[Federal Register Volume 70, Number 40 (Wednesday, March 2, 2005)]
[Notices]
[Pages 10297-10312]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 05-3866]



[[Page 10297]]

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Part III





Nuclear Regulatory Commission





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Notice of Opportunity To Comment on Model Safety Evaluation on 
Technical Specification Improvement To Modify Requirements Regarding 
the Addition of LCO 3.4.[17] on Steam Generator Tube Integrity Using 
the Consolidated Line Item Improvement Process; Notice

Federal Register / Vol. 70, No. 40 / Wednesday, March 2, 2005 / 
Notices

[[Page 10298]]


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NUCLEAR REGULATORY COMMISSION


Notice of Opportunity To Comment on Model Safety Evaluation on 
Technical Specification Improvement To Modify Requirements Regarding 
the Addition of LCO 3.4.[17] on Steam Generator Tube Integrity Using 
the Consolidated Line Item Improvement Process

AGENCY: Nuclear Regulatory Commission.

ACTION: Request for comment.

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SUMMARY: Notice is hereby given that the staff of the Nuclear 
Regulatory Commission (NRC) has prepared a model safety evaluation (SE) 
relating to the addition of a steam generator (SG) tube integrity 
specification to technical specifications (TS). The NRC staff has also 
prepared a model no-significant-hazards-consideration (NSHC) 
determination relating to this matter. The purpose of these models is 
to permit the NRC to efficiently process amendments that propose to add 
an LCO 3.4.[17] that requires that SG tube integrity be maintained and 
requires that all SG tubes that satisfy the repair criteria be plugged 
or repaired in accordance with the Steam Generator Program. Licensees 
of nuclear power reactors to which the models apply could then request 
amendments, confirming the applicability of the SE and NSHC 
determination to their reactors. The NRC staff is requesting comment on 
the model SE and model NSHC determination prior to announcing their 
availability for referencing in license amendment applications.

DATES: The comment period expires April 1, 2005. Comments received 
after this date will be considered if it is practical to do so, but the 
Commission is able to ensure consideration only for comments received 
on or before this date.

ADDRESSES: Comments may be submitted either electronically or via U.S. 
mail. Submit written comments to Chief, Rules and Directives Branch, 
Division of Administrative Services, Office of Administration, Mail 
Stop: T-6 D59, U.S. Nuclear Regulatory Commission, Washington, DC 
20555-0001. Hand deliver comments to: 11545 Rockville Pike, Rockville, 
Maryland, between 7:45 a.m. and 4:15 p.m. on Federal workdays. Copies 
of comments received may be examined at the NRC's Public Document Room, 
11555 Rockville Pike (Room O-1F21), Rockville, Maryland. Comments may 
be submitted by electronic mail to [email protected].

FOR FURTHER INFORMATION CONTACT: Tom Boyce, Mail Stop: O-12H4, Division 
of Inspection Program Management, Office of Nuclear Reactor Regulation, 
U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, 
telephone 301-415-0184.

SUPPLEMENTARY INFORMATION:

Background

    Regulatory Issue Summary 2000-06, ``Consolidated Line Item 
Improvement Process for Adopting Standard Technical Specification 
Changes for Power Reactors,'' was issued on March 20, 2000. The 
consolidated line item improvement process (CLIIP) is intended to 
improve the efficiency of NRC licensing processes by processing 
proposed changes to the standard technical specifications (STS) in a 
manner that supports subsequent license amendment applications. The 
CLIIP includes an opportunity for the public to comment on a proposed 
change to the STS after a preliminary assessment by the NRC staff and a 
finding that the change will likely be offered for adoption by 
licensees. This notice solicits comment on a proposed change that 
requires that SG tube integrity be maintained and requires that all SG 
tubes that satisfy the repair criteria be plugged or repaired in 
accordance with the Steam Generator Program. The CLIIP directs the NRC 
staff to evaluate any comments received for a proposed change to the 
STS and to either reconsider the change or announce the availability of 
the change for adoption by licensees. Licensees opting to apply for 
this TS change are responsible for reviewing the staff's evaluation, 
referencing the applicable technical justifications, and providing any 
necessary plant-specific information. Each amendment application made 
in response to the notice of availability will be processed and noticed 
in accordance with applicable rules and NRC procedures.
    This notice involves the addition of LCO 3.4.[17] to the TS which 
requires that SG tube integrity be maintained and requires that all SG 
tubes that satisfy the repair criteria be plugged or repaired in 
accordance with the Steam Generator Program. This change was proposed 
for incorporation into the standard technical specifications by the 
owners groups participants in the Technical Specification Task Force 
(TSTF) and is designated TSTF-449. TSTF-449 can be viewed on the NRC's 
Web page at http://www.nrc.gov/reactors/operating/licensing/techspecs.html.

Applicability

    This proposal to modify technical specification requirements by the 
addition of LCO 3.4.[17], as proposed in TSTF-449, is applicable to all 
licensees who have adopted or will adopt, in conjunction with the 
proposed change, technical specification requirements for a Bases 
control program consistent with the TS Bases Control Program described 
in Section 5.5 of the applicable vendor's STS.
    To efficiently process the incoming license amendment applications, 
the staff requests that each licensee applying for the changes proposed 
in TSTF-449 include Bases for the proposed TS consistent with the Bases 
proposed in TSTF-449. In addition, licensees that have not adopted 
requirements for a Bases control program by converting to the improved 
STS or by other means are requested to include the requirements for a 
Bases control program consistent with the STS in their application for 
the proposed change. The need for a Bases control program stems from 
the need for adequate regulatory control of some key elements of the 
proposal that are contained in the proposed Bases for LCO 3.4.[17]. The 
staff is requesting that the Bases be included with the proposed 
license amendments in this case because the changes to the TS and the 
changes to the associated Bases form an integral change to a plant's 
licensing basis. To ensure that the overall change, including the 
Bases, includes appropriate regulatory controls, the staff plans to 
condition the issuance of each license amendment on the licensee's 
incorporation of the changes into the Bases document and on requiring 
the licensee to control the changes in accordance with the Bases 
Control Program. The CLIIP does not prevent licensees from requesting 
an alternative approach or proposing the changes without the requested 
Bases and Bases control program. However, deviations from the approach 
recommended in this notice may require additional review by the NRC 
staff and may increase the time and resources needed for the review.

Public Notices

    This notice requests comments from interested members of the public 
within 30 days of the date of publication in the Federal Register. 
After evaluating the comments received as a result of this notice, the 
staff will either reconsider the proposed change or announce the 
availability of the change in a subsequent notice (perhaps with some 
changes to the safety evaluation or the proposed no significant hazards

[[Page 10299]]

consideration determination as a result of public comments). If the 
staff announces the availability of the change, licensees wishing to 
adopt the change must submit an application in accordance with 
applicable rules and other regulatory requirements. For each 
application the staff will publish a notice of consideration of 
issuance of amendment to facility operating licenses, a proposed no 
significant hazards consideration determination, and a notice of 
opportunity for a hearing. The staff will also publish a notice of 
issuance of an amendment to an operating license to announce the 
addition of the steam generator tube integrity requirements for each 
plant that receives the requested change.

Proposed Safety Evaluation

U.S. Nuclear Regulatory Commission; Office of Nuclear Reactor 
Regulation; Consolidated Line Item Improvement; Technical Specification 
Task Force (TSTF) Change TSTF-449 Revision 3; Steam Generator Tube 
Integrity

1.0 Introduction

    By application dated [Date], [Licensee] (the licensee) requested 
changes to the Technical Specifications (TS) for [facility] concerning 
the maintaining of steam generator (SG) tube integrity. This amendment 
request is the culmination of NRC and industry efforts since the mid-
1990s to develop a programmatic, largely performance-based regulatory 
framework for ensuring SG tube integrity. In letters dated March 14 and 
September 9, 2003, October 7, 2004, and January 14, 2005, the Technical 
Specification Task Force (TSTF) proposed requirements for steam 
generator tube integrity and changes to the steam generator program in 
the standard technical specifications (STS) (NUREGs 1430--1432) on 
behalf of the industry. This proposed change is designated TSTF-449.
    The scope of the TS amendment request includes:

a. Revised Table of Contents
b. Revised TS definition of LEAKAGE
c. Revised TS 3.4.13 and TS Bases B 3.4.13, ``RCS [Reactor Coolant 
System] Operational LEAKAGE''
d. New TS 3.4.[17] and new TS Bases B 3.4.[17], ``Steam Generator (SG) 
Tube Integrity''
e. Revised TS 5.5.9, ``Steam Generator (SG) Program''
f. Revised TS 5.6.9, ``Steam Generator Tube Inspection Report''
g. Revised TS Bases B 3.4.4, ``RCS Loops--Modes 1 and 2''
h. Revised TS Bases B 3.4.5, ``RCS Loops--Mode 3''
i. Revised TS Bases B 3.4.6, ``RCS Loops--Mode 4''
j. Revised TS Bases B 3.4.7, ``RCS Loops--Mode 5''

    The proposed new TS 3.4.[17], ``Steam Generator (SG) Tube 
Integrity,'' in conjunction with the proposed revisions to 
administrative TS 5.5.9, ``Steam Generator (SG) Program,'' would 
establish a new programmatic, largely performance-based framework for 
ensuring SG tube integrity. Proposed TS Bases B 3.4.[17] documents the 
licensee's bases for this framework. Proposed TS 3.4.[17] would 
establish new limiting conditions for operation (LCOs) related to SG 
tube integrity; namely, (1) SG tube integrity shall be maintained, and 
(2) all SG tubes satisfying the tube repair criteria (i.e., tubes with 
measured flaw sizes exceeding the tube repair criteria) shall be 
plugged [or repaired] in accordance with the SG Program. TS 3.4.[17] 
would include surveillance requirements (SRs) to verify that the above 
LCOs are met in accordance with the SG Program.
    Proposed administrative TS 5.5.9, ``Steam Generator (SG) Program,'' 
would replace the current administrative TS 5.5.9, ``Steam Generator 
Tube Surveillance Program.'' This revised TS would require establishing 
and implementing a program that ensures that SG tube integrity is 
maintained. Tube integrity is defined in the proposed TS in terms of 
specified performance criteria for structural and leakage integrity. TS 
5.5.9 would also provide for monitoring the condition of the tubes 
relative to these performance criteria during each SG tube inspection 
and for ensuring that tube integrity is maintained between scheduled 
inspections of the SG tubes. TS 5.5.9 would retain the currently 
specified tube repair limit(s).
    The proposed changes to TS 5.6.9, ``Steam Generator (SG) Tube 
Inspection Report,'' revise the existing requirements for, and the 
contents of, the SG tube inspection report consistent with the proposed 
revisions to TS 5.5.9. The current requirement for a 12-month report 
would be changed to a 180-day report.
    The proposed amendment revises the TS definition of LEAKAGE. 
Currently, the TS definition of LEAKAGE refers to ``SG LEAKAGE'' in the 
definition of Identified LEAKAGE and Pressure Boundary Leakage. ``SG 
LEAKAGE'' is not used in the TS or BASES. Therefore, the more 
appropriate term ``primary to secondary LEAKAGE'' is used in the TS 
definition of LEAKAGE.

[Note to reviewers: With respect to the following paragraph, some 
plants may have a less restrictive limit than the 150 gpd per SG. If 
so, the amendment should propose changing this to 150 gpd, and this 
will need to be acknowledged in the SE.]

    The proposed amendment includes proposed revisions to TS 3.4.13 and 
its bases, ``RCS Operational LEAKAGE.'' The proposed changes would 
delete the current LCO limit of [576] gallons per day (gpd) for total 
primary-to-secondary leakage through all SGs, [but would retain the 
current LCO limit of 150 gpd for primary-to-secondary leakage from any 
one SG]. Retaining this latter requirement effectively ensures that 
total primary-to-secondary leakage through all the SGs is not allowed 
to exceed [600] gpd. (Note, [Plant Name, Units 1 and 2], are [four]-
loop plants.) The proposed changes would also revise the TS 3.4.13 
conditions and SRs to better clarify the requirements related to 
primary-to-secondary leakage.
    Finally, the TS Bases for TS [3.4.4,] 3.4.5, 3.4.6, and 3.4.7 would 
be revised to eliminate the reference to the Steam Generator Tube 
Surveillance Program as the method for ensuring SG OPERABILITY.

