Text

TSTF-449, Revision 2, Steam Generator Tube Integrity.
	ML042880287
Person / Time
Issue date:	10/07/2004
From:	Buschbaum D, Furio P, Infanger P, Morris B; BWR Owners Group, Technical Specifications Task Force, Westinghouse Owners Group
To:	Boyce T; NRC/NRR/DIPM
References
	TSTF-04-13 TSTF-449, Rev 2, WOG-169, Rev 0
	Download: ML042880287 (101)
	v • d • e

TECI-INICAL SPECIFICATIONS TASK FOR1CE TSTFF A IOIST 0 MWFRS GIOWA, GIVITY October 7, 2004 TSTF 13 Thomas 11. Boyce, Section Chief Technical Specifications Section Reactor Operations Branch Division of Inspection Program Management Office of Nuclear Reactor Regulation U.S. Nuclear Regulatory Commission Washington, DC 20555-0001

SUBJECT:

TSTF-449, Revision 2, "Steam Generator Tube Integrity"

Dear Mr. Boyce:

Enclosed for NRC consideration is Technical Specification Task Force Traveler TSTF-449, Revision 2, "Steam Generator Tube Integrity." This revision incorporates changes made to respond to the NRC's Requests for Additional Information on the Catawba lead plant submittal for this issue. This Traveler revision was developed in cooperation with the NEI Steam Generator Task Force. Please provide any future correspondence regarding this Traveler to the TSTF and please provide a copy to Mr. Jim Riley of NEI.

We request that NRC review of the Traveler continue to be granted a fee waiver pursuant to the provisions of 10 CFR 170.11. Specifically, the request is to support NRC generic regulatory improvements (steam generator tube integrity), in accordance with 10 CFR 170.1 1(a)(1)(iii).

This request is consistent with the NRC letter to A. R. Pietrangelo on this subject dated January 10, 2003.

Should you have any questions, please do not hesitate to contact us.

Qua~X R i p~ M ohA;:,

Dennis Buschbaum (WOG) Bert Morris (BWROG)

Patricia Furio (CEOG) pa Infang Paul WBWOG) Pont Enclosure cc: J. Riley, NEI /La: oX01.4 SC, NRC Document Control Desk 11921 Rockville Pike, Suite 100, Rockville, MD 20852 [ew~ou Phone: 301-984-4400, Fax: 301-984-7600 The BW OWNERS'GROUP Owners Group Email: tstf@excelservices.com Administered by EXCEL Services Corporation ki

NII VOG-169, Rev. 0 TSTF449, Rev. 2 A Techlnical Specification Task Force Improved Standard Technical Specifications Change Traveler Steam Generator Tube Integrity NUREGsAffected: [/ 1430 R./ 1431 i, 1432 0l 1433 0 1434 Classification: 1) Technical Change Recommended for CLIIP?: Yes Correction or Improvement: Improvement NRC Fee Status: Exempt Industry

Contact:

Denny Buschbaum, (254) 897-5851, dbuschbl txu.com See attached justification.

Revision History OG Revision 0 Revision Status: Closed Revision Proposed by: NEI SG Task Force Revision

Description:

Original Issue Owners Group Review Information Date Originated by OG: 10-Feb-03 Owners Group Comments:

Distributed to WOG core group and NEI Steam Generator Task Force.

Owners Group Resolution: Approved Date: 03-Mar-03 TSTF Review Information TSTF Received Date: 04-Mar-03 Date Distributed for Review: 04-Mar-03 OG Review Completed: 7R; BWOG i; WOG WJ CEOG W, BWROG TSTF Comments:

(No Comments)

TSTF Resolution: Approved Date: 12-Mar-03 NRC Review Information NRC Received Date: 17-Mar-03 NRC Comments:

Revised based on RAls received on Catawba lead plant submittal.

Final Resolution: NRC Requests Changes: TSTF Will Revise TSTF Revision 1 Revision Status: Closed Revision Proposed by: NEI SG Task Force 07-Oct-04 Traveler Rev. 3. Copyright (C) 2004, EXCEL Services Corporation. Use by EXCEL Services associates, utility clients, and the U.S. Nuclear Regulatory Commission is granted. All other use without written permission is prohibited.

NN'OG-169, Rev. 0 TSTF-449, Rev. 2 WOG-169, Rev. 0 TSTF-449, Rev. 2 TSTF Revision I Revision Status: Closed Revision

Description:

Catawba Nuclear Station is the lead plant for the changes in the Traveler. The Catawba submittal was made on February 25, 2003. The NRC responded with Requests for Additional Information (RAls) on April 30, May 29, and July 21, 2003. A revised Catawba submittal was transmitted on June 9, 2003 and a further revision was submitted on July 30, 2003. This revision of TSTF-449 incorporates the applicable changes made in the Catawba submittal as a result of the RAIs.

The specific changes are:

I) The Bases of the RCS loop specifications (3.4.4, 3.4.6, and 3.4.7) are revised to not state that a SG is OPERABLE "in accordance with the Steam Generator Tube Surveillance Program." In order for a SG to be OPERABLE, it must be capable of performing its safety function. SG tube integrity (required for RCS boundary integrity) is one important aspect of SG OPERABILITY, but is not the only aspect. Primary and secondary side water level, the ability to pressurize the system, instrumentation and controls and other design and performance requirements are also necessary. Therefore, the Bases are revised to state that the SG must be OPERABLE. The requirements for OPERABILITY are not explicitly described and are left to the definition of OPERABILITY.

This is consistent with the treatment of Reactor Coolant Pumps in the same sentence.

2) All references to repairing SG tubes which satisfy the tube repair criteria are bracketed. If tube repair methods have been approved for a particular plant, the material in the brackets will be retained. For those plants without approved tube repair methods, the material is not incorporated in the plant-specific Specifications. In order to maintain consistent numbering in the 5.5.9 program, the optional section describing approved tube repair methods is moved to the end of the program.

3) SR 3.4.13.2 is revised. The Frequency is changed from "In accordance with the SG Program" to "72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months ." A Note is added which states, "Not required to be performed until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after establishment of steady state operation." This change is made in response to an NRC RAI stating that 10 CFR 50.36 requires the SR Frequency to be stated in the Technical Specifications. The Bases are revised to reflect the changes to the Specification.

4) The Steam Generator Tube Integrity Specification is revised based on the NRC RAls. Required Action A. l is revised to state, "Verify tube integrity of the affected tube(s) is maintained until the next inspection."

5) Specification 5.6.9 is revised to allow 180 days instead of 120 days to provide the report and to eliminate the threshold for submitting the report. The order of the required information is changed to list the plant-specific (e.g., bracketed) items last in order to maximize consistency.

6) Specification 5.5.9, Steam Generator Program, is revised in response to NRC RAIs:

a) The structural integrity performance criteria was revised to be consistent with the definition used in the Catawba submittal. For discussion of the differences between the Revision 0 and Revision I Traveler, see the Catawba RAI responses.

b) Paragraph c is revised to eliminate the phrase "prior to entry into MODE 4." This information is already contained in the referencing Specification.

c) The requirements for SG tube inspections is replaced in its entirety.

TSTF Review Information TSTF Received Date: 03-Jun-03 Date Distributed for Review: 27-Aug-93 OG Review Completed: ; BWOG tj WOG Fj CEOG F BWROG 07-Oct-04 Traveler Rev. 3. Copyright (C) 2004, EXCEL Services Corporation. Use by EXCEL Services associates, utility clients, and the U.S. Nuclear Regulatory Commission is granted. All other use without X Titten permission is prohibited.

WOG-169, Rev. 0 TSTF*449, Rev. 2 WOG-169, Rev. 0 TSTF-449, Rev. 2 TSTF Revision 1 Revision Status: Closed TSTF Comments:

TSTF to revise based on results of SGTF / NRC discussions on Structural Integrity criterion.

TSTF Resolution: Approved Date: 09-Sep-03 NRC Review Information NRC Received Date: 10-Sep-03 NRC Comments:

The NEI Steam Generator Task Force and the NRC agreed to changes to the Structural Integrity Performance Criteria and to include a definition of "collapse."

Final Resolution: Superceded by Revision TSTF Revision 2 Revision Status: Active Revision Proposed by: NEI SG Task Force Revision

Description:

The NEI Steam Generator Task Force and the NRC worked to resolve issues regarding the Structural Integrity Performance Criteria (SIPC). The proposed Steam Generator Program in the TS Administrative Controls has been revised to reflect the new definition. In addition, the LCO Bases of the Steam Generator Tube Integrity Specification have been revised to incorporate a definition of "collapse" based on an NRC recommendation. Also a definition of what constitutes "significant" loads and a discussion of the treatment of thermal loads ssas added to the LCO Bases. The justification has been revised to discuss these changes.

The references are revised to eliminate the specific EPRI technical report numbers. These numbers change with each revision, but the titles remain the same. Therefore, the document titles are the appropriate reference to the latest version of the documents.

TSTF Review Information TSTF Received Date: 10-Sep-04 Date Distributed for Review: 10-Sep-04 OG Review Completed: F. BWOG i WOG 57 CEOG i BWROG TSTF Comments:

(No Comments)

TSTF Resolution: Approved Date: 07-Oct-04 NRC Review Information NRC Received Date: 07-Oct-04 Affected Technical Splecifications LCO 3.4.5 Bases RCS Loops - MODE 3 NUREG(s)- 1430 1431 1432 Only 07-Oct-04 Traveler Rev. 3. Copyright (C) 2004, EXCEL Services Corporation. Use by EXCEL Services associates, utility clients, and the U.S. Nuclear Regulatory Commission is granted. All other use without written permission is prohibited.

NVOG-169, Rev. 0 TSTF449, Rev. 2 WOG-169, Rev. 0 TSTF-449, Rev. 2 LCO 3.4.6 Bases RCS Loops - MODE 4 NUREG(s)- 1430 1431 1432 Only LCO 3.4.7 Bases RCS Loops - MODE 5, Loops Filled NUREG(s}- 1430 1431 1432 Only Bkgnd 3.4.13 Bases RCS Operational LEAKAGE NUREG(s)- 1430 1431 1432 Only S/A 3.4.13 Bases RCS Operational LEAKAGE NUREG(s)- 1430 1431 1432 Only LCO 3.4.13 RCS Operational LEAKAGE NUREG(s)- 1430 1431 1432 Only LCO 3.4.13 Bases RCS Operational LEAKAGE NUREG(s)- 1430 1431 1432 Only Ref. 3.4.13 Bases RCS Operational LEAKAGE NUREG(s) 1430 1431 1432 Only Action 3.4.13A RCS Operational LEAKAGE NUREG(s)- 1430 1431 1432 Only Action 3.4.13A Bases RCS Operational LEAKAGE NUREG(s) 1430 1431 1432 Only Action 3.4.13.B RCS Operational LEAKAGE NUREG(s)- 1430 1431 1432 Only Action 3.4.13.B Bases RCS Operational LEAKAGE NUREG(s)- 1430 1431 1432 Only SR 3.4.13.1 RCS Operational LEAKAGE NUREG(s)- 1430 1431 1432 Only SR 3.4.13.1 Bases RCS Operational LEAKAGE NUREG(s)- 1430 1431 1432 Only SR 3.4.13.2 RCS Operational LEAKAGE NUREG(s)- 1430 1431 1432 Only SR 3.4.13.2 Bases RCS Operational LEAKAGE NUREG(s) 1430 1431 1432 Only 5.5.9 Steam Generator Tube Surveillance Program NUREG(s)- 1430 1431 1432 Only Change

Description:

Renamed Steam Generator Program 5.6.9 Steam Generator Tube Inspection Report NUREG(s)- 1430 1431 1432 Only 3.4.17 SG Tube Integrity NUREG(s) 1430 Only Change

Description:

New specification 3.4.17 Bases SG Tube Integrity NUREG(s)- 1430 Only Change

Description:

New specification LCO 3.4.4 Bases RCS Loops - MODES 1 and 2 NUREG(s) 1431 1432 Only 3.4.18 SG Tube Integrity NUREG(s)- 1431 Only Change

Description:

New specification 3.4.18 Bases SG Tube Integrity NUREG(s) 1431 Only Change

Description:

New specification 3.4.20 SG Tube Integrity NUREG(s)- 1432 Only Change

Description:

New specification 07-Oct-04 Traveler Rev. 3. Copyright (C) 2004, EXCEL Services Corporation. Use by EXCEL Services associates, utility clients, and the U.S. Nuclear Regulatory Commission is granted. All other use without written permission is prohibited.

'OG-169, Rev. 0 TSTF-449, Rev. 2 3.4.20 Bases SG Tube Integrity NUREG(s)- 1432 Only Change

Description:

New specification 07-Oct-04 Traveler Rev. 3. Copyright (C) 2004, EXCEL Services Corporation. Use by EXCEL Services associates, utility clients, and the U.S. Nuclear Regulatory Commission is granted. All other use without rTitten permission is prohibited.

TSTF-449, Rev. 2

1.0 DESCRIPTION

The proposed change revises the Improved Standard Technical Specification (ISTS), NUREGs 1430, 1431, and 1432, Specification 3.4.13, "RCS Operational LEAKAGE," Specification 5.5.9, "Steam Generator Tube Surveillance Program, and Specification 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," (Reference 1).

2.0 PROPOSED CHANGE

The proposed change will:

Revise Technical Specification 3.4.13, "RCS Operational LEAKAGE" The proposed change revises TS 3.4.13, 'RCS Operational LEAKAGE," by reducing the allowable leakage from any one steam generator (SG) to 150 gallons per day. The proposed change also deletes the existing LCO 3.4.13.d since it is enveloped by the revised LCO and revises the Conditions and Surveillances to clarify the requirements related to primary to secondary LEAKAGE.

