNL) studies ( Ref.12), show that sudden leakage changes, through steam generator tube cracks occurs in unpredictable and random manners. The regulatory guide recommends that hydrostatic pressure tests at room temperature be conducted to demonstrate accident-induced leak rate performance. It is a common industrial experience that boiler tubes do not leak under hydrostatic tests, but do leak wheri the vessel is in operation.
D. Why Steam Generator Will be Dry Following MSLB Accidents, Thereby Exposing Tubes to a Damaging Environment During the preparation of GL-95 the staff refused to analyze the consequences of jet erosion on risk. After the release of GL-95, the staff analyzed (Ref. 6 ) the consequences of jet erosion and concluded that jet eresca WN rapidly damage adjacent tube during severe accidents, when the secondasy side is dry. Unlike during severe accidents, the staff claims that during design basis acciden s erosion will not take place because the water in the vessel will attenuate the jet's energy before its impact on adjacent tubes.
This assumption appears to contradict the basic laws of physics, because as soon as the pressurized (1000 lbs/sq. in) water in the steam generator is exposed to the atmosphere, the vessel empties; it will take about 30 minutes to refill. Using staff's own data on erosion rates (Ref.6) this time is more than sufficient to propagate leakage throughout the steam generator.
11 F. Why Support Plates Will Not Prevent Erosion Damage to Adjacent Tubes For free span cracks, the staff concluded that adjacent tubes could be rapidly damaged.
They claim that for cracks in the support plate region, the adjacent tubes will not be damaged because the jet will be deflected by the support plate in a direction parallel to adjacent tubes.
This assumption is based on the belief that the jet will be initiated away from the edges of the plate and will follow the gap in a prescribed manner. This ideal model doe not take into account the fact that the jet can originate at the edges, rapidly enlarging the crack, and impinge on the adjacent tubes. The support plate / tube gap will contain substantial amount of deposits, preventing the jet from following a well-defined parallel path to the tubes.
F. Why Westinghouse-1/7 Tests Should Not be Used to Determine Tube Temperatures During Station Blackout Accidents i
To demonstrate that cracked tubes have no impact on the consequences of station blackout accidents, the staff relied on the W - 1/7th scale mixing tests (Ref. 4). These tests are completely irrelevant to the assessment of how defective tube will behave t
because they were conducted without leakage and without fission product deposits. As discussed in the DPO (Ref.13) and confirmed by the staff even relatively small leakages (
400gpm ) are of the same order as the free convection loop flow. Recent analysis by JAERI shows that the heat release from fission products causes a sharp rise in steam generator tube temperature, but not in the surge line temperature. These results add weight to the analysis of Ref. 7 which predicts that steam generator tubes will fail before the surge line does. When the tubes fall first, the LERF exceeds Commission i
12 guideline (10 E-5 reactors / year). The staff deflected the significance of the JAERI results by stating, (Ref.14 ), that these results are not applicable to degraded tubes because the analysis was based on the unmixed vapor temperature. This illustrates how the staff's practice of neither stating nor discussing important assumptions can mislead decision makers. As already stated above, the staff without providing any justification for neglected leakage, used complete mixing in NUREG-1570. They continue to use this perfect mixing assumption by rejecting the JAERI results.
l With degraded tubes the leakage can not be ignored, the unmixed vapor temperature is I
i the proper temperature to use in the analysis of fission product deposits and therefore the JAERI results are indeed applicable. In addition, ACRS consultants also raised concems about the applicability of the W-1/7 tests and limited range of sensitivity studies. These comments were completely disregarded.
- 3. DISCUSSION Failures of steam generator tubes as a result of corrosion can have catastrophic consequences when they occur during steam line break accidents. The underlying reason for severe corrosion in steam generators was the selection of alloy 600 during the design phase of the plant. Replacement steam generators use the less susceptible alloy
- Stress, 690; however, not all the plants have replaced their steam generators yet.