2.0 Regulatory Evaluation

2.1 Current Licensing Basis/SG Tube Integrity

    The SG tubes in pressurized water reactors (PWRs) have a number of 
important safety functions. These tubes are an integral part of the 
reactor coolant pressure boundary (RCPB) and, as such, are relied upon 
to maintain primary system pressure and inventory. As part of the RCPB, 
the SG tubes are unique in that they are also relied upon as a heat 
transfer surface between the primary and secondary systems such that 
residual heat can be removed from the primary system and are relied 
upon to isolate the radioactive fission products in the primary coolant 
from the secondary system. In addition, the SG tubes are relied upon to 
maintain their integrity to be consistent with the containment 
objectives of preventing uncontrolled fission product release under 
conditions resulting from core damage severe accidents.
    Title 10 of the Code of Federal Regulations (10 CFR) establishes 
the fundamental regulatory requirements with respect to the integrity 
of the steam generator tubing. Specifically, the General Design 
Criteria (GDC) in Appendix A to 10 CFR Part 50 states that the RCPB 
shall have ``an extremely low probability of abnormal leakage * * * and 
gross rupture'' (GDC 14), ``shall be designed with sufficient margin'' 
(GDC 15 and 31), shall be of ``the highest quality standards possible''

[[Page 10300]]

(GDC 30), and shall be designed to permit ``periodic inspection and 
testing * * * to assess * * * structural and leak tight integrity'' 
(GDC 32). To this end, 10 CFR 50.55a specifies that components which 
are part of the RCPB must meet the requirements for Class 1 components 
in Section III of the American Society of Mechanical Engineers (ASME) 
Boiler and Pressure Vessel Code (Code). Section 50.55a further 
requires, in part, that throughout the service life of a PWR facility, 
ASME Code Class 1 components meet the requirements, except design and 
access provisions and pre-service examination requirements, in Section 
XI, ``Rules for Inservice Inspection [ISI] of Nuclear Power Plant 
Components,'' of the ASME Code, to the extent practical. This 
requirement includes the inspection and repair criteria of Section XI 
of the ASME Code.
    In the 1970s, Section XI requirements pertaining to ISI of SG 
tubing were augmented by additional SG tube SRs in the TSs. Paragraph 
(b)(2)(iii) of 10 CFR, 50.55a, states that where TS SRs for SGs differ 
from those in Article IWB-2000 of Section XI of the ASME Code, the ISI 
program shall be governed by the TSs.
    The existing plant TSs include LCOs and accompanying SRs and action 
statements pertaining to the integrity of the SG tubing. SG operability 
in accordance with the SG tube surveillance program is necessary to 
satisfy the LCOs governing RCS loop operability, as stated in the 
accompanying TS Bases. The LCO governing RCS Operational LEAKAGE 
includes limits on allowable primary-to-secondary LEAKAGE through the 
SG tubing. Accompanying SRs require verification that RCS operational 
LEAKAGE is within limits every 72 hours by an RCS water inventory 
balance and that SG tube integrity is in accordance with the SG tube 
surveillance program. The SG tube surveillance program requirements are 
contained in the administrative TSs. These administrative TSs state 
that the SGs are to be determined OPERABLE after the actions required 
by the surveillance program are completed.
    Under the plant TS SG surveillance program requirements, licensees 
are required to monitor the condition of the steam generator tubing and 
to perform repairs, as necessary. Specifically, licensees are required 
by the plant TSs to perform periodic ISIs and to remove from service, 
by plugging, all tubes found to contain flaws with sizes exceeding the 
acceptance limit, termed ``plugging limit'' (old terminology) or ``tube 
repair criteria'' (new terminology). The frequency and scope of the 
inspection and the tube repair limits are specified in the plant TSs.
    The tube repair limits in the TSs were developed with the intent of 
ensuring that degraded tubes (1) maintain factors of safety against 
gross rupture consistent with the plant design basis (i.e., consistent 
with the stress limits of the ASME Code, Section III) and (2) maintain 
leakage integrity consistent with the plant licensing basis while, at 
the same time, allowing for potential flaw size measurement error and 
flaw growth between SG inspections.
    As part of the plant licensing basis, applicants for PWR licenses 
are required to analyze the consequences of postulated design basis 
accidents (DBAs) such as an SG tube rupture (SGTR) and main steam line 
break (MSLB). These analyses consider the primary-to-secondary leakage 
through the tubing which may occur during these events and must show 
that the offsite radiological consequences do not exceed the applicable 
limits of 10 CFR 100 for offsite doses, GDC-19 criteria for control 
room operator doses, or some fraction thereof as appropriate to the 
accident, or the NRC approved licensing basis (e.g., a small fraction 
of these limits).

2.2 10 CFR 50.36

    In 10 CFR 50.36, the Commission established its regulatory 
requirements related to the content of TSs. In doing so, the Commission 
emphasized those matters related to the preventing of accidents and 
mitigating their consequences. As recorded in the Statements of 
Consideration, Technical Specifications for Facility Licenses: Safety 
Analysis Reports (33 FR 18610, December 17, 1968), the Commission noted 
that applicants are expected to incorporate into their TSs those items 
that are directly related to maintaining the integrity of the physical 
barriers designed to contain radioactivity. Pursuant to 10 CFR 50.36, 
TSs are required to include items in five specific categories related 
to station operation. Specifically, those categories include: (1) 
Safety limits, limiting safety system settings, and limiting control 
settings; (2) limiting conditions for operation (LCO); (3) surveillance 
requirements (SRs); (4) design features; and (5) administrative 
controls. However, the rule does not specify the particular 
requirements to be included in a plant's TS. The licensee's application 
contains proposed LCOs, SRs and administrative controls involving steam 
generator integrity, an important element of the physical barriers 
designed to contain radioactivity.
    Additionally, 10 CFR 50.36(c)(2)(ii) sets forth four criteria to be 
used in determining whether an LCO is required to be included in the TS 
for a certain item. These criteria are as follows:
    1. Installed instrumentation that is used to detect, and indicate 
in the control room, a significant abnormal degradation of the reactor 
coolant pressure boundary.
    2. A process variable, design feature, or operating restriction 
that is an initial condition of a design-basis accident or transient 
analysis that assumes either the failure of or presents a challenge to 
the integrity of a fission product barrier.
    3. A structure, system, or component that is part of the primary 
success path and which functions or actuates to mitigate a design-basis 
accident or transient that either assumes the failure of or presents a 
challenge to the integrity of a fission product barrier.
    4. A structure, system or component which operating experience or 
probabilistic risk assessment has shown to be significant to public 
health and safety.
    The NRC staff has reviewed the proposed changes to ensure that 
these changes conform with 10 CFR 50.36 as discussed herein.

2.3 Background--Technical Specification Amendment Request

    The current TS requirements for inspection and repair of SG tubing 
date to the mid-1970s and define a prescriptive approach for ensuring 
tube integrity. This prescriptive approach involves inspection of the 
tubing at specified intervals, implementation of specified tube 
inspection sampling plans, and repair or removal from service by 
plugging all tubes found by inspection to contain flaws in excess of 
specified flaw repair criteria. However, as evidenced by operating 
experience, the prescriptive approach defined in the TSs is not 
sufficient in-and-of-itself to ensure that tube integrity is 
maintained. For example, in cases of low to moderate levels of 
degradation, the TSs require that only 3 to 21 percent of the tubes be 
inspected, irrespective of whether the inspection results indicate that 
additional tubes may need to be inspected to reasonably ensure that 
tubes with flaws that may exceed the tube repair criteria, or that may 
impair tube integrity, are detected. In addition, the TSs (and ASME 
Code, Section XI) do not explicitly address the inspection methods to 
be employed for different tube degradation mechanisms or tube 
locations, nor are the specific objectives to be fulfilled by the 
selected methods explicitly defined. Also, incremental flaw growth 
between inspections can, in

[[Page 10301]]

many instances, exceed what is allowed in the specified tube repair 
criteria. In such cases, the specified inspection frequencies may not 
ensure reinspection of a tube before its integrity is impaired. In 
short, the current TS SRs do not require licensees to actively manage 
their SG surveillance programs so as to provide reasonable assurance 
that tube integrity is maintained.
    In view of the shortcomings of the current TS requirements, 
licensees experiencing significant degradation problems have frequently 
found it necessary to implement measures beyond minimum TS requirements 
to ensure that adequate tube integrity is being maintained. Until the 
1990s, these measures tended to be ad hoc. By letter dated December 16, 
1997 (Reference 1), the Nuclear Energy Institute (NEI) provided NRC 
with a copy of NEI 97-06 (Original), ``Steam Generator Program 
Guidelines,'' and informed the NRC of the following formal industry 
position.

    Each licensee will evaluate its existing steam generator program 
and, where necessary, revise and strengthen program attributes to 
meet the intent of the guidance provided in NEI 97-06, ``Steam 
Generator Program Guidelines,'' no later than the first refueling 
outage starting after January 1, 1999.

    The stated objectives of this initiative were to have a clear 
commitment from utility executives to follow industry SG related 
guidelines developed through Electric Power Research Institute (EPRI) 
to assure a unified industry approach to emerging SG issues and to 
apply tube integrity performance criteria in conjunction with the 
performance-based philosophy of the maintenance rule, 10 CFR 50.65. 
Reference 2 is the most recent update to NEI 97-06 available to the NRC 
staff. NEI 97-06 provides general, high-level guidelines for a 
programmatic, performance-based approach to ensuring SG tube integrity. 
NEI 97-06 references a number of detailed EPRI guideline documents for 
programmatic details. Subsequently, the NRC staff had extensive 
interaction with the industry to resolve NRC staff concerns with this 
industry initiative and to identify needed changes to the plant TSs to 
ensure that tube integrity is maintained (Reference 3).
    Ultimately, in consideration of the performance-based objective of 
this initiative, the NRC staff determined it was not necessary for the 
NRC staff to formally review or endorse the NEI 97-06 guidelines or the 
EPRI guideline documents referenced by NEI 97-06. The subject 
application for changes to the TS is programmatically consistent with 
the industry's NEI 97-06 initiative. As discussed in this safety 
evaluation, these changes will ensure that an SG program that provides 
reasonable assurance that SG tube integrity will be maintained will be 
implemented.

3.0 Evaluation

3.1 TS 3.4.[17], ``Steam Generator (SG) Tube Integrity''

    The current TS establishes an operability requirement for the SG 
tubing; namely, the tubes shall be determined OPERABLE after completion 
of the actions defined in the SG tube surveillance program (TS 5.5.9). 
In addition, this surveillance program (and SG operability) is directly 
invoked by TS 3.4.13, which contains the LCO relating to RCS leakage. 
However, these specifications do not directly require that tube 
integrity be maintained. Instead, they require implementation of an SG 
tube surveillance program, which is assumed to ensure tube integrity, 
but, as discussed above, may not depending on the circumstances of 
degradation at a plant.
    To address this shortcoming, the [Name of plant] TS amendment 
package includes a proposed new specification, TS 3.4.[17], ``Steam 
Generator (SG) Tube Integrity,'' which includes a new LCO requirement 
and accompanying conditions, required actions, completion times, and 
SRs. The new LCO is applicable in MODES 1, 2, 3, and 4 and requires: 
(1) SG tube integrity shall be maintained, AND 2) all SG tubes 
satisfying the tube repair criteria shall be plugged [or repaired] in 
accordance with the Steam Generator Program (specified in the proposed 
TS 5.5.9). This LCO supplements the LCO in TS 3.4.13 to directly make 
tube integrity an operating restriction. This is consistent with 
Criterion 2 of 10 CFR 50.36(c)(2)(ii) since the assumption of tube 
integrity as an initial condition is implicit in DBA analyses (with the 
exception of analysis of a design-basis SGTR where one tube is assumed 
not to have structural integrity) and is acceptable to the NRC staff.