SR 3.4.13.2 is changed from verifying SG tube integrity to requiring verification that primary to secondary LEAKAGE iswithin limit. SG tube integrity is verified under a new LCO. A new Note is added to SR 3.4.13.1 to indicate that this surveillance in not applicable to primary to secondary LEAKAGE. A Note is added to SR 3.4.13.2 stating that the SR is not required to be performed until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after establishment of stable plant conditions. This is consistent with the existing Note on SR 3.4.13.1. Additionally, for NUREG-1431, changes to SR 3.4.13.1 are shown to emphasize the correct incorporation of TSTF-116, Rev. 2.

TS Bases changes are made to reflect the changes proposed to the Technical Specifications.

Revise Technical Specification 5.5.9, "Steam Generator Tube Surveillance Program" The proposed change revises TS 5.5.9, "Steam Generator Tube Surveillance Program," to delete the Reviewer's Note and to require a Steam Generator Program to be established and implemented to ensure that SG tube integrity is maintained, and to describe SG condition monitoring, performance criteria, repair methods, repair criteria, and inspection intervals. The title of TS 5.5.9 is revised from Steam Generator Tube Surveillance Program to Steam Generator Program.

Revise Technical Specification 5.6.9, "Steam Generator Tube Inspection Report" The proposed change to TS 5.6.9, "Steam Generator Tube Inspection Report," deletes the Reviewer's Note and provides the requirements for and contents of the SG tube inspection report.

The reporting requirements are revised to require a report within 180 days of initial entry into MODE 4 following a steam generator inspection.

Page 1 of 25

TSTF-449, Rev. 2

Add a Steam Generator Tube Integrity Specification The proposed change adds a new Technical Specification entitled "Steam Generator Tube Integrity," and associated Bases. The proposed Specification 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.

Revises the TS Bases for Specifications 3.4.4, 3.4.5, 3.4.6, and 3.4.7 The TS Bases for NUREG-1431 and NUREG-1432, Specification 3.4.4, 'RCS Loops - MODES 1 and 2," and NUREG-1431, -1432, and 1433, Specification 3.4.5, "RCS Loops - MODE 3," 3.4.6,

'RCS Loops - MODE 4," and 3.4.7, 'RCS Loops - MODE 5, Loops Filled," are revised to eliminate the reference to the Steam Generator Tube Surveillance Program as the method of establishing Steam Generator OPERABILITY.

3.0 BACKGROUND

The SG tubes in pressurized water reactors have a number of important safety functions. Steam generator tubes are an integral part of the reactor coolant pressure boundary (RCPB) and, as such, are relied upon to maintain the primary system's pressure and inventory. As part of the RCPB, the SG tubes are unique in that they act as a heat transfer surface between the primary and secondary systems to remove heat from the primary system. In addition, the SG tubes also isolate the radioactive fission products in the primary coolant from the secondary system.

Steam generator tube integrity is necessary in order to satisfy the tubing's safety functions.

Maintaining tube integrity ensures that the tubes are capable of performing their intended safety functions consistent with the plant licensing basis, including applicable regulatory requirements.

Concerns relating to the integrity of the tubing stem from the fact that the SG tubing is subject to a variety of degradation mechanisms. Steam generator tubes have experienced tube degradation related to corrosion phenomena, such as wastage, pitting, intergranular attack, and stress corrosion cracking, along with other mechanically induced phenomena such as denting and wear. These degradation mechanisms can impair tube integrity if they are not managed effectively. When the degradation of the tube wall reaches a prescribed repair criterion, the tube is considered defective and corrective action is taken.

The criteria governing structural integrity of SG tubes were developed in the 1970s and assumed uniform tube wall thinning. This led to the establishment of a through wall SG tube repair criteria (e.g.

40 percent) that has historically been incorporated into most pressurized water reactor (PWR)

Technical Specifications and has been applied, in the absence of other repair criteria, to all forms of SG tube degradation where sizing techniques are available. Since the basis of the through wall depth criterion was 3600 wastage, it is generally considered to be conservative for other mechanisms of SG tube degradation. The repair criterion does not allow licensees the flexibility to manage different types of SG tube degradation. Licensees must either use the through wall criterion for all forms of degradation or obtain approval for use of more appropriate repair criteria that consider the structural integrity implications of the given mechanism.

For the last several years, the industry, through the Electric Power Research Institute (EPRI) Steam Generator Management Program (SGMP), has developed a generic approach to improving SG performance referred to as 'Steam Generator Degradation Specific Management" (SGDSM). Under this approach, different methods of inspection and different repair criteria may be developed for Page 2 of 25

TSTF-449, Rev. 2 different types of degradation. A degradation specific approach to managing SG tube integrity has several important benefits. These include:

improved scope and methods for SG inspection,

industry incentive to continue to improve inspection methods, and

development of plugging and repair criteria based on appropriate NDE parameters.

As a result, the assurance of SG tube integrity is improved and unnecessary conservatism is eliminated.

Over the course of this effort, the SGMP has developed a series of EPRI guidelines that define the elements of a successful SG Program. These guidelines include:

'Steam Generator Examination Guideline" (Reference 2),

"Steam Generator Integrity Assessment Guideline' (Reference 3),

"In-situ Pressure Testing Guideline" (Reference 4),

"PWR Primary-to-Secondary Leak Guideline" (Reference 5),

"Primary Water Chemistry Guideline" (Reference 6), and

"Secondary Water Chemistry Guideline' (Reference 7).

These EPRI Guidelines, along with NEI 97-06 (Ref. 1), tie the entire Steam Generator Program together, while defining a comprehensive, performance based approach to managing SG performance.

In parallel with the industry efforts, the NRC pursued resolution of SG performance issues. In December of 1998, the NRC Staff acknowledged that the Steam Generator Program described by NEI 97-06 (Ref. 1)and its referenced EPRI Guidelines provides an acceptable starting point to use in the resolution of differences between it and the staffs proposed Generic Letter and draft Regulatory Guide (DG-1 074). Since then the industry and the NRC have participated in a series of meetings to resolve the differences and develop the regulatory framework necessary to implement a comprehensive Steam Generator Program.

Revising the existing regulatory framework to accommodate degradation specific management is the most appropriate way to address the issues of regulatory stability, resource expenditure, use of state-of-the-art inservice inspection techniques, repair criteria, and enforceability. The NRC Staff has stated that an integrated approach for addressing SG tube integrity is essential and that materials, systems, and radiological issues that pertain to tube integrity need to be considered in the development of the new regulatory framework.

4.0 TECHNICAL ANALYSIS

The proposed changes do not affect the design of the SGs, their method of operation, or primary coolant chemistry controls. The primary coolant activity limit and its assumptions are not affected by the proposed changes to the standard technical specifications. The proposed changes are an improvement to the existing SG inspection requirements and provide additional assurance that the plant licensing basis will be maintained between SG inspections.

A steam generator tube rupture (SGTR) event is one of the design basis accidents that are analyzed as part of a plant's licensing basis. The analysis of a SGTR event assumes a bounding primary to Page 3 of 25

TSTF-449, Rev. 2 secondary LEAKAGE rate 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.

For design basis accidents such as main steam line break (MSLB), rod ejection, and reactor coolant pump locked rotor, the SG 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. For accidents that do not involve fuel damage, the reactor coolant activity levels are at the technical specification values. For accidents that do involve fuel damage, the primary coolant activity values are a function of the amount of activity released from the damaged fuel.

The consequences of these design basis accidents are, in part, functions of the radioactivity levels in the primary coolant and the accident primary to secondary LEAKAGE rates. As a result, 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 proposed technical specification change includes a reduction in the current technical specification RCS operational LEAKAGE limit. The limit of 150 gallons per day of primary to secondary LEAKAGE through any one SG is based on operating experience as an indication of one or more tube leaks.

The operational leakage rate criterion in conjunction with the implementation of the Steam Generator Program is an effective measure for minimizing the frequency of steam generator tube ruptures.

The other technical specification changes proposed are in general a significant improvement over current requirements. They replace an outdated prescriptive technical specification with one that references Steam Generator Program requirements that incorporate the latest knowledge of SG tube degradation morphologies and the techniques developed to manage them.

The requirements being proposed are more effective in detecting SG degradation and prescribing corrective actions than required by current technical specifications. As a result, these proposed changes will result in added assurance of the function and integrity of SG tubes.

The table below and associated sections describe in detail and provide the technical justification for the proposed changes.

Page 4 of 25

TSTF-449, Rev. 2 Condition or Requirement Current Licensing Basis Location - Proposed Change Section Operational primary to secondary <1 gpm total through all SGs and < [720] or RCS Oper. LEAKAGE TS

150 gallons 1 LEAKAGE [500] gallons per day through any one SG per day through any one SG RCS primary to secondary LEAKAGE Reduce LEAKAGE to within limits in 4 RCS Oper. LEAKAGE TS - Be in 2 through any one SG not within limits hours or be in MODE 3 in 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in MODE 3 in 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in MODE 5 in MODE 5 in 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months RCS LEAKAGE determined by water Note states: Not required to be performed RCS Oper. LEAKAGE TS new Notes: 3 inventory balance (SR 3.4.13.1) until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after establishment of steady state operation 1. Made editorial change to NOTE in NUREG-1431 to show correct incorporation to TSTF-1 16, Rev. 2.

2. Added new Note indicating SR not applicable to primary to secondary LEAKAGE.

SG Tube integrity verification (SR 3.4.13.2) Verify in accordance with the SG Tube RCS Oper. LEAKAGE TS: 4 Surveillance Program Revised the SR to verify primary to secondary LEAKAGE every 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months .

Added Note stating "Not required to be performed until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after establishment of steady state operation.'

Frequency of verification of tube integrity 6to 40 months depending on SG category SG Tube Integrity TS - Requires 5 defined by previous inspection results. Surveillance Frequency in accordance with TS 5.5.9, Steam Generator Program. Frequency is dependent on tubing material and the previous inspection results and the anticipated defect growth rate.

Steam Generator Program -

Establishes maximum inspection intervals Page 5 of 25

TSTF-449, Rev. 2 Condition or Requirement Current Licensing Basis Location - Proposed Change Section Tube sample selection Based on SG Category, industry Steam Generator Program and 6 experience, random selection, existing implementing procedures - Dependent indications, and results of the initial sample on a pre-outage evaluation of actual set - 3% times the number of SGs at the degradation locations and mechanisms, plant as a minimum and operating experience - 20% of all tubes as a minimum.

Inspection techniques Not specified SG Tube Integrity TS - SR 3.4.20.1 7 requires that tube integrity be verified in accordance with the Steam Generator Program.

Steam Generator Program and implementing procedures - Establishes requirements for qualifying NDE techniques. Requires use of qualified techniques in SG inspections. Requires a pre-outage evaluation of potential tube degradation morphologies and locations and an identification of NDE techniques capable of finding the degradation.

Inspection Scope Hot leg point of entry to (typically) the first Steam Generator Program procedures support plate on the cold leg side of the U- - Inspection scope is defined by the bend degradation assessment that considers existing and potential degradation morphologies and locations. Explicitly requires consideration of entire length of tube from tube-sheet weld to tube-sheet weld.

Page 6 of 25

TSTF-449, Rev. 2 Condition or Requirement I Current Licensing Basis Location - Proposed Change Section Performance criteria Operational LEAKAGE < 1 gpm total or < RCS Oper. LEAKAGE TS - Operational 9

[720] or [500] gallons per day through any leakage

150 gallons per day through one SG. any one SG.

No criteria specified for structural integrity SG Tube Integrity TS - Requires that or accident induced leakage. tube integrity be maintained.

TS 5.5.9 - Defines structural integrity and accident induced leakage performance criteria which are dependent on design basis limits.

Provides provisions for condition monitoring assessment to verify compliance.

Repair criteria Plug or repair tubes with imperfections TS 5.5.9 -Criteria unchanged extending [>40%] through wall and alternate criteria approved by NRC and through wall depth based criteria for repair techniques approved by the NRC.

Approved alternate repair criteria listed in the Technical Specification.

ACTIONS Performance Criteria not defined. Primary RCS Oper. LEAKAGE TS and SG Tube I to secondary LEAKAGE limit and actions Integrity TS - Contains primary to included in the Tech Specs. secondary LEAKAGE limit, SG tube integrity requirements and ACTIONS Plug or repair tubes exceeding repair required upon failure to meet criteria. performance criteria.

Plug or repair tubes satisfying repair criteria.

Page 7 of 25

TSTF-449, Rev. 2 Condition or Requirement Current Licensing Basis Location - Proposed Change Section Repair methods Methods (except plugging) require previous TS 5.5.9 -Requirements unchanged 12 approval by the NRC. Approved methods listed in Technical Specification.

Reporting requirements [Plugging and repair report required 15 CFR - Serious SG tube degradation 13 days after each inservice inspection, 12 (i.e., tubing fails to meet the structural month report documenting inspection integrity and accident induced leakage results, and reports in accordance with criteria) requires reporting in

§50.72 when the inspection results fall into accordance with 50.72 or 50.73.

category C-3.]

TS 5.5.9 - 180 days after the initial entry into MODE 4 after performing a SG inspection Definitions SG Terminology Normal TS definitions (i.e., Definitions TS 5.5.9, TS Bases, Steam Generator 14 Section) did not address SG Program Program procedures - Includes Steam issues. Generator Program terminology Iapplicable only to SGs.