coolant chemistry, material microstructure, and temperature are the major factors that affect corrosion. Since these factors vary from plant to plant, it is critical to perform a risk-informed Fitness-for-Next Cycle Assessment during each inspection interval. Given the observed crack sizes and their locations, conservative K values can be used to estimate the total potentialleakage area under MSLB at the end of the next cycle. In selecting K
m
.. 3 13 values, one should reference his/her source and discuss how crack linkage is accounted for in the analysis. Once the initial leakage has been calculated, an estimate should then
_ be made to determine leakage propagation during MSLB, taking into account erosion and crack enlargement from unplugging. The final conclusion from this assessment should I
indicate how many tubes should be plugged and whether a mid-cycle inspection is required. At this point, cost becomes an issue and should be factored into the decision and discussed in the assessment. The analysis does not have to be lengthy or very j
elaborate, but it should reflect that experienced and qualified engineers with familiarity with the history of the plant have prepared the assessment. Assumptions should be l
consistent with engineering observations e.g. if the calculated jet velocities for a given crack geometry are low, it would be sufficient to state that erosion has not been observed on material 600 or similar materials at these velocities and therefore the potential risk for tube-to-tube propagation is very low.
I L
As part of their licensing basis, plants are required to meet certain accident induced leakage criteria. Changes to these criteria require that the staff review the consequences I
of such changes on accident leakage. Stress corrosion cracking introduces a phenomena where it is very difficult to predict leakage because there is hardly any data on flow through these complex cracks. The use of voltage-based repair limits is a convenient tool
['
to bypass these difficulties even though it has no scientific basis. Nevertheless, if this t
[
approach is used, uncertainties must be assessed and not ignored. To gain acceptance with the public, performance-based regulation must be transparent. At the least, the
. public should be informed that because of lack of other means, non-scientific methods are i
being employed.
o m-.-
m
-3 n-_-
14 The NRC has indicated that it intends to move toward risk-informed approach to make regulation more efficient. Before this can be accomplished the agency must first institute procedures that will protect the public from regulations which are based on unreliable technical information. The supporting documents ( Refs.4,11) clearly demonstrate that present internal controls are not adequate to prevent the use of irrelevant data to For example, one is led to believe (Ref.15) that large advance a given outcome.
leakages will not occur because such leakages have never occurred during past depressurization events in operating reactors. One is not told, however, that these depressurization events are not relevant to MSLB accidents, because the plants were not operating with through-the-wall cracks and the steam generators were filled with water.
GL-98-xx states that the risk for plants that operate under the ad-hoc provisions of GL-95 remains at an acceptable level. This statement contradicts the information the staff
,d to the Commission (Ref. 8) stating that some plants using alternate repair criteria p-rr, y oot meet Commission guidelines. The response to the DPO, however, states that when the interim plugging criteria were considered for steam generator tubes under NUREG-1477 and GL-95-05, they did not have the benefit of the Probability Risk Assessment (PRA) policy statement, to focus attention on severe accidents. In other words, the staff has not conducted a complete risk assessment before relaxing, and continuing to relax existing plugging rules. The lack of a formal policy does not bar the staff from performing analysis when there are clear signals that a potential problem exists.
The staff claims that the original DPO was I;mited to Design Basis Accidents (DBA) l accidents, only, and did not include severe accidents. This is incorrect. Several years i
before the preparation of GL-95-05 a DPV/ DPO datec Sept.111992 (Ref. 7) concluded i
15 that degraded tubes may have an important effect on se/ere accident risk. The staff ignored this observation and severe accident risk was not considered. Only after the release of GL-95-05, did the staff discovered that a significant increase in risk exists during severe accident. This finding still did not prevent the staff from continuing rule relaxations under GL-95-05, i
During the development of the GLs and the steam generator rule in the last 6 years, the staff continuously kept changing their actions even-though no new relevant data was being generated. After 4 years of rule-making activities and shortly after briefing the i
Commission that the new steam generator rule will set a precedent in rule-making, the SG rule was withdrawn with an explanation that this was dictated by cost benefit considerations. After spending 2 years on preparing its successor, GL-98-XX, the GL was withdrawn with the explanation that this was dictated by the NEl-97-06 initiative ( Ref.16).
Since the NEl initiative was issued in December 1997, it is difficult to understand why the l
staff did not reach an agreement with the industry earlier, instead of expending resources on GL-98-XX. NEl-96-06 is a high level document which does not contain difficult issues.
While the resolution steam generator issues is being delayed the staff, at the same time, relaxes the existing plugging rules on an ad-hock basis and with disregard of Commission safety guidelines.