[Note to reviewers: Inclusion of the words ``or repaired'' is 
acceptable only in cases where the plant TS already include 
provision for tube repair methods. In general, such provisions do 
not exist for plants with replacement SGs.]

    Proposed SR 3.4.[17].1 would require that SG tube integrity be 
verified in accordance with the Steam Generator Program, which is 
described in proposed revisions to TS 5.5.9. The required frequency for 
this surveillance would also be in accordance with the SG Program, thus 
meeting the requirements of 10 CFR 50.36(c)(3). The revised TS 5.5.9 
would define tube integrity in terms of satisfying tube integrity 
performance criteria for tube structural integrity and leakage 
integrity as specified therein. SR 3.4.[17].1 would replace the 
existing surveillance requirement (SR 3.4.13.2) in the RCS Operational 
LEAKAGE specification (TS 3.4.13), which provides that tube integrity 
be verified in accordance with the SG surveillance program as provided 
in the current TS 5.5.9. The proposed SR improves upon the current SR 
in that it refers to a program that is directly focused on maintaining 
tube integrity rather than on implementing a prescriptive surveillance 
program which, as discussed above, may not be sufficient to ensure tube 
integrity is maintained. Proposed SR 3.4.[17].2 would require 
verification that each inspected SG tube that satisfies the tube repair 
criteria is plugged [or repaired] in accordance with the SG Program. 
The tube repair criteria are contained in the SG Program. The required 
frequency for SR 3.4.[17].2 is prior to entering MODE 4 following a SG 
tube inspection. The NRC staff concludes that SR 3.4.[17].1 and SR 
3.4.[17].2 are sufficient to determine whether the proposed LCO is met, 
meet the requirements of 10 CFR 50.36(c)(3), and are acceptable.
    The licensee has proposed conditions, required actions, and 
completion times for the new LCO 3.4.[17] as shown in Table 1. The 
proposed TS 3.4.[17] allows separate condition entry for each SG tube.

                      Table 1.--TS 3.4.[17] Actions
------------------------------------------------------------------------
            Condition               Required action     Completion time
------------------------------------------------------------------------
A. One or more SG tubes           A.1 Verify tube     7 days.
 satisfying the tube repair        integrity of the
 criteria and not plugged [or      affected tube(s)
 repaired] in accordance with      is maintained
 the Steam Generator Program.      until the next
                                   inspection. AND.

[[Page 10302]]

 
                                  A.2 Plug [or        Prior to entering
                                   repair] the         MODE 4 following
                                   affected tube(s)    the next
                                   in accordance       refueling outage
                                   with the Steam      or SG tube
                                   Generator Program.  inspection.
B. Required Action and            B.1 Be in MODE 3.   6 hours.
 associated Completion Time of     AND.
 Condition A not met. OR SG tube
 integrity not maintained.
                                  B.2 Be in MODE 5..  36 hours.
------------------------------------------------------------------------

    Should SG tube integrity be found by the SG Program not to be 
maintained, Required Actions B.1 and B.2 would require that the plant 
be in MODE 3 within 6 hours and MODE 5 within 36 hours, respectively. 
These required actions and completion times are consistent with (1) the 
general requirements in TS 3.0.3 for failing to meet an LCO and (2) the 
requirements of TS 3.4.13 when the LCO on primary to secondary leakage 
rate is not met. The NRC staff concludes that these required actions 
and completion times provide adequate remedial measures should SG tube 
integrity be found not to be maintained and are acceptable to the NRC 
staff.
    Condition A of proposed TS 3.4.[17] addresses the condition where 
one or more tubes satisfying the tube repair criteria are inadvertently 
not plugged [or repaired] in accordance with the SG Program. Under 
Required Action A.1, the licensee would be required to verify within 7 
days that tube integrity of the affected tubes is maintained until the 
next inspection. The accompanying Bases state that the tube integrity 
determination would be based on the estimated condition of the tube at 
the time the situation is discovered and the estimated growth of the 
degradation prior to the next inspection. The NRC staff notes that 
details of how this assessment would be performed are not included in 
proposed TS 3.4.[17] or 5.5.9. The NRC staff finds this to be 
consistent with having performance-based requirements, finds that the 
performance criteria (i.e., performance objectives) for assessing tube 
integrity are clearly defined (in TS 5.5.9), and finds that it is 
appropriate that the licensee have the flexibility to determine how 
best to perform this assessment based on what information is and is not 
available concerning the circumstances of the subject flaw. The 
proposed 7 days allowed to complete the assessment ensures that the 
risk increment associated with operating with tubes in this condition 
will be very small. Should the assessment reveal that tube integrity 
cannot be maintained until the next scheduled inspection or if the 
assessment is not completed in 7 days, Condition B applies, leading to 
Required Actions B.1 and B.2, which are evaluated above. Finally, if 
Required Action A.1 successfully verifies that tube integrity is being 
maintained until the next inspection, Required Action A.2 would require 
that the subject tube be plugged [or repaired] in accordance with the 
SG Program prior to entering MODE 4 after the next refueling outage or 
SG inspection. Based on the above, the NRC staff concludes that the 
proposed LCO and accompanying ACTIONS related to failure to plug [or 
repair] a tube that satisfies the tube repair criteria to be 
acceptable.
    The licensee has proposed administrative changes to the TS Title 
page and Bases supporting the proposed new TS 3.4.[17]. Although the TS 
Bases are controlled under the auspices of 10 CFR 50.59 and TS 5.5.14, 
TS Bases Control Program, the NRC staff finds the proposed changes to 
the proposed TS 3.4.[17] Bases to be acceptable.

3.2 Steam Generator Operability

    The TS Bases for [TS 3.4.4, RCS Loops--MODES 1 and 2,] TS 3.4.5, 
RCS Loops--MODE 3, and TS 3.4.6, RCS Loops--MODE 4, define an OPERABLE 
RCS Loop as consisting of an OPERABLE reactor coolant pump (RCP) in 
operation providing forced flow for heat transport and an OPERABLE SG 
in accordance with the Steam Generator Tube Surveillance Program. The 
Bases for TS 3.4.7, RCS Loops--MODE 5, Loops Filled, define an OPERABLE 
SG as a SG that can perform as a heat sink via natural circulation when 
it has an adequate water level and is OPERABLE in accordance with the 
Steam Generator Tube Surveillance Program. Although the TS Bases are 
controlled under the auspices of 10 CFR 50.59 and TS 5.5.14, TS Bases 
Control Program, the licensee has proposed to delete the phrases, ``in 
accordance with the Steam Generator Tube Surveillance Program,'' from 
TS [B3.4.4], B3.4.5, and B3.4.6, and ``and is OPERABLE in accordance 
with the Steam Generator Tube Surveillance Program,'' from TS B3.4.7.
    With the deletion of these phrases, an OPERABLE SG will be defined 
under the definition of OPERABLE--OPERABILITY defined in TS 1.1 and 
stated below:

    A system, subsystem, train, component, or device shall be 
OPERABLE or have OPERABILITY when it is capable of performing its 
specified safety function(s) and when all necessary attendant 
instrumentation, controls, normal or emergency electrical power, 
cooling and seal water, lubrication, and other auxiliary equipment 
that are required for the system, subsystem, train, component, or 
device to perform its specified safety function(s) are also capable 
of performing their related support function(s).

    The NRC staff has evaluated the proposed Bases changes. The current 
Bases refer to the SG Tube Surveillance Program for the requirements of 
an OPERABLE SG. The SG Tube Surveillance Program provided the controls 
for the ISI of SG tubes that was intended to ensure that the structural 
integrity of this portion of the RCS is maintained. Using the 
definition of OPERABLE--OPERABILITY expands the definition of an 
OPERABLE SG beyond maintaining structural integrity and is acceptable.

3.3 Proposed Administrative TS 5.5.9, ``Steam Generator Program''

    The proposed Administrative TS 5.5.9, ``Steam Generator Program'' 
replaces the existing administrative TS 5.5.9, ``Steam Generator Tube 
Surveillance Program.'' The current TS 5.5.9 defines a prescriptive 
strategy for ensuring tube integrity consisting of tube inspections 
performed at specified intervals, with a specified inspection scope 
(tube inspection sample sizes), and with a specified tube acceptance 
limit for degraded tubing, termed ``tube repair criterion,'' beyond 
which the affected tubes must be plugged [or repaired]. The proposed TS 
5.5.9 incorporates a largely performance-based strategy for ensuring 
tube integrity, requiring that a SG Program be established and 
implemented to ensure tube integrity is maintained. The proposed 
specification contains only a few details concerning how this is to be

[[Page 10303]]

accomplished, the intent being that the licensee will have the 
flexibility to determine the specific strategy to be employed to 
satisfy the required objective of maintaining tube integrity. However, 
as evaluated below, the NRC staff concludes that proposed TS 5.5.9 
provides reasonable assurance that the SG Program will maintain tube 
integrity.
    The proposed BASES for TS 3.4.[17] state that NEI 97-06 and its 
referenced EPRI guideline documents will be used to establish the 
content of the SG Program. The guidelines are industry-controlled 
documents and licensee SG programs may deviate from these guidelines. 
Except as may be specifically invoked by the TSs, the NRC staff's 
evaluation herein takes no credit for any of the specifics in the 
guidelines.
3.3.1 Performance Criteria for SG Tube Integrity
    Proposed TS 5.5.9 would require that SG tube integrity shall be 
maintained by meeting the performance criteria for tube structural 
integrity, accident induced leakage, and operational leakage as 
specified therein.
    The NRC staff's criteria for evaluating the acceptability of these 
performance criteria are that meeting these criteria is sufficient to 
ensure that tube integrity is within the plant licensing basis and that 
meeting these criteria, in conjunction with implementation of the SG 
Program, ensures no significant increase in risk. These performance 
criteria must also be evaluated in the context of the overall SG 
Program such that if the performance criteria are inadvertently 
exceeded, the consequences will be tolerable before the situation is 
identified and corrected. In addition, the performance criteria must be 
expressed in terms of parameters that are measurable, directly or 
indirectly.
    3.3.1.1 Structural Integrity Criterion. The proposed structural 
integrity criterion is as follows:

    All inservice steam generator tubes shall retain structural 
integrity over the full range of normal operating conditions 
(including startup, operation in the power range, hot standby, 
cooldown, and all anticipated transients included in the design 
specification) and design basis accidents. This includes maintaining 
a safety factor of 3.0 against burst under normal steady state full 
power operation primary-to-secondary pressure differential and a 
safety factor of 1.4 against burst applied to design basis accident 
primary to secondary pressure differentials. Apart from the above 
requirements, additional loading conditions associated with design 
basis accidents, or combination of accidents in accordance with the 
design and licensing basis, shall also be evaluated to determine if 
the associated loads contribute significantly to burst or collapse. 
In the assessment of tube integrity, those loads that do 
significantly affect burst or collapse shall be determined and 
assessed in combination with the loads due to differential pressure 
with a safety factor of 1.2 on the combined primary loads and 1.0 on 
axial secondary loads.

    The NRC staff has evaluated this proposed criterion for consistency 
with the safety factors embodied in the current licensing basis, 
specifically, the safety factors embodied in the TS tube repair 
criterion. The tube repair criterion typically specified in plant TSs 
is 40 percent of the initial tube wall thickness. This criterion is 
typically applicable to all tubing flaws found by inspection, except 
for certain flaw types at certain locations for which less restrictive 
repair criterion may be applicable (as specified in the TSs) and for 
certain sleeve repairs for which a more restrictive tube repair 
criterion may be specified. [For [plant name Units 1 and 2], the 40 
percent tube repair criterion is the only such criterion and is 
applicable to all flaw types at all tube locations.]

[Note to reviewers: If plant TS already include an ARC, add a 
statement to the effect that in addition to the 40% tube repair 
criterion, the subject plant also has alternate repair criteria as 
discussed in Section 3.3.4 of this SE.]