Page 8 of 25

TSTF-449, Rev. 2 Section 1: Operational LEAKAGE The primary to secondary LEAKAGE limit has been reduced to *150 gallons per day through any one SG. The operational leakage rate criterion in conjunction with the implementation of the Steam Generator Program is an effective measure for minimizing the frequency of steam generator tube ruptures. This 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 GDC 19 dose limits or other NRC approved licensing basis for postulated faulted events.

This limit also contributes to meeting the GDC 14 requirement that the reactor coolant pressure boundary 'have an extremely low probability of abnormal leakage, of rapidly propagating to failure, and of gross rupture." The proposed Surveillance references the Steam Generator Program. The Steam Generator Program uses the EPRI Primary-to-Secondary Leak Guideline (Ref. 5) to establish sampling requirements for determining primary to secondary LEAKAGE and plant shutdown requirements if leakage limits are exceeded. The guidelines ensure leakage is effectively monitored and timely action is taken before a leaking tube exceeds the performance criteria. The Frequency for determining primary to secondary LEAKAGE is unchanged (i.e., 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months and within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after establishing stable operating conditions).

The proposed revision to the technical specification requirement to limit primary to secondary LEAKAGE through any one SG to less than or equal to 150 gallons per day is significantly more conservative than the existing technical specification limit [1 gpm] total primary to secondary LEAKAGE through all SGs that is based on an initial condition of the safety analysis.

Section 2: Operational LEAKAGE Actions If primary to secondary LEAKAGE exceeds 150 gallons per day through any one SG, a plant shutdown must be commenced. MODE 3 must be achieved in 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and MODE 5 in 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months . The existing technical specifications allow 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months to reduce primary to secondary LEAKAGE to less than the limit. The proposed technical specification removes this allowance.

The removal of the 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months period during which primary to secondary LEAKAGE can be reduced to avoid a plant shutdown results in a technical specification that is significantly more conservative than the existing RCS Operational LEAKAGE specification. This change is consistent with the Steam Generator Program that also does not allow 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months before commencing a plant shutdown.

Section 3: RCS Operational LEAKAGE Determined by Water Inventory Balance The proposed change adds a second Note to SR 3.4.13.1 that makes the water inventory balance method not applicable to determining primary to secondary LEAKAGE. This change is proposed because primary to secondary LEAKAGE as low as 150 gallons per day through any one SG cannot be measured accurately by an RCS water inventory balance. This change is necessary to make the surveillance requirement appropriate for the proposed LCO.

Section 4: SG Tube Integrity Verification The current SR 3.4.13.2 requires verification of tube integrity in accordance with the SG Tube Surveillance Program. This surveillance is no longer appropriate since tube integrity is addressed through the addition of a new SG Tube Integrity Specification. Specification 3.4.13 now applies specifically to primary to secondary LEAKAGE. Surveillance Requirement 3.4.13.2 has been changed to verify the LCO requirement on primary to secondary LEAKAGE only. Steam generator tube integrity is verified in accordance with a SR in the SG Tube Integrity Specification.

Page 9 of 25

TSTF-449, Rev. 2 The Steam Generator Program and the EPRI 'Pressurized Water Reactor Primary-to-Secondary Leak Guidelines' (Ref. 5) provide guidance on leak rate monitoring. During normal operation the program depends upon continuous process radiation monitors and/or radiochemical grab sampling. The monitoring and sampling frequency increases as the amount of detected LEAKAGE increases or if there are no continuous radiation monitors available.

Primary to secondary LEAKAGE is determined through the analysis of secondary coolant activity levels. At low power, primary and secondary coolant activity is sufficiently low that an accurate determination of primary to secondary LEAKAGE may be difficult. Immediately after shutdown, some of the short lived isotopes are usually at sufficient levels to monitor for LEAKAGE by normal power operational means as long as other plant conditions allow the measurement. During startup, especially after a long outage, there are no short lived isotopes in either the primary or secondary system. This limits measurement of the LEAKAGE to chemical or long lived radiochemical means.

Because of these effects, an accurate primary to secondary leakage measurement is highly dependent upon plant conditions and may not be obtainable prior to reactor criticality (e.g., MODES I and 2). If SG water samples are less than the minimum detectable activity of [5.OE-7] microcuries/ml for each principal gamma emitter, the primary to secondary LEAKAGE surveillance requirements may be assumed to be met because at this low activity level the operator and off-site dose limits that are the basis for the operational leakage limit will not be exceeded..

The Surveillance Frequency is unchanged. Determination of the primary to secondary LEAKAGE is required every 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . The SR is modified by a Note stating the SR is not required to be performed until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after establishment of stable operating conditions. As stated above, additional monitoring of primary to secondary LEAKAGE is also required by the Steam Generator Program based upon guidance provided in Reference 5.

Section 5: Frequency of Verification of SG Tube Inteqrity The current technical specifications contain prescriptive inspection intervals which depend on the condition of the tubes as determined by the last SG inspection. The tube condition is classified into one of three categories based on the number of tubes found degraded and defective. The minimum inspection interval is no less than 12 and no more than 24 months unless the results of two consecutive inspections are in the best category (no additional degradation), and then the interval can be extended to 40 months.

The surveillance Frequency in the proposed Steam Generator Tube Integrity specification is governed by the requirements in the Steam Generator Program and specifically by References 2 and 3. The proposed Frequency is also prescriptive, but has a stronger engineering basis than the existing technical specification requirements. The interval is dependent on tubing material and whether any active degradation is found. The interval is limited by existing and potential degradation mechanisms and their anticipated growth rate. In addition, a maximum inspection interval is established in Specification 5.5.9.

The maximum inspection interval requirement for Alloy 600 mill annealed tubing (600MA) is 'Inspect 100% of the tubes at sequential periods of 60 effective full power months. The first sequential period shall be considered to begin after the first inservice inspection of the SGs. No SG shall operate for more than 24 effective full power months or one refueling outage (whichever is less) without being inspected." This Frequency is at least as conservative as the current technical specification requirement.

The maximum inspection interval for Alloy 600 thermally treated tubing is 'Inspect 100% of the tubes at sequential periods of 120, 90, and, thereafter, 60 effective full power months. The first sequential period shall be considered to begin after the first inservice inspection of the SGs. In addition, inspect Page 10 of 25

TSTF-449, Rev. 2 50% of the tubes by the refueling outage nearest the midpoint of the period and the remaining 50% by the refueling outage nearest the end of the period. No SG shall operate for more than 48 effective full power months or two refueling outages (whichever is less) without being inspected."

The maximum inspection interval for Alloy 690 thermally treated tubing is "Inspect 100% of the tubes at sequential periods of 144, 108, 72, and, thereafter, 60 effective full power months. The first sequential period shall be considered to begin after the first inservice inspection of the SGs. In addition, inspect 50% of the tubes by the refueling outage nearest the midpoint of the period and the remaining 50% by the refueling outage nearest the end of the period. No SG shall operate for more than 72 effective full power months or three refueling outages (whichever is less) without being inspected." Even though the maximum interval for Alloy 600 thermally treated tubing and Allow 690 thermally treated tubing is slightly longer than allowed by current technical specifications, it is only applicable to SGs with advanced materials, it is only achievable early in SG life and only if the SGs are free from active degradation. In addition, the interval must be supported by an evaluation that shows that the performance criteria will continue to be met at the next SG inspection. Taken in total, the proposed inspection intervals provide a larger margin of safety than the current requirements because they are based on an engineering evaluation of the tubing condition and potential degradation mechanisms and growth rates, not only on the previous inspection results. As an added safety measure, the Steam Generator Program requires a minimum sample size at each inspection that is significantly larger than that required by current technical specifications (20 percent versus 3 percent times the number of SGs in the plant); thus providing added assurance that any degradation within the SGs will be detected and accounted for in establishing the inspection interval.

The proposed maximum inspection intervals are based on the historical performance of advanced SG tubing materials. Reference 8 shows that the performance of Alloy 600TT and 690TT is significantly better than the performance of 600MA tubing, the material used in SG tubing at the time that the current technical specifications were written. There have been very few instances of cracking in 600TT tubes in a U.S. SG and this degradation appears to be limited to a small number of tubes in specific SGs that were left with high residual stress as a result of a problem in their manufacturing process. The mechanism is not a result of operational degradation. There are no known instances of cracking in 690TT tubes in either the U.S. or international SGs.

In summary, the proposed change is an improvement over the current technical specification. The current technical specification bases inspection intervals on the results of previous inspections; it does not require an evaluation of expected performance. The proposed technical specification uses information from previous plant inspections as well as industry experience to evaluate the length of time that the SGs can be operated and still provide reasonable assurance that the performance criteria will be met at the next inspection. The actual interval is the shorter of the evaluation results and the requirements in Reference 3. Allowing plants to use the proposed inspection intervals maximizes the potential that plants will use improved techniques and knowledge since better knowledge of SG conditions supports longer intervals.

Section 6: SG Tube Sample Selection The current technical specifications base tube selection on SG conditions and industry and plant experience. The minimum sample size is 3%of the tubes times the number of SGs in the plant. The proposed change refers to the Steam Generator Program degradation assessment guidance for sampling requirements. The minimum sample size is 20% of the tubes inspected.

The Steam Generator Program requires the preparation of a degradation assessment before every SG inspection. The degradation assessment is the key document used for planning a SG inspection, where inspection plans and related actions are determined, documented, and communicated prior to the outage. The degradation assessment addresses the various reactor coolant pressure boundary Page I Iof25

TSTF-449, Rev. 2 components within the SG (e.g., plugs, sleeves, tubes, and components that support the pressure boundary.) In a degradation assessment, tube sample selection is performance based and is dependent upon actual SG conditions and plant operational experience and of the industry in general.

Existing and potential degradation mechanisms and their locations are evaluated to determine which tubes will be inspected. Tube sample selection is adjusted to minimize the possibility that tube integrity might degrade during an operating cycle beyond the limits defined by the performance criteria. The EPRI Steam Generator Examination Guidelines (Ref. 2) and EPRI Steam Generator Integrity Assessment Guidelines (Ref. 3) provide guidance on degradation assessment.

In general, the sample selection considerations required by the current technical specifications and the requirements in the Steam Generator Program as proposed by this change are consistent, but the Steam Generator Program provides more guidance on selection methodologies and incorporation of industry experience and requires more extensive documentation of the results. Therefore the sample selection method proposed by this change is more conservative than the current technical specification requirements. In addition, the minimum sample size in the proposed requirements is larger.

Section 7: SG Inspection Techniques The Surveillance Requirements proposed in the Steam Generator Tube Integrity specification require that tube integrity be verified in accordance with the requirements of the Steam Generator Program.

The Steam Generator Program uses the EPRI Steam Generator Examination Guidelines (Ref. 2) to establish requirements for qualifying NDE techniques and maintains a list of qualified techniques and their capabilities.

The Steam Generator Program requires the performance of a degradation assessment before every SG inspection and refers utilities to EPRI Steam Generator Examination Guidelines (Ref. 2) and EPRI Steam Generator Integrity Assessment Guidelines (Ref. 3) for guidance on its performance. The degradation assessment will identify current and potential new degradation locations and mechanisms and NDE techniques that are effective in detecting their existence. Tube inspection techniques are chosen to reliably detect flaws that might progress during an operating cycle beyond the limits defined by the performance criteria.

The current technical specifications contain no requirements on NDE inspection techniques. The proposed change is an improvement over the current technical specifications that contained no similar requirement.

Section 8: SG Inspection Scone The current technical specifications include a definition of inspection that specifies the end points of the eddy current examination of each tube. Typically an inspection is required from the point of entry of the tube on the hot leg side to some point on the cold leg side of the tube, usually at the first tube support plate after the U-bend. This definition is overly prescriptive and simplistic and has led to interpretation questions in the past.

The Steam Generator Program states, 'The number and portions of the tubes inspected and methods of inspection shall be performed with the objective of detecting flaws of any type (e.g., 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 criteria. The tube-to-tubesheet weld is not part of the tube. In addition to meeting the requirements of d.1, d.2, and d.3 below, the inspection scope, inspection methods, and inspection intervals shall be such as to ensure that SG tube integrity is maintained until the next SG inspection. An assessment of degradation shall be performed to determine the type and Page 12 of 25

TSTF-449, Rev. 2 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 Steam Generator Program provides extensive guidance and a defined process, the degradation assessment, for determining the extent of a tube inspection. This guidance takes into account industry and plant specific history to determine potential degradation mechanisms and the location that they might occur within the SG. This information is used to define a performance based inspection scope targeted on plant specific conditions and SG design.

The proposed change is an improvement over the current technical specifications because it focuses the inspection effort on the areas of concern, thereby minimizing the unnecessary data that the NDE analyst must review to identify indication of tube degradation.

Section 9: SG Performance Criteria The proposed change adds a performance-based Steam Generator Program to the Technical Specifications. A performance-based approach has the following attributes:

measurable parameters,

objective criteria to assess performance based on risk-insights,

deterministic analysis-and/or performance history, and

licensee flexibility to determine how to meet established performance criteria.

The performance criteria used for SGs are based on tube structural integrity, accident induced leakage, and operational LEAKAGE. The structural integrity and accident induced leakage criteria were developed deterministically and are consistent with the plant's licensing basis. The operational LEAKAGE criterion was based on providing an effective measure for minimizing the frequency of tube ruptures at normal operating and faulted conditions. The proposed structural integrity and accident induced leakage performance criteria are new requirements. The performance criteria are specified in Specification 5.5.9. The requirements and methodologies established to meet the performance criteria are documented in the Steam Generator Program. The current technical specifications contain only the operational LEAKAGE criterion; therefore the proposed change is more conservative than the current requirements.