- 4. CONCLUSIONS GL-98-XX and GL-95-05 demonstrate approaches which are based on adapting models to attain a desired outcome. Such approaches are not conducive to gain endorsernents of risk based regulations. Unbiased risk assessments should include the following elements:
-+
w
_~~~'r'
--;-_,c,___-_-_
16 1.
Good scienco 2.
Timely response to steam generator problems Acceptance criteria for accidentalleakage assessment 3.
Use of relevant data to support conclusions 4.
5.
Proper use of referenced material Sensitivity studies with full range of plausible parameters.
6.
7.
Proper use of different views and opinions
- 5. RECOMMENDATIONS Do not issue GL-98-XX for public comments 1.
2.
Phase out GL-95-05 Issue specific acceptance criteria to demonstrate that accident induced 3.
leakage will meet Commission safety guidelines and Part 100 requirements Reach agreements with the industry on methods for measuring safety 4.
performance of degraded steam generator tubes.
- 5. REFERENCES Memo, J. Hopenfeld U.S. Nuclear Regulatory Commission, Memorandum to 1.
Beckjord,U.S. Nuclear Regulatory Commission, " Differing Professional Opinion",
December 23,1991 Memo, J. Hopenfeld,U.S. Nuclear Regulatory Commission, Memorandum to J.
2.
l
m _ _ _. _. _. _... __
3..
17 l
Taylor,U.S. Nuclear Regulatory Commission, " Differing Professional Opinion l
Regarding Voltage Based Interim Repair Criteria For Steam Generator Tubes",
I l
July 1994.
3.
Memo, J. Mihoan U S. Nuclear Regulatory Commission Memorandum to J.
l Hopenfeld,U.S. Nuclear Regulatory Commission, " Resolution of DPO regarding Voltage-Based Repair Criteria, for Steam Generator Tubes" July 13,1994 4.
U.S. Nuclear Regulatory Commission, NUREG-1570 " Risk Assessment of j
Severe Accident induced Steam Generator tube Rupture" Draft, Feb 1997 5.
U.S. Nuclear Regulatory Commission, " Regulatory Analysis SG Tube Integrity Rulemaking", Draft Dec.1996
- 6.
Memo, T.S. Kress U.S. Nuclear Regulatory Commission Memorandum to J.M.
l Taylor, U.S. Nuclear Regulatory Commission " Proposed Rule on Steam Generator Integrity" May 13,1997 7.
J. Hopenfeld U.S. Nuclear Regulatory Commission Memorandum to Beckjord,
U.S. Nuclear Regulatory Commission " Addendum To March 27,1992, Memorandum Regarding Degraded Steam Generator Tubes, Sept 11 1992."
l 8.
Memo L.J. Callan U.S. Nuclear Regulatory Commission, Memorandum, to Commision, Steam Generator Rulemaking, May 23,1997 I
9.
Donald O. Sprowls," Environmental Cracking-Does it Affect You?" ASTM Standardization News. Aoril1996
- 10.
Letter from, Southern Company, Joseph M. Farley, " Nuclear Plant-Unit 1, Attemate Repair Criteria (ARC) for ODSCC at Tube Support Plate Intersection,"
May 20,1997.
4 i
11.
U.S. Nuclear Regulatory Commission, NUREG-1477, " Voltage-Based Interim 4
Plugging Criteria for Steam Generator Tubes," June 1993 4
I
18 U.S. Nuclear Regulatory Commission, " Steam Generator Tube Integrity Program,"
12.
NUREG/CR-2336, Aug.1988 Advisory Committee on Reactor Safety, ACRP Materials and Metallurgy 13.
Subcommittee & Severe Accidents Subcommittee, March 5,1997 G.C. Laines, U.S. Nuclear Regulatory Commission, to the Advisory Committee on 14.
Reactor Safety, "JAERI Analysis of Fission Product Heating of Steam Generator
(
I f
Tubes" Aug. 7,1998 Advisory Committee on Reactor Safety, ACRS, 445* Meeting Oct.2-3,1997 15.
L. Joseph Callan, U.S. Nuclear Regulatory Commission, Memorandum to Samu 15.
J. Collins U.S. Nuclear Regulatory Commission " Proposed Generic Letter 98-XX "
Steam Generator Tube Inte0rity" Sept.11,1998