    In 1976 the NRC staff prepared RG 1.121 (Draft), ``Basis for 
Plugging Degraded PWR Steam Generator Tubes,'' (Reference 4) describing 
a technical basis for the development of tube repair criteria. This 
draft RG was issued for public comment, but was never finalized. 
Although not finalized, the RG is generally cited in licensee and 
industry documentation as the bases for the TS tube repair criterion in 
plant TSs. The draft RG includes the following with respect to safety 
factors:
    a. Degraded tubing should retain a factor of safety against burst 
of not less than three under normal operating conditions.
    b. Degraded tubing should not be stressed beyond the elastic range 
of the tube material during the full range of normal reactor operation. 
The draft regulatory guide also states that loadings associated with 
normal plant conditions, including startup, operation in the power 
range, hot standby, and cooldown, as well as all anticipated transients 
(e.g., loss of electrical load, loss of off-site power) that are 
included in the design specifications for the plant, should not produce 
a primary membrane stress in excess of the yield stress of the tube 
material at operating temperature.
    c. Degraded tubes should maintain a margin of safety against tube 
failure under postulated accidents consistent with the margin of safety 
determined by the stress limits specified in NB-3225 of Section III of 
the ASME Code. Note, NB-3225 specifies that the rules in Appendix F of 
Section III may be used for evaluating these loadings.
    The ``safety factor of three'' criterion stems from Section III of 
the ASME Code which, in part, limits primary membrane stress under 
design conditions to one third of ultimate strength. The proposed 
structural integrity criterion would limit application of the ``safety 
factor of three'' criterion to those pressure loadings existing during 
normal full power, steady state operating conditions. Differential 
pressures under this condition are plant specific, ranging from 1250 
psi to 1500 psi (Reference 5). However, differential pressure loadings 
can be considerably higher during normal operating transients, ranging 
to between 1600 psi to 2150 psi during plant heatup and cooldown 
(Reference 5). Given a factor of safety equal to three under normal 
full power conditions, the factor of safety during heatups and 
cooldowns can be as low as about two. The industry stated in a white 
paper (Reference 5) that it was not the intent of the 40 percent depth-
based tube repair criterion to ensure a factor of safety of three for 
operating transients such as heatups and cooldowns. The industry stated 
that maintaining a safety factor of three for such transients would 
lead to a tube repair criterion less than the standard 40 percent 
criterion for many plants. The NRC staff has independently performed 
calculations that support the industry's contention that applying the 
``safety factor of three'' criterion to the full range of normal 
operating conditions would lead to a tube repair criterion more 
restrictive than the 40 percent criterion that the NRC staff has 
accepted since the 1970s. The NRC staff concludes that the ``safety 
factor of three'' criterion for application to normal full power, 
steady state pressure differentials, as proposed by the licensee and 
the industry, is consistent with the safety margins implicit in 
existing TS tube repair criteria and, thus, is consistent with the 
current licensing basis.
    Item b above from draft RG 1.121 is often referred to as the ``no 
yield'' criterion. The purpose of this criterion is to prevent 
permanent deformation of the tube to assure that degradation of the 
tube will not occur due to mechanical effects of the service condition. 
This is consistent with the ASME Code, Section III, stress limits,

[[Page 10304]]

which serve to limit primary membrane stress to less than yield. The 
proposed structural integrity criteria do not include this ``no yield'' 
criterion. The industry states in its white paper (Reference 5) that, 
if a tube satisfies the ``safety factor of three'' criterion at full 
power operating pressure differentials, the tube will generally satisfy 
the ``no yield'' criterion for the operating transient (e.g., heatup 
and cooldown) pressure differentials. The white paper acknowledges that 
this may not be true for all plant-specific conditions and material 
properties. For this reason, NEI 97-06, Rev. 1, and the EPRI Steam 
Generator Integrity Assessment Guidelines state that, in addition to 
meeting the safety factor of three for normal steady state operation, 
the integrity evaluation shall verify that the primary pressure 
stresses do not exceed the yield strength for the full range of normal 
operating conditions. The white paper, which has been incorporated as 
part of the EPRI Steam Generator Integrity Assessment Guidelines, 
recommends that this be demonstrated for each plant using plant 
specific conditions and material properties.
    The NRC staff concurs that the ``no yield'' criterion need not be 
specifically spelled out in the TS definition of the structural 
integrity criterion. The NRC staff finds that the appropriate focus of 
the TS criteria should be on preventing burst. The NRC staff 
calculations confirm that the proposed ``safety factor of three'' 
criterion bounds or comes close to bounding the ``no yield'' criterion 
for most of the cases investigated. This is not absolute, however. For 
once-through steam generators (OTSGs), the NRC staff noted a case where 
elastic hoop stress in a uniformly thinned tube could exceed the yield 
strength by 20 percent under heatup and cooldown conditions and still 
satisfy the ``safety factor of three'' criterion against burst under 
normal steady state, full power operating conditions. Such a tube would 
still retain a factor of safety of two against burst under heatup and 
cooldown conditions. The amount of plastic strain induced would be 
limited to between 1 and 2 percent based on typical strain hardening 
characteristics of the material. This is quite small compared to cold 
working associated with fabrication of tube u-bends and tube 
expansions. Operating experience shows that this level of plastic 
strain (i.e., permanent strain caused by exceeding the yield stress) 
has not adversely affected the stress corrosion cracking resistance of 
OTSG tubing relative to that expected for non-plastically strained 
tubing. Thus, the NRC staff concludes that the ``safety factor of 
three'' criterion is sufficient to limit plastic strains to values that 
will not contribute significantly to degradation of the tubing and that 
the ``no yield'' criterion need not be specifically spelled out in the 
structural integrity performance criterion.
    The proposed safety factor of 1.4 against burst applied to design 
basis primary-to-secondary pressure differentials derives from the 0.7 
times ultimate strength limit for primary membrane stress in the ASME 
Code, Appendix F, F-1331.1(a). This criterion is consistent with the 
stress limit criterion used to develop the standard 40 percent tube 
repair criterion in the TSs and with the safety factor criteria used in 
the derivation of alternate tube repair criteria in plant TSs, such as 
the voltage based criterion for outer-diameter stress corrosion 
cracking. Thus, the criterion is consistent with the current licensing 
basis and is acceptable.
    Apart from differential pressure loadings, other types of loads may 
also contribute to burst. Examples of such loads include bending 
moments on the tubes due to flow induced vibration, earthquake, and 
loss-of-coolant accident (LOCA) rarefaction waves. For OTSGs, axial 
loads are induced in the tubes due to pressure loadings acting on the 
SG shell and tube sheets and due to differential thermal expansion 
between the tubes and the SG shell. Such non-pressure loads generally 
produce negligible primary stress during normal operating conditions 
from the standpoint of influencing burst pressure. In general, such 
non-pressure loads may be more significant under certain accident 
loadings depending on SG design, flaw location, and flaw orientation. 
Such non-pressure sources of primary stress under accident conditions 
were explicitly considered in the development of the 40 percent tube 
repair criterion relative to ASME Code, Appendix F, stress limits.
    The proposed structural criterion requires that, apart from the 
safety-factor requirements applying to pressure loads, additional loads 
associated with DBAs, or combination of accidents in accordance with 
the design and licensing basis, shall also be evaluated to determine 
whether these loads contribute significantly to burst or collapse. The 
NRC staff notes that examples of such additional loads include bending 
moments during LOCA, MSLB, or safe shutdown earthquake (SSE) and axial, 
differential thermal loads. ``Combination of accidents'' refers to the 
fact that the design and licensing basis for many plants is that DBAs, 
such as LOCA and MSLB, are assumed to occur concurrently with SSE. 
Whereas ``burst'' is the failure mode of interest where primary-to-
secondary pressure loads are dominant, ``collapse'' is a potential 
limiting failure mode (although an unlikely one, according to industry, 
based on a recent study (Reference 6)) for loads other than pressure 
loads. ``Collapse'' refers to the condition where the tube is not 
capable of resisting further applied loading without unlimited 
displacement. Although the occurrence of a collapsed tube or tubes 
would not necessarily lead to perforation of the tube wall, the 
consequences of tube collapse have not been analyzed and, thus, the NRC 
staff finds it both appropriate and conservative to ensure there is 
margin relative to such a condition.
    Where non-pressure loads are determined to significantly contribute 
to burst or collapse, the proposed structural criterion requires that 
such loads be determined and assessed in combination with the loads due 
to pressure with a safety factor of 1.2 on the combined primary loads 
and 1.0 safety factor on axial secondary loads. The 1.2 safety factor 
for combined primary loads was derived from the ratio of burst or 
collapse load divided by allowable load from ASME Code for faulted 
conditions. Burst or collapse load was assumed to be equal to the 
material flow stress, assuming Code minimum yield and ultimate strength 
values and a flow stress coefficient of 0.5. Allowable load was 
determined from ASME Code, Section III, Appendix F, F-1331.3.a, which 
defines an allowable primary membrane plus bending load for service 
level d (faulted) conditions. The NRC staff finds this 1.2 safety 
factor acceptable. The proposed 1.0 safety factor for axial secondary 
loads goes beyond what is required by the design basis in Section III 
of the ASME Code, since Section III assumes that a one time application 
of such a load cannot lead to burst or collapse. However, this is not 
necessarily the case for tubes with circumferential cracks. The 
proposed safety factor criterion of 1.0 is conservative for loads that 
behave as secondary since it ignores the load relaxation effect 
associated with axial yielding before tube severance (burst) occurs.
    Apart from being consistent with the current licensing basis, NRC 
risk studies have indicated that maintaining the performance criteria 
safety factors is important to avoiding undue risk, particularly risk 
associated with severe accident scenarios involving a fully

[[Page 10305]]

pressurized primary system and depressurized secondary system and where 
the tubes may heat to temperatures well above design basis values, 
significantly reducing the strength of the tubes (Reference 7).
    Based on the above, the NRC staff finds that the proposed 
structural performance criterion is consistent with the margins of 
safety embodied in existing plant licensing bases. Exceeding this 
criterion is not likely to lead to consequences that are intolerable 
provided that such a condition is infrequent and that, if it occurs, it 
is promptly detected and corrected so as to ensure that risk is 
limited. Even if a tube should degrade to the point of rupture under 
normal operating conditions, such an occurrence is an analyzed 
condition with reasonable assurance that the radiological consequences 
will be acceptable. Finally, the structural performance criterion is 
expressed in terms of parameters that are measurable. Specifically, 
structural margins can be directly demonstrated through in situ 
pressure testing or can be calculated from burst prediction models 
using as input flaw size measurements obtained by inspection. Thus, the 
NRC staff finds the proposed structural performance criterion to be 
acceptable.
    3.3.1.2 Accident Induced Leakage Criterion. The proposed accident 
induced leak rate criterion is as follows:

    The primary-to-secondary accident induced leakage rate for any 
design basis accident, other than a SG tube rupture, shall not 
exceed the leakage rate assumed in the accident analysis in terms of 
total leakage rate for all SGs and leakage rate for an individual 
SG. Leakage is not to exceed [1 gpm] per SG [except for specific 
types of degradation at specific locations as described in paragraph 
c of the Steam Generator Program.]

    This performance criterion for accident induced leak rate is 
consistent with leak rates assumed in the licensing basis accident 
analyses for purposes of demonstrating that the consequences of DBAs 
meet the limits in 10 CFR 100 for offsite doses, GDC 19 for control 
room operator doses, or some fraction thereof as appropriate to the 
accident, or the NRC-approved licensing basis (e.g., a small fraction 
of these limits). This criterion does not apply to design basis SGTR 
accidents for which leakage corresponding to a postulated double ended 
rupture of a tube is assumed in the analysis. The proposed criterion 
ensures that from the standpoint of accident induced leakage the plant 
will be operated within its analyzed condition and is acceptable.
    For certain severe accident sequences involving high primary side 
pressure and a depressurized secondary system (``high-dry'' condition), 
primary-to-secondary leakage may lead to more heating of the leaking 
tube than would be the case were it not leaking, thus increasing the 
potential for failure of that tube and a consequent large early 
release. The proposed [1.0 gpm] limit on total leakage from each SGs 
during DBAs (other than an SGTR) ensures that the potential for induced 
leakage during severe accidents will be maintained at a level that will 
not increase risk.