The SG performance criteria identify the standards against which performance 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 RCPB integrity throughout each operating cycle.

The structural integrity performance criterion is:

"Structural integrity performance criterion: All in-service steam generator tubes shall retain structural integrity over the full range of normal operating conditions (including startup, operation in the power range, hot standby, and cool down and all anticipated transients included in the design specification) and design basis accidents. This includes retaining 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 the design basis accident primary-to-secondary pressure differentials.

Apart from the above requirements, additional loading conditions associated with the 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 Page 13 of 25

TSTF-449, Rev. 2 with the loads due to pressure with a safety factor of 1.2 on the combined primary loads and 1.0 on axial secondary loads.

The structural integrity performance criterion is based on providing reasonable assurance that a SG tube will not burst during normal operation or postulated accident conditions.

Adjustments to include contributing loads are addressed in the applicable EPRI guidelines.

Normal steady state full power operation is defined as the conditions existing during MODE 1 operation at the maximum steady state reactor power as defined in the design or equipment specification. Changes in design parameters such as plugging or sleeving levels, primary or secondary modifications, or Thot should be assessed and included if significant.

The definition of normal steady state full power operation is important as it relates to application of the safety factor of three in the structural integrity performance criterion. The criterion requires

"...retaining a safety factor of 3.0 under normal steady state full power operation primary to secondary pressure differential...". The application of the safety factor of three to normal steady state full power operation is founded on past NRC positions, accepted industry practice, and the intent of the ASME Code for original design and evaluation of inservice components. The assumption of normal steady state full power operating pressure differential has been consistently used in the analysis, testing and verification of tubes with stress corrosion cracking for verifying a safety factor of three against burst.

Additionally, the 3AP criterion is measurable through the condition monitoring process.

The actual operational parameters may differ between cycles. As a result of changes to these parameters, reaching the differential pressure in the equipment specification may not be possible during plant operations. Evaluating to the pressure in the design or equipment specification in these cases would be an unnecessary conservatism. Therefore, the definition allows adjustment of the 3AP limit for changes in these parameters when necessary. Further guidance on this adjustment is provided in Appendix M of the EPRI Steam Generator Integrity Assessment Guidelines (Ref. 3).

The accident induced leakage performance criterion is:

"The primary to secondary accident induced leakage rate for all design basis accidents, other than a steam generator tube rupture, shall not exceed the leakage rate assumed in the accident analysis in terms of total leakage rate for all steam generators and leakage rate for an individual steam generator. Leakage is not to exceed [1 gpm] per SG, [except for specific types of degradation at specific locations where the NRC has approved greater accident-induced leakage as part of a plant's licensing basis. Exceptions to the

[1 gpm] limit can be applied if approved by the NRC in conjunction with approved alternate repair criteria]."

Primary to secondary LEAKAGE is a factor in the activity releases outside containment resulting from a limiting design basis accident. The potential dose consequences from primary to secondary LEAKAGE during postulated design basis accidents must not exceed the radiological limits imposed by 10 CFR Part 100 guidelines, or the radiological limits to control room personnel imposed by GDC-19, or other NRC approved licensing basis.

In most cases when calculating offsite doses, the safety analysis for the limiting Design Basis Accident, other than a steam generator tube rupture, assumes a total of 1 gpm primary to secondary LEAKAGE as an initial condition. Revision 2 of the Standard Technical Specifications limited the amount of RCS Operational LEAKAGE to 1 gpm from all SGs, with 500 or 720 gallons per day from the worst generator, since the initial safety analyses assumed that leakage under accident conditions would not exceed the limit on Operational LEAKAGE. More recent experience with degradation Page 14 of 25

TSTF-449, Rev. 2 mechanisms involving tube cracking has revealed that leakage under accident conditions can exceed the level of operating leakage by orders of magnitude. The NRC has concluded (Item Number 3.4 in Attachment I to Reference 14) that additional research is needed to develop an adequate methodology for fully predicting the effects of leakage on the outcome of some accident sequences.

Therefore, a separate performance criterion was established for accident induced leakage. The limit for accident induced leakage is 1 gpm or the plant's design basis, whichever is less, unless a greater leakage rate has been approved as part of an alternate repair criteria. Use of an increased accident induced leakage limit approved in conjunction with an alternate repair criteria is limited to the specific criteria and type of degradation for which it was granted.

The operational LEAKAGE performance criterion is:

'The RCS operational primary to secondary LEAKAGE through any one steam generator shall be limited to 150 gallons per day."

Plant shutdown will commence if primary to secondary LEAKAGE exceeds 150 gallons per day at room temperature conditions from any one SG.

The operational LEAKAGE performance criterion is documented in the Steam Generator Program and implemented in Specification 3.4.13, 'RCS Operational LEAKAGE."

Proposed Administrative Specification 5.5.9 contains the performance criteria and is more conservative than the current technical specifications. The current technical specifications do not address the structural integrity and accident induced leakage criteria. In addition, the primary to secondary LEAKAGE limit (150 gallons per day per SG) included in the proposed changes to Technical Specification 3.4.13, 'RCS Operational LEAKAGE," is more conservative than the primary to secondary LEAKAGE limit in the current RCS operational LEAKAGE specification.

Section 10: SG Repair Criteria Repair criteria are those NDE measured parameters at or beyond which the tube must be repaired or removed from service by plugging.

Tube repair criteria are established for each active degradation mechanism. Tube repair criteria are either the standard through-wall depth-based criterion (e.g., 40% through-wall for most plants) or through-wall depth based criteria for repair techniques approved by the NRC, or other Alternate Repair Criteria (ARC) approved by the NRC such as a voltage-based repair limit per Generic Letter 95-05 (Ref. 12). A SG degradation-specific management strategy is followed to develop and implement an ARC.

The surveillance requirements of the proposed Steam Generator Integrity specification require that tubes that satisfy the tube repair criteria be plugged or repaired in accordance with approved methods. SG tubes experiencing a damage form or mechanism for which no depth sizing capability exists are "repaired/plugged-on-detection" and their integrity should be assessed. It cannot be guaranteed that every flaw will be detected with a given eddy current technique and, therefore, it is possible that some flaws will not be detected during an inspection. If a flaw is discovered and it is determined that this flaw would have satisfied the repair criteria at the time of the last inspection of the affected tube, this does not mean that the Steam Generator Program was violated.

Any plant-specific alternate repair criteria approved for a licensee are listed in Technical Specification 5.5.9. These are the same criteria as existed under the pre-Improved Technical Specifications.

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TSTF-449, Rev. 2 Section 11: ACTIONS The RCS Operational LEAKAGE and Steam Generator Tube Integrity specifications require the licensee to monitor SG performance against performance criteria in accordance with the Steam Generator Program.

During plant operation, monitoring is performed using the operational LEAKAGE criterion. Exceeding that criterion will lead to a plant shutdown in accordance with Technical Specification 3.4.13. Once shutdown, the Steam Generator Program will ensure that the cause of the operational LEAKAGE is determined and corrective actions are taken to prevent recurrence. Operation may resume when the requirements of the Steam Generator Program have been met. This requirement is unchanged from the current technical specifications.

Also during plant operation the licensee may discover an error or omission that indicates a failure to implement a required plugging or repair during a previous SG inspection. Under these circumstances, the licensee is expected to take the actions required by Condition A in the Steam Generator Tube Integrity specification. If a performance criterion has been exceeded, a principal safety barrier has been challenged and 10 CFR 50.72 (b) (3) (ii) (A) and 50.73 (a) (2) (ii) (A) require NRC notification and the submittal of a report containing the cause and corrective actions to prevent recurrence. The Steam Generator Program additionally requires that the report contain information on the performance criteria exceeded and the basis for the planned operating cycle. The current technical specifications only address operational LEAKAGE during operations and therefore do not include the proposed requirement.

During MODES 5 and 6, the operational LEAKAGE criterion is not applicable, and the SGs will be inspected as required by the surveillance in the Steam Generator Tube Integrity specification. A condition monitoring assessment of the "as found' condition of the SG tubes will be performed to determine the condition of the SGs with respect to the structural integrity and accident leakage performance criteria. If the performance criteria are not met, the Steam Generator Program requires ascertaining the cause and determining corrective actions to prevent recurrence. Operation may resume when the requirements of the Steam Generator Program have been met.

The proposed technical specification's change to the ACTIONS required upon exceeding the operational leakage criterion is conservative with respect to the current technical specifications as explained in Section 2 above.

The current technical specifications do not address ACTIONS required while operating if it is discovered that the structural integrity or accident induced leakage performance criteria or a repair criterion are exceeded, so the proposed change is conservative with respect to the current technical specifications.

If performance or repair criteria are exceeded while shutdown, the affected tubes must be repaired or plugged. A report will be submitted to the NRC in accordance with Technical Specification 5.6.9.

The changes in the required reports are discussed in Section 13 below.

Section 12: SG Repair Methods Repair methods are those means used to reestablish the RCS pressure boundary integrity of SG tubes without removing the tube from service. Plugging a SG tube is not a repair.

The purpose of a repair is typically to reestablish or replace the RCPB. The proposed Steam Generator Tube Integrity surveillance requirements requires that tubes that satisfy the tube repair criteria be plugged or repaired in accordance with the Steam Generator Program. Repair methods Page 16 of 25

TSTF-449, Rev. 2 established in accordance with the Steam Generator Program are listed in Technical Specification 5.5.9 as in the current technical specifications.

Steam generator tubes experiencing a damage form or mechanism for which no depth sizing capability exists are 'repaired/plugged-on-detection" and their integrity is assessed. This requirement is unchanged by the proposed technical specifications.

Note that SG plug designs do not require NRC review and therefore plugging is not considered a repair in the context of this requirement.

The proposed approach is not a change to the technical specifications.

Section 13: Reporting Requirements The current technical specifications require the following reports:

A report listing the number of tubes plugged or repaired in each SG submitted within 15 days of the end of the inspection.

A SG inspection results report submitted within 12 months after the inspection.

Reports required pursuant to 10 CFR 50.73.

The proposed change to Technical Specification 5.6.9 replaces the 15 day and the SG inspection reports with one report required within 180 days. The proposed report also contains more information than the current SG inspection report. This provision expands the report to provide more substantive information will be sent earlier (180 days versus 12 months). This allows the NRC to focus its attention on the more significant conditions.

The guidance in NUREG-1 022, Rev. 2, 'Event Reporting Guidelines 10 CFR 50.72 and 50.73,"

identifies serious SG tube degradation as an example of an event or condition that results in the condition of the nuclear power plant, including its principal safety barriers, being seriously degraded.

Steam generator tube degradation is considered serious if the tubing fails to meet structural integrity accident induced leakage performance criteria. Serious SG tube degradation would be reportable in accordance with 10 CFR 50.72 (b)(3) (ii) (A) and 50.73 (a)(2) (ii) (A) requiring NRC notification and the submittal of a report containing the cause and corrective actions to prevent recurrence.

The proposed reporting requirements are an improvement as compared to those required by the current technical specifications. The proposed reporting requirements are more useful in identifying the degradation mechanisms and determining their effects. In the unlikely event that a performance criterion is not met, NEI 97-06 (Ref. 1)directs the licensee to submit additional information on the root cause of the condition and the basis for the next operating cycle.

The changes to the reporting requirements are performance based. The new requirements remove the burden of unnecessary reports from both the NRC and the licensee, while ensuring that critical information related to problems and significant tube degradation is reported more completely and, when required, more expeditiously than under the current technical specifications.

Section 14: SG Terminology The proposed Steam Generator Tube Integrity specification Bases explain a number of terms that are important to the function of a Steam Generator Program. The Technical Specification Bases are controlled by the Technical Specification Bases Control Program, which appears in the Administrative Technical Specifications.

The terms are described below.

Page 17 of 25

TSTF-449, Rev. 2

1. Accident induced leakage rate means the primary to secondary LEAKAGE rate occurring during postulated accidents other than a steam generator tube rupture. This includes the primary to secondary LEAKAGE rate existing immediately prior to the accident plus additional primary to secondary LEAKAGE induced during the accident.

Primary to secondary LEAKAGE is a factor in the dose releases outside containment resulting from a limiting design basis accident. The potential primary to secondary leak rate during postulated design basis accidents must not cause radiological dose consequences in excess of the 10 CFR Part 100 guidelines for offsite doses, or the GDC-1 9 requirements for control room personnel, or other NRC approved licensing basis.

2. The LCO section of Steam Generator Tube Integrity Bases define the term 'burst" as 'the gross structural failure of the tube wall. The condition typically corresponds to an unstable opening displacement (e.g., opening area increased in response to constant pressure) accompanied by ductile (plastic) tearing of the tube material at the ends of the degradation."

Since a burst definition is required for condition monitoring, a definition that can be analytically defined and is capable of being assessed via in situ and laboratory testing is necessary.

Furthermore, the definition must be consistent with ASME Code requirements, and apply to most forms of tube degradation.

The definition developed for tube burst is consistent with the testimony of James Knight (Ref. 9),

and the historical guidance of draft Regulatory Guide 1.121 (Ref. 10). The definition of burst per these documents is in relation to gross failure of the pressure boundary; e.g., 'the degree of loading required to burst or collapse a tube wall is consistent with the design margins in Section III of the ASME B&PV Code (Ref. 11)." Burst, or gross failure, according to the Code would be interpreted as a catastrophic failure of the pressure boundary.

The above definition of burst was chosen for a number of reasons:

The burst definition supports field application of the condition monitoring process. For example, verification of structural integrity during condition monitoring may be accomplished via in situ testing. Since these tests do not have the capability to provide an unlimited water supply, or the capability to maintain pressure under certain leakage scenarios, opening area may be more a function of fluid reservoir rather than tube strength. Additionally, in situ designs with bladders may not be reinforced. In certain cases, the bladder may rupture when tearing or extension of the defect has not occurred. This condition may simply mean the opening of the flanks of the defect was sufficient to permit extrusion of the bladder, and that the actual, or true, burst pressure was not achieved during the test. The burst definition addresses this issue.

The definition does not characterize local instability or 'ligament pop-through", as a burst.

The onset of ligament tearing need not coincide with the onset of a full burst. For example, an axial crack about 0.5" long with a uniform depth at 98% of the tube wall would be expected to fail the remaining ligament, (i.e., extend the crack tip in the radial direction) due to deformation during pressurization at a pressure below that required to cause extension at the tips in the axial direction. Thus, this would represent a leakage situation as opposed to a burst situation and a factor of safety of three against crack extension in the axial direction may still be demonstrated. Similar conditions have been observed for deep wear indications.

Page 18 of 25

TSTF-449, Rev. 2

3. The LCO section of Steam Generator Tube Integrity Bases define a SG tube as, 'the entire length of the tube, including the tube wall and any repairs to it, between the tube-to-tubesheet weld at the tube inlet and the tube-to-tubesheet weld at the tube outlet. The tube-to-tubesheet weld is not considered part of the tube."

This definition ensures that all portions of SG tubes that are part of the RCPB, with the exception of the tube-to-tubesheet weld, are subject to Steam Generator Program requirements. The definition is also intended to exclude tube ends that can not be NDE inspected by eddy current. If there are concerns in the area of the tube end, they will be addressed by NDE techniques if possible or by using other methods if necessary.

For the purposes of SG tube integrity inspection, any weld metal in the area of the tube end is not considered part of the tube. This is necessary since the acceptance requirements for tubing and weld metals are different.

4. The LCO section of Steam Generator Tube Integrity Bases define the term 'collapse" as 'For the load displacement curve for a given structure, collapse occurs at the top of the load versus displacement curve where the slope of the curve becomes zero."

In dealing with pure pressure loadings, burst is the only failure mechanism of interest. If bending loads are introduced in combination with pressure loading, the definition of failure must be broadened to encompass both burst and bending collapse. Which failure mode applies depends on the relative magnitude of the pressure and bending loads and also on the nature of any flaws that may be present in the tube. Guidance on assessing applicable failure modes is provided in the EPRI steam generator guidelines.

5. The LCO section of Steam Generator Tube Integrity Bases define the term 'significant" as used in the structural integrity performance criterion as "An accident loading condition other than differential pressure is considered significant when the addition of such loads in the assessment of the structural integrity performance criterion could cause a lower structural limit or limiting burst/collapse condition to be established."

6. The LCO section of Steam Generator Tube Integrity Bases describes how to determine whether thermal loads are primary or.secondary loads. For circumferential degradation, the classification of axial thermal loads as primary or secondary loads will be evaluated on a case-by-case basis.

The division between primary and secondary classifications will be based on detailed analysis and/or testing.

Conclusion The proposed changes will provide greater assurance of SG tube integrity than that offered by the current technical specifications. The proposed requirements are performance based and provide the flexibility to adopt new technology as it matures. These changes are consistent with the guidance in NEI 97-06, 'Steam Generator Program Guidelines," (Ref. 1).

Adopting the proposed changes will provide added assurance that SG tubing will remain capable of fulfilling its specific safety function of maintaining RCPB integrity.

Page 19 of 25

TSTF-449, Rev. 2

5.0 REGULATORY ANALYSIS

5.1 Nd Significant Hazards Consideration The proposed change revises the improved Standard Technical Specification (iSTS) Section 3.4.13,

'RCS Operational LEAKAGE," Section 5.5.9, 'Steam Generator Tube Surveillance Program, and Section 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, OSteam Generator Program Guidelines," (Reference 1). The TSTF has evaluated whether or not a significant hazards consideration is involved with the proposed generic change by focusing on the three standards set forth in 10 CFR 50.92, 'Issuance of amendment," as discussed below:

1. Does the proposed change involve a significant increase in the probability or consequences of an accident previously evaluated?

Response: No The proposed change requires a Steam Generator Program that includes performance criteria that will provide reasonable assurance that the steam generator (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.

The structural integrity performance criterion is:

Structural integrity performance criterion: All in-service steam generator tubes shall retain structural integrity over the full range of normal operating conditions (including startup, operation in the power range, hot standby, and cool down and all anticipated transients included in the design specification) and design basis accidents. This includes retaining 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 the design basis accident primary-to-secondary pressure differentials. Apart from the above requirements, additional loading conditions associated with the 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 pressure with a safety factor of 1.2 on the combined primary loads and 1.0 on axial secondary loads.

The accident induced leakage performance criterion is:

The primary to secondary accident induced leakage rate for any design basis accidents, 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 where the NRC has approved greater accident-induced leakage as part of a plant's licensing basis. Exceptions to the 1 gpm limit can be applied if approved by the NRC in conjunction with approved alternate repair criteria.

Page 20 of 25

TSTF-449, Rev. 2 The operational LEAKAGE performance criterion is:

The RCS operational primary to secondary LEAKAGE through any one SG shall be limited to 150 gallons per day.

A steam generator tube rupture (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 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 main steam line break (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 ISTS 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 Steam Generator Program required by the proposed change to the ISTS. 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 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 technical specification 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 technical specifications 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 technical specifications.

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.

2. Does the proposed change create the possibility of a new or different kind of accident from any accident previously evaluated?

Response: No Page 21 of 25

TSTF-449, Rev. 2 The proposed performance based requirements are an improvement over the requirements imposed by the current technical specifications.

Implementation of the proposed Steam Generator 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 Steam Generator 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.

3. Does the proposed change involve a significant reduction in a margin of safety?

Response: No 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 also isolate the radioactive fission products in the primary coolant from the secondary system. In summary, the safety function of a 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 Steam Generator Program to manage SG tube inspection, assessment, repair, and plugging. The requirements established by the Steam Generator Program are consistent with those in the applicable design codes and standards and are an improvement over the requirements in the current technical specifications.

For the above reasons, the margin of safety is not changed and overall plant safety will be enhanced by the proposed change to the ISTS.

5.2 Applicable Regulatory RequirementslCriteria The regulatory requirements applicable to SG tube integrity are the following:

10 CFR 50.55a, Codes and Standards - Section (b), ASME Code - c) Reactor coolant pressure boundary. (1) Components which are part of the reactor coolant pressure boundary must meet the requirements for Class 1 components in Section III of the ASME Boiler and Pressure Vessel Code, except as provided in paragraphs (c)(2), (c)(3), and (c)(4) of this section.

The proposed change and the Steam Generator Program requirements which underlie it are in full compliance with the ASME Code. The proposed technical specifications are more effective at Page 22 of 25

TSTF-449, Rev. 2 ensuring tube integrity and, therefore, compliance with the ASME Code, than the current technical specifications as described in Section 4.0 (Technical Analysis).

10 CFR 50.65 Maintenance Rule - Each holder of a license to operate a nuclear power plant under

§§50.21 (b) or 50.22 shall monitor the performance or condition of structures, systems, or components, against licensee-established goals, in a manner sufficient to provide reasonable assurance that such structures, systems, and components, as defined in paragraph (b), are capable of fulfilling their intended functions. Such goals shall be established commensurate with safety and, where practical, take into account industry-wide operating experience. When the performance or condition of a structure, system, or component does not meet established goals, appropriate corrective action shall be taken. For a nuclear power plant for which the licensee has submitted the certifications specified in §50.82(a)(1), this section only shall apply to the extent that the licensee shall monitor the performance or condition of all structures, systems, or components associated with the storage, control, and maintenance of spent fuel in a safe condition, in a manner sufficient to provide reasonable assurance that such structures, systems, and components are capable of fulfilling their intended functions.

Under the Maintenance Rule, licensees classify SGs as risk significant components because they are relied on to remain functional during and after design basis events. The performance criteria included in the proposed technical specifications are used to demonstrate that the condition of the SG "is being effectively controlled through the performance of appropriate preventive maintenance' (Maintenance Rule §(a)(2)). If the performance criteria are not met, a root cause determination of appropriate depth is done and the results evaluated to determine if goals should be established per §(a)(1) of the Maintenance Rule.

NEI 97-06, Steam Generator Program Guidelines, and its referenced EPRI guidelines define a SG program that provides the appropriate preventive maintenance that meets the intent of the Maintenance Rule. NUMARC 93-01, 'Industry Guideline for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants," (Reference 13) offers guidance for implementing the Maintenance Rule should a licensee elect to incorporate additional monitoring goals beyond the scope of those documented in NEI 97-06.

10 CFR 50. Appendix A. GDC 14 - Reactor Coolant Pressure Boundary. The reactor coolant pressure boundary shall be designed, fabricated, erected, and tested so as to have an extremely low probability of abnormal leakage, or rapidly propagating failure, and of gross rupture.

There are no changes to the SG design that impact this general design criteria. The evaluation performed in Section 4.0 concludes that the proposed change will continue to comply with this regulatory requirement.

10 CFR 50. Appendix A, GDC 30- Quality of reactor coolant pressure boundary. Components which are part of the reactor coolant pressure boundary shall be designed, fabricated, erected, and tested to the highest quality standards practical. Means shall be provided for detecting and, to the extent practical, identifying the location of the source of reactor coolant leakage.

There are no changes to the SG design that impact this general design criteria. The evaluation performed in Section 4.0 concludes that the proposed change will continue to comply with this regulatory requirement.

10 CFR 50, Appendix A, GDC 32 - Inspection of reactor coolant pressure boundary. Components which are part of the reactor coolant pressure boundary shall be designed to (1) periodic inspection and testing of important areas and features to assess their structural and leaktight integrity, and (2) an appropriate material surveillance program for the reactor pressure vessel.

Page 23 of 25

TSTF-449, Rev. 2 There are no changes to the SG design that impact this general design criteria. The evaluation performed in Section 4.0 concludes that the proposed change will continue to comply with this regulatory requirement.

General Design Criteria (GDC) 14, 30, and 32 of 10 CFR Part 50, Appendix A, define requirements for the reactor coolant pressure boundary with respect to structural and leakage integrity. Steam generator tubing and tube repairs constitute a major fraction of the reactor coolant pressure boundary surface area. Steam generator tubing and associated repair techniques and components, such as plugs and sleeves, must be capable of maintaining reactor coolant inventory and pressure. The Steam Generator Program required by the proposed technical specification establishes performance criteria, repair criteria, repair methods, inspection intervals and the methods necessary to meet them.

These requirements provide reasonable assurance that tube integrity will be met in the interval between SG inspections.

The proposed change provides requirements that are more effective in detecting SG degradation and prescribing corrective actions. The proposed change results in added assurance of the function and integrity of SG tubes. Therefore, based on the considerations discussed above:

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) Issuance of the amendment will not be inimical to the common defense and security or to the health and safety of the public.

6.0 ENVIRONMENTAL CONSIDERATION

A review has determined that the proposed change would change a requirement with respect to installation or use of a facility component located within the restricted areas, as defined in 10 CFR 20, or would change an inspection or surveillance requirement. However, the proposed change does not involve (i) a significant hazards consideration, (ii) a significant change in the types or significant increase in the amounts of any effluent that may be released offsite, or (iii) a significant increase in individual or cumulative occupational radiation exposure. Accordingly, the proposed change meets the eligibility criterion for categorical exclusion set forth in 10 CFR 51.22(c)(9). Therefore, pursuant to 10 CFR 51.22(b), no environmental impact statement or environmental assessment need be prepared in connection with the proposed change.

7.0 REFERENCES

1. NEI 97-06, 'Steam Generator Program Guidelines."

2. EPRI, "Steam Generator Examination Guideline."

3. EPRI, "Steam Generator Integrity Assessment Guideline."

4. EPRI, "Steam Generator In-situ Pressure Test Guideline."

5. EPRI, "PWR Primary-to-Secondary Leak Guideline."

6. EPRI, "Primary Water Chemistry Guideline."

Page 24 of 25

TSTF-449, Rev. 2

7. EPRI, 'Secondary Water Chemistry Guideline."

8. EPRI Report R-5515-00-2, 'Experience of US and Foreign PWR Steam Generators with Alloy 600TT and Alloy 690TT Tubes and Sleeves," June 5, 2002.

9. Testimony of James Knight Before the Atomic Safety and Licensing Board, Docket Nos. 50-282 and 50-306, January 1975.

10. Draft Regulatory Guide 1.121, 'Bases for Plugging Degraded Steam Generator Tubes," August 1976.

11. ASME B&PV Code, Section 1II,Rules for Construction of Nuclear Facility Components.

12. Generic Letter 95-05, "Voltage-Based Repair Criteria for Westinghouse Steam Generator Tubes Affected by Outside Diameter Stress Corrosion Cracking," August 3,1995.

13. NUMARC 93-01, "Industry Guideline for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants," Revision 3.

14. S. C. Collins memo to W. D.Travers, "Steam Generator Action Plan Revision to Address Differing Professional Opinion on Steam Generator Tube Integrity," May 11, 2001.