[Note to reviewers: Where the limit on total leakage is higher than 
1 gpm for the component of leakage associated with implementation of 
previously approved ARCs for specific types of degradation and 
locations, the following sentences should be included in the SE.]

    [However, the staff finds that this limit may be exceeded for the 
component of accident leakage associated with [degradation mechanism] 
located [degradation locations] and calculated in accordance with the 
associated, approved ARC, provided the total leakage for all SGs from 
all degradation mechanisms doesn't exceed that assumed in the accident 
analyses. This is based on the fact that leakage associated with 
[degradation type] at [location] DBAs is conservatively treated as free 
span leakage by the ARC methodology. Because of the constraint against 
leakage provided by the [tight tube-to-tube support plate intersections 
or tubesheets, as the case may be] for the subject degradation type and 
location under high-dry severe accident sequences, allowing the 
calculated leakage during DBAs to exceed 1 gpm up to the value assumed 
in the accident analyses is not expected for practical purposes to 
increase the potential for leakage during high-dry severe accident 
sequences than would the case of a freespan crack leaking at the rate 
of 1 gpm under DBA conditions.]
    It is not likely that exceeding this criterion will lead to 
intolerable consequences provided that such an occurrence is infrequent 
and that such an occurrence, if it occurs, is promptly detected and 
corrected so as to ensure that risk is minimized. It should be noted 
that the criterion applies to leakage that could be induced by an 
accident in the unlikely event that such an accident occurs. Finally, 
the accident leakage performance criterion is expressed in terms of 
parameters that are measurable, both directly and indirectly. 
Specifically, structural margins can be directly demonstrated through 
in situ pressure testing or can be calculated using leakage prediction 
models using flaw size measurements obtained by ISI as input.
    Based on the foregoing, the NRC staff finds the proposed accident 
leakage performance criterion to be acceptable.
    3.3.1.3 Operational Leakage Criterion. Proposed TS 5.5.9 states 
that the operational leakage performance criterion is specified in LCO 
3.4.13, ``RCS Operational LEAKAGE.'' Given the TS LCO limit, a separate 
performance criterion for operational leakage is unnecessary for 
ensuring prompt shutdown should the limit be exceeded. However, 
operational leakage is an indicator of tube integrity performance, 
though not a direct indicator. It is the only indicator that can be 
monitored while the plant is operating. Maintaining leakage to within 
the limit provides added assurance that the structural and accident 
leakage performance criteria are being met. Thus, the NRC staff 
believes that inclusion of the TS leakage limit among the set of tube 
integrity performance criteria is appropriate from the standpoint of 
completeness and is, therefore, acceptable.
3.3.2 Condition Monitoring Assessment
    Proposed TS 5.5.9 would require that the SG Program include 
provisions for condition monitoring assessments as follows:

    Condition monitoring assessment means an evaluation of the ``as 
found'' condition of the tubing with respect to the performance 
criteria for structural integrity and accident induced leakage. The 
``as found'' condition refers to the condition of the tubing during 
a SG inspection outage, as determined from the inservice inspection 
results or by other means, prior to the plugging [or repair] of 
tubes. Condition monitoring assessments shall be conducted during 
each outage during which the SG tubes are inspected or plugged [or 
repaired] to confirm that the performance criteria are being met.

    The NRC staff finds that the proposed requirement for condition 
monitoring assessments addresses an essential element of any 
performance-based strategy, namely, the need to monitor performance 
relative to the performance criteria. Confirmation that the tube 
integrity criteria are met would confirm that the overall programmatic 
goal of maintaining tube integrity has been met to that point in time. 
However, failure to meet the tube integrity criteria would be 
indicative of potential shortcomings in the effectiveness of the 
licensee's SG Program and the need for corrective actions relative to 
the program to ensure that tube integrity is maintained in the future. 
Failure to meet either the structural or accident induced leakage

[[Page 10306]]

performance criterion would be reportable pursuant to 10 CFR 50.72 and 
50.73 in accordance with guidelines in Reference 8. In addition, the 
NRC Regional Office would follow up on such an occurrence as 
appropriate consistent with the NRC Reactor Oversight Program (ROP) 
(Reference 10) and the risk significance of the occurrence.
    TS 5.5.9 would require that condition monitoring be performed at 
each ISI of the tubing. The NRC staff's evaluation of the proposed 
frequency of ISI is addressed in section 3.3.3 of this safety 
evaluation.
3.3.3 Inservice Inspection
    The proposed TS 5.5.9 would require that the SG Program include 
periodic tube inspections. This proposal includes a new performance-
based requirement that the inspection scope, inspection methods, and 
inspection intervals shall be such as to ensure that SG tube integrity 
is maintained until the next inspection. This is a performance-based 
requirement that complements the requirement for condition monitoring 
from the standpoint of ensuring tube integrity is maintained. The 
requirement for condition monitoring is backward looking in that it is 
intended to confirm that tube integrity has been maintained up to the 
time the assessment is performed. The ISI requirement, by contrast, is 
forward looking. It is intended to ensure that tube inspections in 
conjunction with plugging [or repairing] of tubes are performed such as 
to ensure that the performance criteria will continue to be met at the 
next SG inspection. This would be followed again by condition 
monitoring at the next SG inspection to confirm that the performance 
criteria were in fact met.
    With respect to scope and methods of inspection, the proposed 
specification would also require that the number and portions of tubes 
inspected and method of inspection be performed with the objective of 
detecting flaws of any type (for example, volumetric flaws, axial and 
circumferential cracks) that may be present along the length of the 
tube, from the tube-to-tubesheet weld at the tube inlet to the tube-to-
tubesheet weld at the tube outlet, and that may satisfy the applicable 
tube repair criterion. Furthermore, an assessment of degradation shall 
be performed to determine the type and location of flaws to which the 
tubes may be susceptible and, based on this assessment, to determine 
which inspection methods need to be employed and at what locations.
    The NRC staff finds that this proposal concerning the scope and 
methods of inspection includes a number of improvements relative to the 
current specification. The current specification requires that tube 
inspections be conducted from the point of entry on the hot leg side 
completely around the u-bend to the top support plate on the cold leg 
side. Thus, the current TS does not require inspection of tubing on the 
cold leg side up to the uppermost support plate elevation. Operating 
experience demonstrates that the entire length of tubing is subject to 
various forms of degradation. The proposed specification addresses this 
issue by requiring cold leg as well as hot leg inspections. Also, the 
proposed requirement clarifies the licensee's obligation under existing 
TSs and 10 CFR 50, Appendix B, to employ inspection methods capable of 
detecting flaws of any type that the licensee believes may potentially 
be present anywhere along the length of the tube based on a degradation 
assessment.
    The proposed specification specifically excludes the tubesheet 
welds and the tube ends beyond the welds from the inspection 
requirements therein. The NRC staff finds this to be consistent with 
current actual practice and to be acceptable. The tube ends beyond the 
tube-to-tubesheet welds are not part of the primary pressure boundary.
    The proposed specification would replace current specific 
requirements pertaining to the number of tubes to be inspected at each 
inspection, in part, with a requirement that is performance-based; that 
is, the number and portions of tubes inspected (in conjunction with 
other elements of inspection) shall be such as to ensure that tube 
integrity is maintained until the next inspection. The current minimum 
tube sampling requirement for an SG inspection is 3 percent of the SG 
tubing at the plant. The purpose of this initial sample is to determine 
whether active degradation is present and whether there is a need to 
perform additional inspection sampling. Actual industry practice, 
consistent with NEI 97-06 and the EPRI Examination Guidelines, Rev. 6, 
typically involves initial inspection samples of at least 20 percent. 
If moderate numbers of tubes (i.e., category C-2 as defined in the 
current TS) are found to contain flaws, the current TS require that an 
additional 6 to 18 percent of the tubes be inspected. In many cases 
this requirement is very non-conservative since no consideration is 
given to whether uninspected tubes may contain flaws that could 
challenge the tube integrity performance criteria prior to the next 
inspection. Current industry practice and the industry guidelines 
involve substantially higher levels of sampling under these 
circumstances. This practice has been motivated by a desire to minimize 
forced outages as well as to ensure tube integrity. The NRC staff 
finds, therefore, that current TS sampling requirements do not drive 
actual sampling programs in the field for plants with low to moderate 
levels of tube degradation, and that for moderate levels of tube 
degradation the current TS requirements do not ensure adequate levels 
of sampling to ensure tube integrity will be maintained. The proposed 
specification addresses this shortcoming by requiring that inspection 
scope be consistent with the overall performance objective that tube 
integrity be maintained until the next SG inspection.
    For SGs with high levels of degradation (i.e., category C-3 as 
defined in current TS), the current TS requires that the inspections be 
expanded to include 100 percent of the tubes in the affected SG. This 
requirement is conservative in cases where the active degradation is 
confined to specific groups of tubes in the SG. This requirement does 
drive actual sampling programs in the field since industry guidelines 
would permit 100 percent sampling to be confined to those portions of 
the SG bounding the region where the degradation has been found to be 
active. The proposed specification would give licensees the flexibility 
to implement less than 100 percent inspection of the SG in these cases 
provided it is consistent with the performance-based objective of 
ensuring that tube integrity is maintained until the next SG 
inspection.
    Overall, the NRC staff concludes that the proposed specification 
ensures that the licensee will implement inspection scopes consistent 
with the overall objective that tube integrity be maintained. To meet 
this requirement, it will be necessary to inspect tubes that may 
contain flaws that may challenge the tube integrity performance 
criteria prior to the next inspection. The proposed specification gives 
the licensee the flexibility to define an inspection scope that ensures 
that this objective is met while avoiding any unnecessary inspections.
    With respect to frequency of inspection, the current specification 
requires that SG inspections be performed every 24 calendar months. 
This frequency may be extended to once every 40 calendar months if the 
previous two inspections revealed only low-level degradation (i.e., 
category C-1 results as defined in the TS). The

[[Page 10307]]

inspection frequency is required to revert from the 40 calendar months 
to 20 calendar months if an extensive level of degradation (i.e., 
category C-3 results as defined in the TS) is observed during the most 
recent inspection. Except in cases where extensive degradation (i.e., 
category C-3) is found in any SG, SGs may be inspected on a rotating 
basis at each inspection. Thus, for 4-loop plants performing SG 
inspections at 24-month intervals, intervals for individual SGs may 
range to 96 months. Similarly, for 4-loop plants performing SG 
inspections at 40-month intervals, intervals for individual SGs may 
range to 160 months. However, these prescriptive requirements bear no 
direct relationship to the overall objective of ensuring tube integrity 
is maintained. These requirements apply irrespective of the flaw 
detection and sizing performance of the inspection methods utilized and 
the rate at which flaws may be growing in the subject SGs. These 
requirements do not ensure that flawed tubing remaining in service 
following an SG tube inspection and the incremental flaw growth that 
may take place prior to the next inspection are with within the 
allowances provided for by the TS tube repair limit or that tube 
integrity will be maintained prior to the next inspection.
    Plants operating with their originally installed SGs have typically 
inspected each SG at each refueling outage, which typically occur at 
intervals of less than 24 calendar months. The vast majority of these 
SGs contained alloy 600 mill annealed (MA) tubing, which quickly became 
moderately to extensively degraded (i.e., category C-2 or C-3 as 
defined in the TS) such that the TS would not allow longer intervals. 
The 24-month inspection interval requirement usually proved sufficient 
in maintaining tube integrity. Nonetheless, there have been instances 
where licensees have performed mid-cycle inspections to ensure tube 
integrity would be maintained.

[Note to reviewers: the following paragraph may be deleted for 
plants with alloy 600 MA tubing. For plants with 600 TT and 690 TT, 
the following paragraph may need to be extensively revised, as 
appropriate.]

    [However, many SGs with alloy 600 MA tubing have been replaced with 
SGs with alloy 600 TT or alloy 690 TT tubing, which have proven to be 
much more resistant to SCC than alloy 600 MA tubing. In addition, a few 
plants are operating with originally installed SGs with alloy 600TT 
tubing. Based on early low levels of degradation, some of the plants 
with SGs with alloy 600TT or 690TT tubing are taking advantage of the 
longer inspection intervals permitted by the TS.]
    Under the proposed specification (TS 5.5.9), the required frequency 
of inspection in conjunction with inspection scope and inspection 
methods shall be such as to ensure that tube integrity is maintained 
until the next SG inspection. This addresses existing shortcomings in 
the current requirements in that it requires that inspection frequency 
be part of a management strategy aimed at ensuring tube integrity. The 
proposed TS 3.4.[17] BASES states that inspection frequency will be 
determined, in part, by operational assessments that utilize additional 
information on existing degradation and flaw growth rates to determine 
an inspection frequency that provides reasonable assurance that the 
tubing will meet the SG performance criteria at the next SG inspection.
    The NRC staff also notes, however, that any assessment or 
projection of the future condition of the SG tubing based on the 
existing condition of the tubing and anticipated flaw growth rates can 
involve significant uncertainty that may be difficult to conservatively 
and reliably bound. For this reason, the proposed specification (TS 
5.5.9) supplements the performance-based requirement concerning 
inspection frequencies with a set of prescriptive requirements that 
provide added assurance that tube integrity will be maintained.
    The proposed prescriptive requirements include a requirement that 
100 percent of the tubes in each SG be inspected at the first refueling 
outage following SG replacement. [The NRC staff notes that this 
requirement is a moot point for [Plant Name] since the first ISI of the 
replacement SGs has already been performed.] The required scope of this 
inspection is substantially more restrictive than the current 
requirement, which requires a 3 percent sample of the total SG tube 
population and requires inspection of only [two] of the [four] SGs.

[Note to reviewers: The following three paragraphs apply to SGs with 
alloy 600 MA, 600 TT, and 690 TT tubing, respectively.]

    [For [Plant Name], which has alloy 600 MA tubing, the proposed 
specification would require that 100 percent of the tubes be inspected 
at sequential periods of 60 effective full power months (EFPM), with 
the first sequential period being considered to begin at the time of 
the first ISI of the SGs [following SG replacement]. However, no SG 
shall operate for more than 24 EFPM or one refueling outage (whichever 
is less) without being inspected.]
    [For [Plant Name], which has alloy 600 TT tubing, the proposed 
specification would require that 100 percent of the tubes be inspected 
at sequential periods of 120, 90, and, thereafter, 60 EFPM, with the 
first sequential period being considered to begin at the time of the 
first ISI of the SGs [following SG replacement]. This sliding scale is 
intended to address the increased potential for the initiation of 
stress corrosion cracking over time. In addition, the licensee would be 
required to inspect 50 percent of the tubes by the refueling outage 
nearest the mid-point of the period and the remaining 50 percent by the 
refueling outage nearest the end of the period. However, no SG shall 
operate for more than 48 EFPM or two refueling outages (whichever is 
less) without being inspected.]
    [For [Plant Name], which has alloy 690 TT tubing, the proposed 
specification would require that 100 percent of the tubes be inspected 
at sequential periods of 144, 108, 72, and, thereafter, 60 EFPM, with 
the first sequential period being considered to begin at the time of 
the first ISI of the SGs following SG replacement. This sliding scale 
is intended to address the increased potential for the initiation of 
stress corrosion cracking over time. In addition, the licensee would be 
required to inspect 50 percent of the tubes by the refueling outage 
nearest the mid-point of the period and the remaining 50 percent by the 
refueling outage nearest the end of the period. However, no SG shall 
operate for more than 72 EFPM or three refueling outages (whichever is 
less) without being inspected.]
    Regardless of the type of tubing, if crack indications are found in 
any tube, the proposed specification requires that the next inspection 
for each SG for the degradation mechanism causing the crack indication 
shall not exceed 24 EFPM or one refueling outage (whichever is less). 
As a point of clarification, the proposed requirements stipulate that 
if definitive information, such as from examination of a pulled tube, 
diagnostic non-destructive testing, or engineering evaluation, 
indicates that a crack-like indication is not a crack, then the 
indication need not be treated as such.
    These proposed prescriptive requirements, in total, cannot be 
described simplistically as being more restrictive or less restrictive 
than current requirements. They are a quite different set of 
requirements, being generally more restrictive for SGs with low-to-
moderate levels of degradation (i.e., categories C-1 to C-2 as defined 
in

[[Page 10308]]

current TS) to somewhat less restrictive for plants with extensive 
levels of degradation other than cracks.

[Note to reviewers: The following sentences apply only for SGs with 
alloy 600 TT or 690 TT tubing.]

    [As previously noted, management of SCC mechanisms relative to the 
performance criteria poses a particular challenge compared to other 
degradation mechanisms. The proposed requirement to limit inspection 
intervals to one refueling outage to address any cracking mechanism 
found to be present in the SGs is a substantially more restrictive 
requirement than current TS requirements that apply for plants with 
low-to-moderate levels of cracked tubes and, for practical purposes, 
leads to the same inspection frequency (every refueling outage) as 
would be required under current TS requirements for plants with 
moderate to extensive levels of cracked tubes.]

[Note to reviewers: The following sentence applies only to plants 
with alloy 600 MA tubing.]

    [The proposed requirement to limit inspection intervals to one 
refueling outage ensures that inspection intervals will be no less 
restrictive than current requirements.]
    The proposed prescriptive requirements relating to inspection 
frequency have been developed based on qualitative engineering 
considerations and experience[, reflecting the improved SCC resistance 
of alloy 690 TT tubing relative to alloy 600 TT and particularly 
relative to alloy 600 MA tubing, that the potential for cracking 
increases with increasing time in service, and the particular 
challenges associated with the management of SCC with respect to 
satisfying the tube integrity performance criteria].

[Note to reviewers: The preceeding words apply only to SGs with 
alloy 600 TT or 690 TT tubing.]

    The proposed prescriptive requirements are intended primarily to 
supplement the performance-based requirement that inspection frequency 
in conjunction with inspection scope and methods be such as to ensure 
tube integrity is maintained. This performance-based requirement must 
be satisfied in addition to the prescriptive requirements. The NRC 
staff concludes that the proposed performance-based requirement, in 
conjunction with the proposed prescriptive requirements, represents a 
significantly more effective strategy for ensuring tube integrity than 
that provided by current TS requirements and will serve to ensure that 
tube integrity is maintained between SG inspections.
3.3.4 Tube Repair Criteria
    Revised TS 5.5.9 would retain the current TS tube repair 
[criterion/criteria] (termed plugging limit[s] in current TSs) 
requirements. Specifically, the proposed specification would require 
that tubes found by ISI to contain flaws with a depth equal to or 
exceeding 40 percent of the nominal tube wall thickness be plugged. 
This criterion is consistent with the tube integrity performance 
criteria in that flaws not exceeding the tube repair criterion satisfy 
the performance criteria with allowances for flaw size measurement 
error and incremental crack growth between inspections.
    [In addition to the 40 percent depth based criterion, the proposed 
specification would continue to permit (as is currently permitted by 
the existing TS) the following alternate tube repair criteria (ARC) to 
be applied as an alternative to 40 percent depth based criterion:
    1)
    2)
    As is the case with the 40 percent depth-based criterion, flaws not 
exceeding the ARC satisfy the applicable performance criteria with 
allowance for inspection measurement error and flaw growth between 
inspections. The NRC staff has reviewed the descriptions of the ARCs in 
the revised specification and finds these descriptions to be equivalent 
to the descriptions in the existing specification and, thus, 
acceptable.]

[Note to reviewers: For certain ARCs such as the ODSCC voltage-based 
criteria and tube support plate PWSCC criteria, the following 
sentence applies.]

    [[Specific ARC name] provides for an exception to the tube 
structural integrity and accident induced leakage criteria in lieu of 
demonstrating during condition monitoring that each tube satisfies the 
1.4 criterion against burst under accident conditions as given in 
5.5.9.b.1, the licensee can establish that structural integrity is 
assured by demonstrating that the conditional probability of burst 
during accidents (for the degradation mechanisms and locations subject 
to the alternate repair criteria) is less than 1.0x10-2. In addition, 
the component of accident induced leakage for the degradation 
mechanisms and locations subject to the ARC may exceed 1 gpm per SG. 
However, total accident induced leakage for all degradation mechanisms 
and locations for any design basis accident, other than an SGTR, shall 
not exceed the leakage rate assumed in the accident analysis in terms 
of total leak rate for all SGs and leakage rate for an individual SG.] 
The TS tube repair criteria provide added assurance that tube integrity 
will be maintained, given the performance-based strategy that is also 
to be followed under the proposed specification. The inclusion of tube 
repair criteria as part of the proposed specification also ensures that 
the NRC staff has the opportunity to review any risk implications 
should the licensee propose a license amendment for alternate tube 
repair criteria, in conjunction with alternate tube integrity 
performance criteria, at some time in the future.
3.3.5 Monitoring of Operational Primary to Secondary Leakage
    Proposed TS 5.5.9 would require that the SG Program include 
provisions for monitoring primary-to-secondary leakage. The NRC staff's 
evaluation of this proposal is included as part of the NRC staff's 
evaluation of the proposed change to TS 3.4.13, ``RCS Operational 
Leakage,'' in Section 3.5 of this safety evaluation.

    [Note to reviewers: The following section is applicable only for 
those plants with technical specifications authorizing the use of 
one or more tube repair methods.]

3.3.6 SG Tube Repair Methods Other Than Plugging
    The proposed specification includes maintaining provisions for SG 
tube repair methods other than plugging as provided for in the existing 
TS. The proposed specification states that such repair methods shall 
provide the means to reestablish the RCS pressure boundary integrity of 
the SG tubes without removing the tube from service. The specification 
lists all acceptable repair methods, as follows:
    1)
    2)
    The NRC staff has reviewed the descriptions of these repair methods 
in the revised specification, including associated inspection and 
repair limit requirements, and finds these descriptions to be 
equivalent to the descriptions in the existing specification and, thus, 
to be acceptable.]

3.4 TS 5.6.9, ``Steam Generator (SG) Tube Inspection Report''

    The proposed administrative TS 5.6.9 would revise the reporting 
requirements of existing TS 5.6.9. Currently, this specification 
requires that the complete results of the SG Tube Surveillance Program 
(i.e., the ISI results) be reported within 12 months following 
completion of the program and include (1) the

[[Page 10309]]

number and extent of the tubes inspected, (2) the location and percent 
of wall thickness penetration for each indication, and (3) 
identification of tubes plugged. Under the revised requirement, a 
report shall be submitted within 180 days of entry into MODE 4 
following a SG inspection. The report shall include:
     The scope of the inspections performed in each SG,
     active degradation mechanisms found,
     non-destructive examination techniques used for each 
degradation mechanism,
     location, orientation (if linear), and measured sizes (if 
available) of service induced indications,
     number of tubes plugged [or repaired] during the 
inspection outage for each active degradation mechanism,
     total number and percentage of tubes plugged [or repaired] 
to date, [and]
     the results of condition monitoring, including the results 
of tube pulls and in-situ testing,
     [the effective plugging percentage for all plugging and 
tube repairs in each SG, and]
     [repair method utilized and the number of tubes repaired 
by each repair method.]
    This revised reporting requirement is a more comprehensive 
requirement than the current 12-month report and will enhance the NRC 
staff's ability to monitor the kinds of inspections being performed, 
the extent and severity of each active degradation mechanism, 
degradation trends (stable or getting worse), and the degree of 
challenge faced by the licensee in maintaining tube integrity. The 180-
day reporting requirement is adequate given that the failure of the SG 
program to maintain tube integrity as indicated by condition monitoring 
would be promptly reportable in accordance with 10 CFR 50.72 and 
Reference 8, allowing the NRC staff to engage in any follow-up 
activities that it determines to be necessary.
    The specification currently requires that the number of tubes 
plugged in each SG be reported to the NRC within 15 days following 
completion of the program. In addition, the specification currently 
requires that inspection results falling into Category C-3 shall be 
reported to the NRC pursuant to 10 CFR 50.73 prior to the resumption of 
plant operation and that the report include a description of the tube 
degradation and corrective measures taken to prevent recurrence. The 
proposed administrative TS 5.6.9 deletes both of these requirements. 
The NRC staff finds deletion of these requirements to be acceptable. 
Neither the number of tubes plugged nor the finding of Category C-3 
results (i.e., 10 percent of the tubes inspected contain degradation or 
1 percent of the tubes inspected satisfy the tube repair criterion) 
have any real bearing on whether tube integrity is being maintained. 
The NRC staff also notes that the proposed TS 5.6.9 would delete the 
definition of inspection results categories in the current TSs. If the 
SG program is effectively maintaining tube integrity, tubes found to be 
degraded or to be pluggable will also satisfy the tube integrity 
performance criteria. The regulation 10 CFR 50.72, in conjunction with 
Reference 8, requires that the NRC staff be promptly notified in the 
event that the tube integrity performance criteria are not met. The NRC 
staff would have the opportunity under the NRC ROP to follow up on such 
an occurrence as warranted. The regulation at 10 CFR 50.73 requires 
that a Licensee Event Report (LER) be issued within 60 days of the 
finding which addresses, in part, the degraded condition of the tube(s) 
and corrective measures being taken.
    Based on the foregoing, the NRC staff finds the proposed revisions 
to the reporting requirements to be acceptable.