Page 25 of 25

TSTF-449, Rev. 2 INSERT 3.4.13 A

a--------NOTE ------ ----- --------- ---- ------

Not required to be performed until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after establishment of steady state operation.

INSERT B 3.4.13 A that primary to secondary LEAKAGE from all steam generators (SGs) is [one gallon per minute]

or increases to [one gallon per minute] as a result of accident induced conditions. The LCO requirement to limit primary to secondary LEAKAGE through any one SG to less than or equal to 150 gallons per day is significantly less than the conditions assumed in the safety analysis.

INSERT B 3.4.13 B

d. Primary to Secondary LEAKAGE Through Any One SG The limit of 150 gallons per day per SG is based on the operational LEAKAGE performance criterion in NEI 97-06, Steam Generator Program Guidelines (Ref. 4). The Steam Generator Program operational LEAKAGE performance criterion in NEI 97-06 states, "The RCS operational primary to secondary leakage through any one SG shall be limited to 150 gallons per day." The limit is based on operating experience with SG tube degradation mechanisms that result in tube leakage. The operational leakage rate criterion in conjunction with the implementation of the Steam Generator Program is an effective measure for minimizing the frequency of steam generator tube ruptures.

INSERT B 3.4.13 C Note 2 states that this SR is not applicable to primary to secondary LEAKAGE because LEAKAGE of 150 gallons per day cannot be measured accurately by an RCS water inventory balance.

Page 1

TSTF-449, Rev. 2 INSERT B 3.4.13 D (BWOG)

This SR verifies that primary to secondary LEAKAGE is less or equal to 150 gallons per day through any one SG. Satisfying the primary to secondary LEAKAGE limit ensures that the operational LEAKAGE performance criterion in the Steam Generator Program is met. If this SR is not met, compliance with LCO 3.4.17, 'Steam Generator Tube Integrity," should be evaluated.

The 150 gallons per day limit is measured at room temperature as described in Reference 5.

The operational LEAKAGE rate limit applies to LEAKAGE through any one SG. If it is not practical to assign the LEAKAGE to an individual SG, all the primary to secondary LEAKAGE should be conservatively assumed to be from one SG.

The Surveillance is modified by a Note which states that the Surveillance is not required to be performed until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after establishment of steady state operation. For RCS primary to secondary LEAKAGE determination, steady state is defined as stable RCS pressure, temperature, power level, pressurizer and makeup tank levels, makeup and letdown, and RCP seal injection and return flows.

The Surveillance Frequency of 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months is a reasonable interval to trend primary to secondary LEAKAGE and recognizes the importance of early leakage detection in the prevention of accidents. During normal operation the primary to secondary LEAKAGE is determined using continuous process radiation monitors or radiochemical grab sampling. In MODES 3 and 4, the primary system radioactivity level may be very low, making it difficult to measure primary to secondary LEAKAGE. If SG water samples are less than the minimum detectable activity of

[5.0 E-7] microcuries/ml for each principal gamma emitter, the primary to secondary LEAKAGE surveillance requirements may be assumed to be met because at this low activity level the operator and off-site dose limits that are the basis for the operational leakage limit will not be exceeded. (Ref. 5).

INSERT B 3.4.13 D (WOG)

This SR verifies that primary to secondary LEAKAGE is less or equal to 150 gallons per day through any one SG. Satisfying the primary to secondary LEAKAGE limit ensures that the operational LEAKAGE performance criterion in the Steam Generator Program is met. If this SR is not met, compliance with LCO 3.4.20, 'Steam Generator Tube Integrity," should be evaluated.

The 150 gallons per day limit is measured at room temperature as described in Reference 5.

The operational LEAKAGE rate limit applies to LEAKAGE through any one SG. If it is not practical to assign the LEAKAGE to an individual SG, all the primary to secondary LEAKAGE should be conservatively assumed to be from one SG.

The Surveillance is modified by a Note which states that the Surveillance is not required to be performed until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after establishment of steady state operation. For RCS primary to secondary LEAKAGE determination, steady state is defined as stable RCS pressure, temperature, power level, pressurizer and makeup tank levels, makeup and letdown, and RCP seal injection and return flows.

The Surveillance Frequency of 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months is a reasonable interval to trend primary to secondary LEAKAGE and recognizes the importance of early leakage detection in the prevention of accidents. During normal operation the primary to secondary LEAKAGE is determined using continuous process radiation monitors or radiochemical grab sampling. In MODES 3 and 4, the primary system radioactivity level may be very low, making it difficult to measure primary to secondary LEAKAGE. If SG water samples are less than the minimum detectable activity of Page 2

TSTF-449, Rev. 2

[5.0 E-7] microcuries/ml for each principal gamma emitter, the primary to secondary LEAKAGE surveillance requirements may be assumed to be met because at this low activity level the operator and off-site dose limits that are the basis for the operational leakage limit will not be exceeded. (Ref. 5).

INSERT B 3.4.13 D (CEOG)

This SR verifies that primary to secondary LEAKAGE is less or equal to 150 gallons per day through any one SG. Satisfying the primary to secondary LEAKAGE limit ensures that the operational LEAKAGE performance criterion in the Steam Generator Program is met. If this SR is not met, compliance with LCO 3.4.18, 'Steam Generator Tube Integrity,' should be evaluated.

The 150 gallons per day limit is measured at room temperature as described in Reference 5.

The operational LEAKAGE rate limit applies to LEAKAGE through any one SG. If it is not practical to assign the LEAKAGE to an individual SG, all the primary to secondary LEAKAGE should be conservatively assumed to be from one SG.

The Surveillance is modified by a Note which states that the Surveillance is not required to be performed until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after establishment of steady state operation. For RCS primary to secondary LEAKAGE determination, steady state is defined as stable RCS pressure, temperature, power level, pressurizer and makeup tank levels, makeup and letdown, and RCP seal injection and return flows.

The Surveillance Frequency of 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months is a reasonable interval to trend primary to secondary LEAKAGE and recognizes the importance of early leakage detection in the prevention of accidents. During normal operation the primary to secondary LEAKAGE is determined using continuous process radiation monitors or radiochemical grab sampling. In MODES 3 and 4, the primary system radioactivity level may be very low, making it difficult to measure primary to secondary LEAKAGE. If SG water samples are less than the minimum detectable activity of

[5.0 E-7] microcuries/ml for each principal gamma emitter, the primary to secondary LEAKAGE surveillance requirements may be assumed to be met because at this low activity level the operator and off-site dose limits that are the basis for the operational leakage limit will not be exceeded. (Ref. 5).

INSERT B 3.4.13 E

4. NEI 97-06, 'Steam Generator Program Guidelines."

5. EPRI TR-1 04788, "Pressurized Water Reactor Primary-to-Secondary Leak Guidelines."

Page 3

TSTF-449, Rev. 2 RCS Operational LEAKAGE 3.4.13 3.4 REACTOR COOLANT SYSTEM (RCS) 3.4.13 RCS Operational LEAKAGE LCO 3.4.13 RCS operational LEAKAGE shall be limited to:

a. No pressure boundary LEAKAGE,

b. I gpm unidentified LEAKAGE,

c. 10 gpm identified LEAKAGE, ( 3

/71,11-11 0.

(V-APPLICABILITY: MODES' 1, 2, 3, and 4.

p ovia I ACTIONS K CONDITION A. RCt'LEAKAGE not within limits for reasons A.1 REQUIRED ACTION Reduce LEAKAGE to within limits.

COMPLETION TIME 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months other than pressure {O printa 4o boundary LEAKAGE.S r B. Required Action and B.1 Be in MODE 3. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months associated Completion Time of Condition A not AND met.

B.2 Be in MODE 5. 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months OR Pressure boundary LEAKAGE exists.

/r,,

< p; et,7 a" 4v Sr ca J- r; Le AKAGdE n+ I' l'-

BWOG STS 3.4.13 - 1 Rev. 2, 04/30/01

TSTF-449, Rev. 2 RCS Operational LEAKAGE 5 a zlekXpia 5 " ^LE 3.4.13 t ._ _

BWOG STS 3.4.13 -^2 Rev. 2. 04/30/01

TSTF-449, Rev. 2 RCS Operational LEAKAGE B 3.4.13 B 3.4 REACTOR COOLANT SYSTEM (RCS)

B 3.4.13 RCS Operational LEAKAGE BASES BACKGROUND Components that contain or transport the coolant to or from the reactor core make up the RCS. Component joints are made by welding, bolting, rolling, or pressure loading, and valves isolate connecting systems from the RCS.

During plant life, the joint and valve interfaces can produce varying amounts of reactor coolant LEAKAGE, through either normal operational wear or mechanical deterioration. The purpose of the RCS Operational LEAKAGE LCO is to limit system operation in the presence of LEAKAGE from these sources to amounts that do not compromise safety. This LCO specifies the types and amounts of LEAKAGE.

10 CFR 50, Appendix A, GDC 30 (Ref. 1), requires means for detecting and, to the extent practical, identifying the source of reactor coolant LEAKAGE. Regulatory Guide 1.45 (Ref. 2) describes acceptable methods for selecting Leakage Detection Systems.

The safety significance of RCS LEAKAGE varies widely depending on its source, rate, and duration. Therefore, detectin and monitoring reactor.

coolant LEAKAGE into the containment areaWnecessary. Quickly cvird-;-"/

separating the identified LEAKAGE from the unidentified LEAKAGE is necessary to provide quantitative information to the operators, allowing them to take corrective action should a leak occur detrimental to the safety of the facility and the public.

A limited amount of leakage inside containment is expected from auxiliary systems that cannot be made 100% leaktight. Leakage from these systems should be detected, located, and isolated from the containment atmosphere, if possible, to not interfere with RCS leakage detection.

This LCO deals with protection of the reactor coolant pressure boundary (RCPB) from degradation and the core from inadequate cooling, in addition to preventing the accident analysis radiation release assumptions from being exceeded. The consequences of violating this LCO include the possibility of a loss of coolant accident (LOCA).

However, the ability to monitor leakage provides advance warning to permit plant shutdown before a LOCA occurs. This advantage has been shown by leak before break" studies.

BWOG STS B 3.4.1 3 - 1 Rev. 2, 04/30/01

TSTF-449, Rev. 2 RCS Operational LEAKAGE B 3.4.13 BASES APPLICABLE Except for primary to secondary LEAKAGE, the safety analyses do not SAFETY address operational LEAKAGE. However, other operational LEAKAGE is ANALYSES related to the safety analyses for LOCA; the amount of leakage can affect the probability of such an event. The safety analysis for an event

-- > ~~resultin in steam discharge to the atmosphere assumesi Uk$,- ri o eo r LEAKAQLas the initialco in 3,4.13 Primary to secondary LEAKAGE is a factor in the dose releases outside containment resulting from a steam line break (SLB) accident. To a lesser extent, other accidents or transients involve secondary steam release to the atmosphere, such as a steam generator tube rupture (SGTR). The leakage contaminates the secondary fluid.

The FSAR (Ref. 3) analysis for SGTR assumes the contaminated secondary fluid is only briefly released via safety valves and the majority is steamed to the condenser. Theli gpmjprimary to secondary amEAA ss relatively inconsequential.

The SLB is more limiting for site radiation releases. The safety analysis for the SLB accident assumeslj gpmjprimary to secondary LEAKAGE in one generator as an initial condition. The dose consequences resulting from the SLB accident are well within the limits defined in 10 CFR 100.

RCS operational LEAKAGE satisfies Criterion 2 of 10 CFR 50.36(c)(2)(ii).

LCO RCS operational LEAKAGE shall be limited to:

a. Pressure Boundary LEAKAGE No pressure boundary LEAKAGE is allowed, being indicative of material deterioration. LEAKAGE of this type is unacceptable as the leak itself could cause further deterioration, resulting in higher LEAKAGE. Violation of this LCO could result in continued degradation of the RCPB. LEAKAGE past seals and gaskets is not pressure boundary LEAKAGE.

b. Unidentified LEAKAGE One gallon per minute (gpm) of unidentified LEAKAGE is allowed as a reasonable minimum detectable amount that the containment air monitoring and containment sump level monitoring equipment can detect within a reasonable time period. Violation of this LCO could result in continued degradation of the RCPB, if the LEAKAGE is from the pressure boundary.

BWOG STS B 3.4.13 - 2 Rev. 2, 04/30/01

TSTF-449, Rev. 2 RCS Operational LEAKAGE B 3.4.13 BASES LCO (continued)

c. Identified LEAKAGE Up to 10 gpm of identified LEAKAGE is considered allowable because LEAKAGE is from known sources that do not interfere with detection of unidentified LEAKAGE and is well within the capability of the RCS makeup system. Identified LEAKAGE includes LEAKAGE to the containment from specifically known and located sources, but does not include pressure boundary LEAKAGE or controlled reactor coolant pump (RCP) seal leakoff (a normal function not considered LEAKAGE). Violation of this LCO could result in continued degradation of a component or system.

d. Primarv to Secoa LEAKAGE through All Mam Generators I

(SGs)

Tota rimary to secondary LEAKAGE mounting to 1 gpm throug Gs produces acceptable offsit oses in the SLB accident analysis. Violation of this LCO c Id exceed the offsite dose its A for this accident. Primapote fordRCP LEAKAGE is geates ite. Primarv to§9ndary LEAKAGE throuaWnv One SG 3,,13 _ Th,0 allon per day limit on oSG allocates the total~g

- whn the Rtotis prowbessuized.