3.5 Definition of LEAKAGE

    Technical Specification 1.1 currently defines LEAKAGE as (a) 
Identified LEAKAGE, (b) Unidentified LEAKAGE, and (c) Pressure Boundary 
LEAKAGE. The third definition under Identified LEAKAGE is: ``Reactor 
Coolant System (RCS) LEAKAGE through a steam generator (SG) to the 
Secondary System.'' Pressure Boundary LEAKAGE is defined as ``LEAKAGE 
(except SG Leakage) through a nonisolable fault in an RCS component 
body, pipe wall, or vessel wall.'' The licensee has proposed to replace 
the term ``SG LEAKAGE'' with ``primary to secondary LEAKAGE'' because 
``SG LEAKAGE'' is not used in the TS or TS Bases. Therefore, the third 
definition of Identified LEAKAGE will state: ``Reactor Coolant System 
(RCS) LEAKAGE through a steam generator to the Secondary System 
(primary to secondary LEAKAGE),'' and the definition of Pressure 
Boundary LEAKAGE will state: ``LEAKAGE (except primary to secondary 
LEAKAGE) through a nonisolable fault in an RCS component body, pipe 
wall, or vessel wall.'' The proposed changes are editorial in nature 
and adequately reflect the terminology used throughout the TS and 
Bases. Therefore, the NRC staff finds the proposed revisions to the 
definition of LEAKAGE to be acceptable.

3.6 TS 3.4.13, RCS Operational Leakage

    The licensee proposed several changes to the LCO, required actions, 
and SRs for TS 3.4.13, RCS Operational Leakage. These changes include 
administrative changes to the LCO, required action statements, and SR. 
The proposed administrative changes include the following:
    (a) adding ``and'' to the end of LCO 3.4.13.c;
    (b) replacing ``SG'' in LCO 3.4.13.e with ``steam generator (SG)';
    (c) LCO 3.4.13.e is changed to LCO 3.4.13.d with the deletion of 
the existing LCO 3.4.13.d discussed below.
    (d) adding ``operational'' to ``RCS operational LEAKAGE'' in 
Condition A;
    (e) adding ``or primary to secondary LEAKAGE'' to the end of 
Condition A. Condition A will state ``RCS operational LEAKAGE not 
within limits for reasons other than pressure boundary LEAKAGE or 
primary to secondary LEAKAGE.''
    (f) modifying the NOTE associated with SR 3.4.13.1. ``NOTE'' will 
be changed to ``NOTES,'' a ``1.'' and a second note, Note 2, will be 
added which will state ``Not applicable to primary to secondary 
LEAKAGE.''
    The NRC staff has reviewed these administrative changes and finds 
them acceptable. In particular, the addition of ``or primary to 
secondary LEAKAGE'' to Condition A and SR 3.4.13.1 Note 2 are 
considered to be administrative changes because these changes support 
the more restrictive addition of primary to secondary LEAKAGE to 
Condition B and SR 3.4.13.2. The need for Note 2 with respect to SR 
3.4.13.1 (i.e., not applicable to primary to secondary LEAKAGE) and for 
the proposed new SR 3.4.13.2, which deals with primary to secondary 
LEAKAGE, is discussed in the proposed revision to the BASES in 
B3.4.13.2. The revised BASES states that SR 3.4.13.1 is not applicable 
to primary to secondary leakage because leakage rates of 150 gpd or 
less cannot be accurately measured by an RCS water inventory balance.

[Note to reviewers: The following section, 3.6.X, is needed only for 
those plants which currently have a higher than 150 gpd limit) per 
SG. Such plants should be proposing to change this limit to 150 
gpd.]

    [3.6.X Revision of Leakage Limit for Individual SGs. LCO 3.4.13.e 
(which will become LCO 3.4.13.d, as discussed above) currently 
specifies a [500] gpd limit for primary to secondary LEAKAGE through 
any one SG. The proposed specification would replace this limit with a 
more restrictive 150 gpd limit. Although no leakage limit, even if 
reduced to zero, can be totally

[[Page 10310]]

effective in preventing SG tube ruptures, the NRC staff notes that 
operating experience demonstrates that leakage limits are an important 
element of an overall approach to limiting the occurrence of tube 
rupture and for ensuring SG tube integrity. In addition, the proposed 
limit is [significantly less than the conditions assumed in the safety 
analyses.] For these reasons, the NRC staff finds the revised LCO limit 
to be more restrictive than the existing limit, to be in accordance 
with 10 CFR 50.36(c)(2)(ii) and, thus, acceptable.]
3.6.[1] Deletion of LCO 3.4.13.d
    LCO 3.4.13.d currently requires that total primary to secondary 
LEAKAGE through all SGs be limited to 1 gpm and LCO 3.4.13.e requires 
that primary to secondary LEAKAGE through any one SG be limited to 150 
gpd. The licensee states that the 1 gpm limit for LEAKAGE through all 
SGs is redundant with the 150 gpd limit through any one SG (each [Plant 
Name] unit has [4] SGs; thus, [4] x 150 = 600 gpd total leakage through 
all SGs) and, accordingly, the licensee is proposing deletion of the 1 
gpm limit. Accordingly, the proposed specification would delete LCO 
3.4.13.d, but would retain the 150 gpd limit for any one SG in LCO 
3.4.13.e. This revised requirement would allow total LEAKAGE through 
all SGs to be equal to 600 gpd, assuming all SGs are leaking at the 
rate of 150 gpd. Because the existing LCO 3.4.13.d is redundant to LCO 
3.4.13.e, the NRC staff concludes that deleting LCO 3.4.13.d results in 
no change to the existing limits on total primary to secondary leakage 
from all SGs. Thus, the NRC staff finds the proposed change to the LCO 
requirement to be acceptable.
3.6.[2] TS 3.4.13 Condition B Primary to Secondary LEAKAGE
    The primary to secondary leakage limit, together with the allowable 
accident induced leakage limit, helps to ensure that the dose 
contribution from tube leakage will be limited to less than the 10 CFR 
100 and General Design Criterion (GDC) 19 dose limits or other NRC 
approved licensing basis for postulated accidents. The licensee 
proposed to add an additional OR statement to Condition B with regards 
to primary to secondary LEAKAGE. As proposed, Condition B would state:
    ``Required Action and associated Completion Time of Condition A not 
met.
    OR
    Pressure boundary LEAKAGE exists.
    OR
    Primary to secondary LEAKAGE not within limit.''
    The current requirements, Condition A, have a completion time of 
four hours to reduce LEAKAGE (other than pressure boundary LEAKAGE) to 
within limits after which Condition B (plant shutdown) must be entered. 
The TS limit is more restrictive than the current requirements in that 
if primary to secondary leakage exceeds 150 gpd, then a plant shutdown 
must be commenced without an allowance to reduce leakage, as provided 
in Condition A. The revised Condition B would require the reactor to be 
in MODE 3 in 6 hours and MODE 5 in 36 hours if primary to secondary 
leakage is not within limits. As discussed in Section 3.6 above, the 
licensee has excluded primary to secondary leakage from Condition A. 
The NRC staff has reviewed the proposed change to Condition B. These 
changes are additional restrictions on plant operations that enhance 
safety; therefore, the NRC staff has concluded that the addition of the 
primary to secondary leakage OR statement to Condition B is acceptable.
3.6.[3] Surveillance Requirements--Primary to Secondary Leakage
    SR 3.4.13.1 currently requires verification that RCS operational 
LEAKAGE is within limits by performance of RCS water inventory balance. 
The accompanying BASES state that primary to secondary leakage is also 
measured by performance of an RCS water inventory balance in 
conjunction with effluent monitoring within the secondary steam and 
feedwater systems. The BASES further state that the RCS water inventory 
balance must be met with the reactor at steady state operating 
conditions and near operating pressure. As previously discussed in 
Section 3.6 of this SE, the licensee has proposed adding a note to SR 
3.4.13.1 stating that this particular surveillance requirement is not 
applicable to primary to secondary leakage. The licensee would revise 
the accompanying BASES justifying this change, namely, LEAKAGE of 150 
gpd cannot be measured accurately by an RCS water inventory balance. 
The licensee has proposed a new surveillance requirement, SR 3.4.13.2, 
which would verify with a frequency of 72 hours that primary to 
secondary leakage does not exceed the 150 gpd LCO limit. The NRC staff 
believes this to be acceptable and in accordance with 10 CFR 
50.36(c)(3). The revised requirement would not specify the specific 
method to be employed; however, it would require that the SG Program 
include provisions for monitoring primary to secondary leakage. There 
are a variety of methods that can be used and the NRC staff concludes 
there is no need to tie this surveillance to a specific method in order 
to ensure that the plant is operated safely and within its LCO limits. 
The licensee would state in the accompanying BASES that the primary to 
secondary leakage measurement uses continuous process radiation 
monitors or radio chemical grab sampling. The NRC staff notes that the 
EPRI PWR Primary-to-Secondary Leak Guidelines provide extensive 
guidance to this effect.
    The accompanying BASES would also state that primary to secondary 
LEAKAGE is measured against the 150 gpd limit under room temperature 
conditions as described in the EPRI PWR Primary-to-Secondary Leak 
Guidelines. The BASES state that steam line break (SLB) is the most 
limiting accident or transient from the standpoint of dose releases 
from primary to secondary LEAKAGE. The [Plant Name] safety analysis for 
SLB assumes [500] gpd and [470] gpd primary to secondary LEAKAGE (for 
room temperature conditions) in the faulted and intact SGs respectively 
as an initial condition. Thus, the assumed total primary to secondary 
LEAKAGE from all SGs is [1440] gpd (1 gpm). The NRC staff concludes 
that measurement of operational primary to secondary LEAKAGE under room 
temperature conditions relative to the 150 gpd operational limit is 
acceptable since it ensures that LEAKAGE under hot operational 
conditions will be less than assumed in the [Plant Name] safety 
analysis and, thus, is in accordance with 10 CFR 50.36(c)(2)(ii).
    The new SR, SR 3.4.13.2, with respect to primary to secondary 
leakage replaces the current SR 3.4.13.2, which involved verifying SG 
tube integrity in accordance with the SG Tube Surveillance Program. As 
discussed earlier in this SE, TS 5.5.9, ``Steam Generator Tube 
Surveillance Program,'' would be replaced by TS 5.5.9, ``Steam 
Generator Program.'' The SR to verify tube integrity would be addressed 
in the proposed new TS 3.4.[17], ``Steam Generator Tube Integrity,'' 
SRs.
    Based on the above, the NRC staff concludes that the proposed 
revisions to SR 3.4.13.1 and SR 3.4.13.2 are in accordance with 10 CFR 
50.36(c)(3) and 10 CFR 50.36(c)(2)(ii) and are acceptable.