Alowedpriary o scondry~AKAG tfi EKAE eqally betwee t~e two APPLICABILITY In MODES 1, 2, 3, and 4, the potential for RCPB LEAKAGE is greatest when the RCS is pressurized.

In MODES 5 and 6, LEAKAGE limits are not required because the reactor coolant pressure is far lower, resulting in lower stresses and reduced potentials for LEAKAGE.

LCO 3.4.14, "RCS Pressure Isolation Valve (PIV) Leakage," measures leakage through each individual PIV and can impact this LCO. Of the two PIVs in series in each isolated line, leakage measured through one PIV does not result in RCS LEAKAGE when the other is leaktight. If both valves leak and result in a loss of mass from the RCS, the loss must be included in the allowable identified LEAKAGE.

BWOG STS B 3.4.13 - 3 Rev. 2, 04/30/01

TSTF-449, Rev. 2 RCS Operational LEAKAGE B 3.4.13 BASES ACTIONS A.1 6; If unidentified LEAKAGE/identified LEAKAGEFosedar (L oare In excess of the LCO limits, the LEAKAGE must be re d to within limits within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months . This Completion Time allows time to verify leakage rates and either identify unidentified LEAKAGE or reduce LEAKAGE to within limits before the reactor must be shut down.

This action is necessary to prevent further deterioration of the RCPB.

B.1 and B.2 Nrri 4 arcly AeK',I is h an ressure boundary LEAKAGE exists r if de (Qrjao seoeida LEAKAGE cannot be reduced to within limits within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months , the reactor must be brought to lower pressure conditions to reduce the severity of the LEAKAGE and its potential consequences.

The reactor must be brought to MODE 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and MODE 5 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months . This action reduces the LEAKAGE and also reduces the factors that tend to degrade the pressure boundary.

The Completion Times allowed are reasonable, based on operating experience, to reach the required conditions from full power conditions In an orderly manner and without challenging plant systems. In MODE 5, the pressure stresses acting on the RCPB are much lower and further deterioration is much less likely.

SURVEILLANCE SR 3.4.13.1 REQUIREMENTS Verifying RCS LEAKAGE within the LCO limits ensures that the integrity of the RCPB is maintained. Pressure boundary LEAKAGE would at first appear as unidentified LEAKAGE and can only be positively identified by inspection. Unidentified LEAKAGE and identified LEAKAGE are determined by performance of an RCS water inventory balance.fP-r-iqia o eoq ~^j saso measured by perlomac of an, vtrienory balancej' conjunction wit eflt nitonn-inlthin the) iecr~av team and Sedwater systems.

The RCS water inventory balance must be performed with the reactor at

,Tve; steady state operating conditions (stable temperature, power level,

. . pressurizer and makeup tank levels, makeup and letdown, [and RCP seal linjecion and retumflows . h re 6)Note(isaa nthat this SR is not required to be performed until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after establishing steady state operation. The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months allowance provides sufficient time to collect and process all necessary data after stable plant conditions are established.

BWOG STS B 3.4.13 - 4 Rev. 2, 04/30/01

TSTF-449, Rev. 2 RCS Operational LEAKAGE B 3.4.13 BASES SURVEILLANCE REQUIREMENTS (continued)

Steady state operation is required to perform a proper water inventory balance since calculations during maneuvering are not useful. For RCS operational LEAKAGE determination by water Inventory balance, steady state is defined as stable RCS pressure, temperature, power level, pressurizer and makeup tank levels, makeup and letdown, and RCP pump seal injection and return flows.

SI?1ere An early warning of pressure boundary LEAKAGE or unidentified L 2 ;q C } LEAKAGE is provided by the automatic systems that monitor the containment atmosphere radioactivity and the containment sump level.

These leakage detection systems are specified in LCO 3.4.15, "RCS Leakage Detection Instrumentation."

The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Frequency is a reasonable interval to trend LEAKAGE and recognizes the importance of early leakage detection in the prevention of accidents.

~SR 3.4.13.2 r.Se- 4 ~is SR provides t means necessary to determine SG 0 R BITY in an operationa~kwODEE. The requirement to derronstra G tube r t Ie3i D ly&z /Pro integrity in ordance with the Steam Generator T Surveillance ra >mp asizes the importance of SG tube' fgrity, even thog th urveillance cannot be performed at norr perating conditios REFERENCES 1. 10 CFR 50, Appendix A, GDC 30.

2. Regulatory Guide 1.45, May 1973.

3. FSAR, Chapter [15].

BWOG STS B 3.4.13 - 5 Rev. 2, 04/30/01

TSTF-449, Rev. 2 RCS Operational LEAKAGE 3.4.13 3.4 REACTOR COOLANT SYSTEM (RCS) 3.4.13 RCS Operational LEAKAGE LCO 3.4.13 RCS operational LEAKAGE shall be limited to:

a. No pressure boundary LEAKAGE,

b. .1 gpm unidentified LEAKAGE,

c. 10 gpm identified LEAKAGE, d atotas p secondaw KAGE throug~,esteam ns per day primary to secondary LEAKAGE through any one APPLICABIL ITY: MODES 1, 2, 3, and 4.

ACTIONS0 K CONDITION A.7RkEAKAGE not within limits for reasons A.1 REQUIRED ACTION Reduce LEAKAGE to within limits.

COMPLETION TIME 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months other than pressure c Gr %0seca-j )

boundary LEAKAGE.

B. Required Action and B.1 Be in MODE 3. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months associated Completion Time of Condition A not AND met.

OR B.2 Be in MODE 5. 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months Pressure boundary LEAKAGE exists.

I_ a- _ -

WOG STS 3.4.13- 1 Rev. 2, 04/30/01

TSTF-449, Rev. 2 RCS Operational LEAKAGE 3.4.13 I

WOG STS 3.4.13- 2 Rev. 2, 04130/01

TSTF-449, Rev. 2 RCS Operational LEAKAGE B 3.4.13 BASES APPLICABLE Except for primary to secondary LEAKAGE, the safety analyses do not SAFETY address operational LEAKAGE. However, other operational LEAKAGE is ANALYSES related to the safety analyses for LOCA; the amount of leakage can affect the probability of such an event. The safety analysis for an event resulting in steam discharge to the atmi'osphere assumeea/

Primary to secondary LEAKAGE is a factor in the dose releases outside containment resulting from a steam line break (SLB) accident. To a lesser extent, other accidents or transients involve secondary steam release to the atmosphere, such as a steam generator tube rupture (SGTR). The leakage contaminates the secondary fluid.

The FSAR (Ref. 3) analysis for SGTR assumes the contaminated secondary fluid is only briefly released via safety valves and the majority is steamed to the condenser. Theffgpmjprimary to secondary LEAKAG is relatively inconsequential.

The SLB is more limiting for site radiation releases. The safety analysis for the SLB accident assumes Fgpmjprimary to secondary LEAKAGE in one generator as an initial condition. The dose consequences resulting from the SLB accident are well within the limits defined in 10 CFR 100 or the staff approved licensing basis (i.e., a small fraction of these limits).

The RCS operational LEAKAGE satisfies Criterion 2 of 10 CFR 50.36(c)(2)(ii).

LCO RCS operational LEAKAGE shall be limited to:

a. Pressure Boundary LEAKAGE No pressure boundary LEAKAGE is allowed, being indicative of material deterioration. LEAKAGE of this type is unacceptable as the leak itself could cause further deterioration, resulting in higher LEAKAGE. Violation of this LCO could result in continued degradation of the RCPB. LEAKAGE past seals and gaskets is not pressure boundary LEAKAGE.

b. Unidentified LEAKAGE One gallon per minute (gpm) of unidentified LEAKAGE is allowed as a reasonable minimum detectable amount that the containment air monitoring and containment sump level monitoring equipment can detect within a reasonable time period. Violation of this LCO could WOG STS B 3.4.13 - 2 Rev. 2, 04/30/01

TSTF-449, Rev. 2 RCS Operational LEAKAGE B 3.4.13 BASES LCO (continued) result in continued degradation of the RCPB, if the LEAKAGE is from the pressure boundary.

c. Identified LEAKAGE Up to 10 gpm of identified LEAKAGE is considered allowable because LEAKAGE is from known sources that do not interfere with detection of unidentified LEAKAGE and is well within the capability of the RCS Makeup System. Identified LEAKAGE includes LEAKAGE to the containment from specifically known and located sources, but does not include pressure boundary LEAKAGE or controlled reactor coolant pump (RCP) seal leakoff (a normal function not considered LEAKAGE). Violation of this LCO could result in continued degradation of a component or system.

d. Prima to Second AKAGE through All Steam Generat s LaGsI Total pri to secondary LEAKAGE amounting t gpm through all S produces acceptable offsite doses in th tSB accident lysis. Violation of this LCO could excee e offsite dose limits

/fr this accident. Primary to secondary AKGE must be included in the total allowable limit for identifie dEAKAGE.

IgeA. Pr marvto Secop4 LEAKAGE through Any One SG/

The [500 allons per day limit on one SG is based the

, 3assu tion that a single crack leaking this amo would not p agate to a SGTR under the stress condins of a LOCA or a main steam line rupture. If leaked throu many cracks, the cracks are very small, and the above assum n is conservative.

APPLICABILITY In MODES 1, 2, 3, and 4, the potential for RCPB LEAKAGE is greatest when the RCS is pressurized.

In MODES 5 and 6, LEAKAGE limits are not required because the reactor coolant pressure is far lower, resulting in lower stresses and reduced potentials for LEAKAGE.

LCO 3.4.14, "RCS Pressure Isolation Valve (PIV) Leakage," measures leakage through each individual PIV and can impact this LCO. Of the two PlVs in series in each isolated line, leakage measured through one PIV does not result in RCS LEAKAGE when the other is leak tight. If both WOG STS B 3.4.13 - 3 Rev. 2, 04/30/01

TSTF-449, Rev. 2 RCS Operational LEAKAGE B 3.4.13 BASES APPLICABILITY (continued) valves leak and result in a loss of mass from the RCS, the loss must be included in the allowable identified LEAKAGE.

ACTIONS A.1 ¢ Unidentified LEAKAGE7Tidentified LEAKAG o GEto ean (L in excess of the LCO limits must be reduced to within limits within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months . This Completion Time allows time to verify leakage rates and either identify unidentified LEAKAGE or reduce LEAKAGE to within limits before the reactor must be shut down. This action is necessary to prevent further deterioration of the RCPB.

'?r proe oSea JgL14 B.1 and B.2 5 /. -

If any pressure bounda LEAKA exstsr if unidentified identified LEAKAGcnorarvto seaa-ARcannot be reduced to within limits within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months , the reactor must be brought to lower pressure conditions to reduce the severity of the LEAKAGE and its potential consequences. It should be noted that LEAKAGE past seals and gaskets is not pressure boundary LEAKAGE. The reactor must be brought to MODE 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and MODE 5 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months . This action reduces the LEAKAGE and also reduces the factors that tend to degrade the pressure boundary.

The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.

In MODE 5, the pressure stresses acting on the RCPB are much lower, and further deterioration is much less likely.

SURVEILLANCE SR 3.4.13.1 REQUIREMENTS Verifying RCS LEAKAGE to be within the LCO limits ensures the integrity of the RCPB Is maintained. Pressure boundary LEAKAGE would at first appear as unidentified LEAKAGE and can only be positively identified by Inspection. It should be noted that LEAKAGE past seals and gaskets is not pressure boundary LEAKAGE. Unidentified LEAKAGE and identified LEAKAGE are determined by performance of S water inventory balance. Pr secon ary Lis also measur&by perormae~of an RCS water mv ory balance in conli ction with efmonitoring within the scondary steam and fe'edwater systems WOG STS B 3.4.13 - 4 Rev. 2, 04130/01

TSTF-449, Rev. 2 RCS Operational LEAKAGE

,.-~av' f~wer&e(,prserser-B 3.4.13 BASES l ,-,-,.,Ke"

J rags Ca I d ub13

SURVEILLANCE REQUIREMENTS (continued)

The RCS water invento balance must be me th the reactor at steady Ci x state oerating Conditions. TheNoth at this (otek-/sS)

,te. is not required to be perormed until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after establishing to &J > lsteady state operation. The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months allowance provides sufficient time to 4iW, Sts0 collect and process all necessary data after stable plant conditions are established.

Steady state operation is required to perform a proper inventory balance since calculations during maneuvering are not useful. For RCS operational LEAKAGE determination by water inventory balance, steady state is defined as stable RCS pressure, temperature, power level, pressurizer and makeup tank levels, makeup and letdown, and RCP seal injection and return flows.

An early warning of pressure boundary LEAKAGE or unidentified LEAKAGE is provided by the automatic systems that monitor the containment atmosphere radioactivity and the containment sump level. It should be noted that LEAKAGE past seals and gaskets is not pressure boundary LEAKAGE. These leakage detection systems are specified in 2 3 c. LCO 3.4.15, "RCS Leakage Detection Instrumentation."

The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Frequency is a reasonable interval to trend LEAKAGE and recognizes the importance of early leakage detection in the prevention of accidents.

SR 3.4.13.2 This SR provides th eans necessary to determine SG in an operationa DE. The requirement to demonstral integrity in a rdance with the Steam Generator Tuba Program phasizes the importance of SG tube in rity this eillance cannot be performed at norm atin REFERENCES 1. 10 CFR 50, Appendix A, GDC 30.