3.7 Technical Evaluation--Summary and Conclusions

    The proposed [Plant Name] specification changes establish a 
programmatic, largely performance-

[[Page 10311]]

based regulatory framework for ensuring SG tube integrity is 
maintained. The NRC staff finds that it addresses key shortcomings of 
the current framework by ensuring that SG programs are focused on 
accomplishing the overall objective of maintaining tube integrity. It 
incorporates performance criteria for evaluating tube integrity that 
the NRC staff finds consistent with the structural margins and the 
degree of leak tightness assumed in the current plant licensing basis. 
The NRC staff finds that maintaining these performance criteria 
provides reasonable assurance that the SGs can be operated safely 
without increase in risk.
    The revised TSs would contain limited details concerning how the SG 
Program is to achieve the required objective of maintaining tube 
integrity, the intent being that the licensee will have the flexibility 
to determine the specific strategy for meeting this objective. However, 
the NRC staff finds that the revised TSs include sufficient regulatory 
constraints on the establishment and implementation of the SG Program 
such as to provide reasonable assurance that tube integrity will be 
maintained.
    Failure to meet the performance criteria will be reportable 
pursuant to 10 CFR 50.72 and 50.73. The NRC ROP provides a process by 
which the NRC staff can verify that the licensee has identified any SG 
Program deficiencies that may have contributed to such an occurrence 
and that appropriate corrective actions have been implemented.
    In conclusion, the NRC staff finds that the [Plant Name] TS 
amendment request conforms to the requirements of 10 CFR 50.36 and 
establishes a TS framework that will provide reasonable assurance that 
tube integrity is maintained without undue risk to public health and 
safety.

4.0 References

    (1) Letter, R.E. Beedle, NEI, to L.J. Callan, NRC, December 16, 
1997, transmitting NEI 97-06 (Original), ``Steam Generator Program 
Guidelines.''
    (2) NEI 97-06, Revision 1, ``Steam Generator Program Guidelines,'' 
January 2001. ADAMS Accession No. ML010430054.
    (3) SECY-00-0078, ``Status and Plans for Revising the Steam 
Generator Tube Integrity Regulatory Framework,'' March 30, 2000.
    (4) Draft Regulatory Guide 1.121, ``Bases for Plugging Degraded PWR 
Steam Generator tubes,'' August 1976.
    (5) Memorandum dated September 8, 1999, to W.H. Bateman, Chief, 
EMCB, NRR, NRC from J.W. Anderson, EMCB, NRR, NRC, ``Summary of August 
27, 1999, Senior Management Meeting with NEI/EPRI/Industry to Discuss 
Issues Involving Implementation of NEI 97-06.'' This memorandum 
encloses Industry White Paper entitled, ``Deterministic Structural 
Performance Criterion Pressure Loading Definition.''
    (6) Memorandum dated May 19, 2004, from J.L. Birmingham, Project 
Manager, NRR, NRC to Cathy Haney, Program Director, Policy and 
Rulemaking Program, Division of Regulatory Improvement Programs, NRR, 
NRC, ``Summary of May 14, 2004 Meeting with Nuclear Energy Institute 
(NEI) on Status of Steam Generator Structural Integrity Performance 
Criteria.'' ADAMS Accession No. ML041540500.
    (7) NUREG-1570, ``Risk Assessment of Severe Accident--Induced Steam 
Generator Tube Rupture,'' March 1998.
    (8) NUREG-1022, Rev 2, ``Event Reporting Guidelines 10 CFR 50.72 
and 50.73,'' October 31, 2000.\1\
---------------------------------------------------------------------------

    \1\ On September 24, 2004, a Federal Register notice (69 FR 
57367) was published noticing the issuance of an errata to Revision 
2 of NUREG-1022, ``Event Reporting Guidelines 10 CFR 50.72 and 
50.73.'' The errata indicates that steam generator tube degradation 
is considered serious if either of the two criteria specified in 
Section 3.2.4(A)(3) of NUREG-1022 (i.e., the structural and accident 
leakage performance criteria), Revision 2, are not satisfied.
---------------------------------------------------------------------------

    (9) NUREG-1649, Rev 3, ``Reactor Oversight Process,'' July 2000.

5.0 State Consultation

    In accordance with the Commission's regulations, the [ ] State 
official was notified of the proposed issuance of the amendment. The 
State official had [(1) no comments or (2) the following comments--with 
subsequent disposition by the staff].

6.0 Environmental Consideration

    The amendments change a requirement with respect to the 
installation or use of a facility component located within the 
restricted area as defined in 10 CFR Part 20 and change surveillance 
requirements. The NRC staff has determined that the amendments involve 
no significant increase in the amounts and no significant change in the 
types of any effluents that may be released offsite, and that there is 
no significant increase in individual or cumulative occupational 
radiation exposure. The Commission has previously issued a proposed 
finding that the amendments involve no significant hazards 
consideration, and there has been no public comment on such finding 
(FR). Accordingly, the amendments meet the eligibility criteria for 
categorical exclusion set forth in 10 CFR 51.22(c)(9). Pursuant to 10 
CFR 51.22(b) no environmental impact statement or environmental 
assessment need be prepared in connection with the issuance of the 
amendments.

7.0 Conclusion

    The Commission has concluded, based on the considerations discussed 
above, that (1) there is reasonable assurance that the health and 
safety of the public will not be endangered by operation in the 
proposed manner, (2) such activities will be conducted in compliance 
with the Commission's regulations, and (3) the issuance of the 
amendments will not be inimical to the common defense and security or 
to the health and safety of the public.

Model No Significant Hazards Consideration Determination

    Description of Amendment Request: The proposed amendment revises TS 
1.1, Definitions, TS 3.4.13, RCS Operational LEAKAGE, TS 5.5.9, Steam 
Generator Tube Surveillance Program, and TS 5.6.9, Steam Generator Tube 
Inspection Report, and adds a new specification for Steam Generator 
Tube Integrity. The proposed changes are necessary in order to 
implement the guidance for the industry initiative on NEI 97-06, 
``Steam Generator Program Guidelines.'' The licensee has evaluated 
whether or not a significant hazards consideration is involved with the 
proposed changes by focusing on the three standards set forth in 10 CFR 
50.92, ``Issuance of Amendment,'' as discussed below:
    Basis for proposed no significant hazards consideration 
determination: As required by 10 CFR 50.91(a), an analysis of the issue 
of no significant hazards consideration is presented below:

Criterion 1--The Proposed Change Does Not Involve a Significant 
Increase in the Probability or Consequences of an Accident Previously 
Evaluated

    The proposed change requires a SG Program that includes performance 
criteria that will provide reasonable assurance that the SG tubing will 
retain integrity over the full range of operating conditions (including 
startup, operation in the power range, hot standby, cooldown and all 
anticipated transients included in the design specification). The SG 
performance criteria are based on tube structural integrity, accident 
induced leakage, and operational LEAKAGE.
    A SGTR event is one 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

[[Page 10312]]

equal to the operational LEAKAGE rate limits in the licensing basis 
plus the LEAKAGE rate associated with a double-ended rupture of a 
single tube is assumed.
    For other design basis accidents such as MSLB, rod ejection, and 
reactor coolant pump locked rotor the tubes are assumed to retain their 
structural integrity (i.e., they are assumed not to rupture). These 
analyses typically assume that primary to secondary LEAKAGE for all SGs 
is 1 gallon per minute or increases to 1 gallon per minute as a result 
of accident induced stresses. The accident induced leakage criterion 
introduced by the proposed changes accounts for tubes that may leak 
during design basis accidents. The accident induced leakage criterion 
limits this leakage to no more than the value assumed in the accident 
analysis.
    The SG performance criteria proposed change to the TS identify the 
standards against which tube integrity is to be measured. Meeting the 
performance criteria provides reasonable assurance that the SG tubing 
will remain capable of fulfilling its specific safety function of 
maintaining reactor coolant pressure boundary integrity throughout each 
operating cycle and in the unlikely event of a design basis accident. 
The performance criteria are only a part of the SG Program required by 
the proposed change to the TS. The program, defined by NEI 97-06, Steam 
Generator Program Guidelines, includes a framework that incorporates a 
balance of prevention, inspection, evaluation, repair, and leakage 
monitoring. The proposed changes do not, therefore, significantly 
increase the probability of an accident previously evaluated.
    The consequences of design basis accidents are, in part, functions 
of the DOSE EQUIVALENT 1-131 in the primary coolant and the primary to 
secondary LEAKAGE rates resulting from an accident. Therefore, limits 
are included in the plant technical specifications for operational 
leakage and for DOSE EQUIVALENT 1-131 in primary coolant to ensure the 
plant is operated within its analyzed condition. The typical analysis 
of the limiting design basis accident assumes that primary to secondary 
leak rate after the accident is 1 gallon per minute with no more than 
[500 gallons per day or 720 gallons per day] in any one SG, and that 
the reactor coolant activity levels of DOSE EQUIVALENT 1-131 are at the 
TS values before the accident.
    The proposed change does not affect the design of the SGs, their 
method of operation, or primary coolant chemistry controls. The 
proposed approach updates the current TSs and enhances the requirements 
for SG inspections. The proposed change does not adversely impact any 
other previously evaluated design basis accident and is an improvement 
over the current TSs.
    Therefore, the proposed change does not affect the consequences of 
a SGTR accident and the probability of such an accident is reduced. In 
addition, the proposed changes do not affect the consequences of an 
MSLB, rod ejection, or a reactor coolant pump locked rotor event, or 
other previously evaluated accident.

Criterion 2--The Proposed Change Does Not Create the Possibility of a 
New or Different Kind of Accident From Any Previously Evaluated

    The proposed performance based requirements are an improvement over 
the requirements imposed by the current technical specifications. 
Implementation of the proposed SG Program will not introduce any 
adverse changes to the plant design basis or postulated accidents 
resulting from potential tube degradation. The result of the 
implementation of the SG Program will be an enhancement of SG tube 
performance. Primary to secondary LEAKAGE that may be experienced 
during all plant conditions will be monitored to ensure it remains 
within current accident analysis assumptions.
    The proposed change does not affect the design of the SGs, their 
method of operation, or primary or secondary coolant chemistry 
controls. In addition, the proposed change does not impact any other 
plant system or component. The change enhances SG inspection 
requirements.
    Therefore, the proposed change does not create the possibility of a 
new or different type of accident from any accident previously 
evaluated.

Criterion 3--The Proposed Change Does Not Involve a Significant 
Reduction in the Margin of Safety

    The SG tubes in pressurized water reactors are an integral part of 
the reactor coolant pressure boundary and, as such, are relied upon to 
maintain the primary system's pressure and inventory. As part of the 
reactor coolant pressure boundary, 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. In addition, the SG tubes isolate the radioactive 
fission products in the primary coolant from the secondary system. In 
summary, the safety function of an SG is maintained by ensuring the 
integrity of its tubes.
    Steam generator tube integrity is a function of the design, 
environment, and the physical condition of the tube. The proposed 
change does not affect tube design or operating environment. The 
proposed change is expected to result in an improvement in the tube 
integrity by implementing the SG Program to manage SG tube inspection, 
assessment, repair, and plugging. The requirements established by the 
SG Program are consistent with those in the applicable design codes and 
standards and are an improvement over the requirements in the current 
TSs.
    For the above reasons, the margin of safety is not changed and 
overall plant safety will be enhanced by the proposed change to the TS.
    Based upon the reasoning presented above and the previous 
discussion of the amendment request, the requested change does not 
involve a significant hazards consideration.


    Dated at Rockville, Maryland, this 22nd day of February 2005.

    For the Nuclear Regulatory Commission.
Thomas H. Boyce,
Section Chief, Technical Specifications Section, Operating Improvements 
Branch, Division of Inspection Program Management, Office of Nuclear 
Reactor Regulation.
[FR Doc. 05-3866 Filed 3-1-05; 8:45 am]
BILLING CODE 7590-01-P