2. Regulatory Guide 1.45, May 1973.

3. FSAR, Section [15].

WOG STS B 3.4.13 - 5 Rev. 2, 04/30/01

TSTF-449, Rev. 2 RCS Operational LEAKAGE 3.4.13 3.4 REACTOR COOLANT SYSTEM (RCS) 3.4.13 RCS Operational LEAKAGE LCO 3.4.13 RCS operational LEAKAGE shall be limited to:

a. No pressure boundary LEAKAGE,

b. 1 gpm unidentified LEAKAGE,

c. 10 gpm identified LEAKAGE, (D

d. I gpp'otalp1 prmr osc LAGE;t gt

'Venherators (SGs), and 7 C-

'@ gllon perdayprimary to secondary LEAKAGE through any t 4,$q~t~i C6)

APPLICABILITY: MODES 1, 2,3, and 4.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. RC LEAKAGE not A.1 Reduce LEAKAGE to 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months within limits for reasons within limits.

other than pressure vo Drhea 4CASG a v boundary LEAKAGE B. Required Action and B.1 Be in MODE 3. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months associated Completion Time of Condition A not AND met.

B.2 Be in MODE 5. 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months OR Pressure boundary LEAKAGE exists.

r s/Pro-" 47 4 eco"Jrc CEOG STS 3.4.13- 1 Rev. 2, 04/30/01

TSTF-449, Rev. 2 RCS Operational LEAKAGE 3.4.13

- NOTE:

(D Not required to be performed until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after reestablishment of steady state operation.

Verify RCSperational LEAKAGE is within limits by performance of RCS water inventory balance.

CEOG STS 3.4.13 - 2 Rev. 2, 04/30/01

TSTF-449, Rev. 2 RCS Operational LEAKAGE B 3.4.13 BASES APPLICABLE Except for primary to secondary LEAKAGE, the safety analyses do not SAFETY address operational LEAKAGE. However, other operational LEAKAGE is ANALYSES related to the safety analyses for LOCA; the amount of leakage can affect the probability of such an event. The safety analysis for an event resulting in steam discharge to the atmosphere assumes 1I prima sec a aste initiaeondition. n.

3A. /3 4 Primary to secondary LEAKAGE is a factor in the dose releases outside containment resulting from a steam line break (SLB) accident. To a lesser extent, other accidents or transients involve secondary steam release to the atmosphere, such as a steam generator tube rupture (SGTR). The leakage contaminates the secondary fluid.

The FSAR (Ref. 3) analysis for SGTR assumes the contaminated secondary fluid is only briefly released via safety valves and the majority is steamed to the condenser. Theffgpmjprimary to secondary danv~os; LEAKAG ~s relatively inconsequential.

aetlys" The SLB is more limiting for site radiation releases. The safety analysis for the SLB accident assumesU gpmjprimary to secondary LEAKAGE in one generator as an initial condition. The dose consequences resulting from the SLB accident are well within the limits defined in 10 CFR 50 or the staff approved licensing basis (i.e., a small fraction of these limits).

RCS operational LEAKAGE satisfies Criterion 2 of 10 CFR 50.36(c)(2)(ii).

LCO RCS operational LEAKAGE shall be limited to:

a. Pressure Boundary LEAKAGE No pressure boundary LEAKAGE is allowed, being indicative of material deterioration. LEAKAGE of this type is unacceptable as the leak itself could cause further deterioration, resulting in higher LEAKAGE. Violation of this LCO could result in continued degradation of the RCPB. LEAKAGE past seals and gaskets is not pressure boundary LEAKAGE.

b. Unidentified LEAKAGE One gallon per minute (gpm) of unidentified LEAKAGE is allowed as a reasonable minimum detectable amount that the containment air monitoring and containment sump level monitoring equipment can detect within a reasonable time period. Violation of this LCO could CEOG STS B 3.4.13 - 2 Rev. 2, 04130/01

TSTF-449, Rev. 2 RCS Operational LEAKAGE B 3.4.13 BASES LCO (continued) result in continued degradation of the RCPB, if the LEAKAGE is from the pressure boundary.

c. Identified LEAKAGE Up to 10 gpm of identified LEAKAGE is considered allowable because LEAKAGE is from known sources that do not interfere with detection of unidentified LEAKAGE and is well within the capability of the RCS makeup system. Identified LEAKAGE includes LEAKAGE to the containment from specifically known and located sources, but does not include pressure boundary LEAKAGE or controlled reactor coolant pump (RCP) seal leakoff (a normal function not considered LEAKAGE). Violation of this LCO could result in continued degradation of a component or system.

LCO 3.4.14, "RCS Pressure Isolation Valve (PIV) Leakage,"

measures leakage through each individual PIV and can impact this LCO. Of the two PIVs in series in each isolated line, leakage measured through one PIV does not result in RCS LEAKAGE when the other is leaktight. If both valves leak and result in a loss of mass from the RCS, the loss must be included in the allowable identified LEAKAGE.

d rmary to SecondacwLEAKAGE through All Steam Geneiaos L$GsA Total prirt scndary LEAKAGE amountin t~mtrough all S 4roduces acceptable offsite doses in thL acient ysis. Violation of this LCO could excee e offsite dose limits A Aor I his accident analysis. Primary RCPBary LEAKAGE must be

\ included in the total allowable limit~k ietified LEAKAGE.

K~ns~t 8 e. Primary to Seqpearv LEAKAGE through Any Onl3G

{ 3 v.13 B ) The[7 aln per day limit on primary todr EKG thrg~ any one SG allocates the oa gpalweprmyo/

< SconaryLEAAGEequllybeteenthetwogenerao APPLICABILITY In MODES 1, 2, 3, and 4, the potential for RCPB LEAKAGE is greatest when the RCS is pressurized.

CEOG STS B 3.4.13 - 3 Rev. 2, 04/30/01

TSTF-449, Rev. 2 RCS Operational LEAKAGE B 3.4.13 BASES APPLICABILITY (continued)

In MODES 5 and 6, LEAKAGE limits are not required because the reactor coolant pressure is far lower, resulting in lower stresses and reduced potentials for LEAKAGE.

ACTIONS A.1 Unidentified LEAKAGE/identified LEAKAGE~or pcito secondaa

( 1 in excess of the LCO limits must be reduced to within limits within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months . This Completion Time allows time to verify leakage rates and either identify unidentified LEAKAGE or reduce LEAKAGE to within limits before the reactor must be shut down. This action is necessary to prevent further deterioration of the RCPB.

8.1 and B.2 _______________________

If any pressure boundary LEAKAGE exists or If unidentified) entified npri to sepoida LEAKAGE cannot be reduced to within limits within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months , the reactor must be brought to lower pressure conditions to reduce the severity of the LEAKAGE and its potential consequences.

The reactor must be brought to MODE 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and to MODE 5 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months . This action reduces the LEAKAGE and also reduces the factors that tend to degrade the pressure boundary.

The allowed Completion Times are reasonable, based on operating experience, to reach the required conditions from full power conditions in an orderly manner and without challenging plant systems. In MODE 5, the pressure stresses acting on the RCPB are much lower, and further deterioration is much less likely.

SURVEILLANCE SR 3.4.13.1 REQUIREMENTS Verifying RCS LEAKAGE to be within the LCO limits ensures the Integrity of the RCPB is maintained. Pressure boundary LEAKAGE would at first appear as unidentified LEAKAGE and can only be positively identified by inspection. Unidentified LEAKAGE and identified LEAKAGE are deerindbpefracofnRC water inventory balac. rmfy

[toseondryLEAKAGE istfso measured by -performance of an RS

{ wtejr~enory balancey~conjunction with eff~mnt monitoringhi the c~iayteam andSedwater sysatem. /--

The RCS water inventory balance must be performed with the reactor at steady state operating conditions (stable temperature, power level, CEOG STS B 3.4.13- 4 Rev. 2, 04/30/01

TSTF-449, Rev. 2 RCS Operational LEAKAGE B 3.4.13 BASES SURVEILLANCE REQUIREMENTS (continued)

Le pressurizer and makeup tank levels, makeup and letdown, land RCP seal i ection and return flowsl. Throre, hatthis

5 Ad J;-e J 67 SR is not required to be performed until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after establishing 4h Ak4c.steady state operation. The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months allowance provides sufficient time to k , 5 / collect and process all necessary data after stable plant conditions are

< established.

Steady state operation is required to perform a proper water inventory balance since calculations during maneuvering are not useful. For RCS operational LEAKAGE determination by water inventory balance, steady state is defined as stable RCS pressure, temperature, power level, pressurizer and makeup tank levels, makeup and letdown, and RCP seal injection and return flows.

An early warning of pressure boundary LEAKAGE or unidentified LEAKAGE is provided by the automatic systems that monitor the containment atmosphere radioactivity and the containment sump level.

These leakage detection systems are specified in LCO 3.4.15, "RCS

, Leakage Detection Instrumentation."

The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Frequency is a reasonable interval to trend LEAKAGE and recognizes the importance of early leakage detection Inthe prevention of accidents.

SR 3.4.13.2 7 3, 1s 3'q ctl s/13 D

/

Thi;s SR pro~des thepdlans necessary to determine SOPERABITt in an operationa DE. The requirement to demo rate SG tube integrity in acrance with the Steam Generat ~be Surveillance I Progra phasizes the importance of SG t IIntegrity, even though kthi svilance cannot be performed at nafal operating conditions.

REFERENCES 1. 10 CFR 50, Appendix A, GDC 30.

2. Regulatory Guide 1.45, May 1973.

3. FSAR, Section [15].

CEOG STS B 3.4.13 - 5 Rev. 2, 04/30/01

TSTF-449, Rev. 2 INSERT 5.5.9 A Steam Generator Program shall be established and implemented to ensure that SG tube integrity is maintained. In addition, the Steam Generator Program shall include the following provisions:

a. Provisions for condition monitoring assessments. Condition monitoring assessment means an evaluation of the 'as found" condition of the tubing with respect to the performance criteria for structural integrity and accident induced leakage. The 'as found" condition refers to the condition of the tubing during an SG inspection outage, as determined from the inservice inspection results or by other means, prior to the plugging

[or repair] of tubes. Condition monitoring assessments shall be conducted during each outage during which the SG tubes are inspected, plugged, [or repaired] to confirm that the performance criteria are being met.

b. Performance criteria for SG tube integrity. SG tube integrity shall be maintained by meeting the performance criteria for tube structural integrity, accident induced leakage, and operational LEAKAGE.

1. Structural integrity performance criterion: All in-service steam generator tubes shall retain structural integrity over the full range of normal operating conditions (including startup, operation in the power range, hot standby, and cool down and all anticipated transients included in the design specification) and design basis accidents. This includes retaining 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 the design basis accident primary-to-secondary pressure differentials. Apart from the above requirements, additional loading conditions associated with the 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 pressure with a safety factor of 1.2 on the combined primary loads and 1.0 on axial secondary loads.

2. Accident induced leakage performance criterion: 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 where the NRC has approved greater accident induced leakage as part of a plant's licensing basis. Exceptions to the [1 gpm] limit can be applied if approved by the NRC in conjunction with approved alternate repair criteria].

3. The operational LEAKAGE performance criterion is specified in LCO 3.4.13, "RCS Operational LEAKAGE."

c. Provisions for SG tube repair criteria. Tubes found by inservice inspection to contain flaws with a depth equal to or exceeding [40%] of the nominal tube wall thickness shall be plugged [or repaired].

Page 1

TSTF-449, Rev. 2

-- ----------- Reviewer's Note -------------------------

Alternate tube repair criteria currently permitted by plant technical specifications are listed here. The description of these alternate tube repair criteria should be equivalent to the descriptions in current technical specifications.

[The following alternate tube repair criteria may be applied as an alternative to the 40%

depth based criteria:

1.]

d. Provisions for SG tube inspections. Periodic SG tube inspections shall be performed. The number an portions of the tubes inspected and methods of inspection shall be performed with the objective of detecting flaws of any type (e.g., 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 criteria. The tube-to-tubesheet weld is not part of the tube. In addition to meeting the requirements of d.1, d.2, and d.3 below, the inspection scope, inspection methods, and inspection intervals shall be such as to ensure that SG tube integrity is maintained until the next SG inspection. An assessment of degradation shall be performed to determine the type and location of flaws to which the tubes may be susceptible and, based on this assessment, to determine which inspection methods need to be employed and at what locations.

a-----------a--Reviewer's Note--------------

Plants are to include the appropriate Frequency (e.g., select the appropriate Item 2.) for their SG design. The first Item 2 is applicable to SGs with Alloy 600 mill annealed tubing.

The second Item 2 is applicable to SGs with Alloy 600 thermally treated tubing. The third Item 2 is applicable to SGs with Alloy 690 thermally treated tubing.

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

[2. Inspect 100% of the tubes at sequential periods of 60 effective full power months.

The first sequential period shall be considered to begin after the first inservice inspection of the SGs. No SG shall operate for more than 24 effective full power months or one refueling outage (whichever is less) without being inspected.]

[2. Inspect 100% of the tubes at sequential periods of 120, 90, and, thereafter, 60 effective full power months. The first sequential period shall be considered to begin after the first inservice inspection of the SGs. In addition, inspect 50% of the tubes by the refueling outage nearest the midpoint of the period and the remaining 50% by the refueling outage nearest the end of the period. No SG shall operate for more than 48 effective full power months or two refueling outages (whichever is less) without being inspected.]

[2. Inspect 100% of the tubes at sequential periods of 144, 108, 72, and, thereafter, 60 effective full power months. The first sequential period shall be considered to begin after the first inservice inspection of the SGs. In addition, inspect 50% of the tubes by the refueling outage nearest the midpoint of the period and the remaining 50% by Page 2

TSTF-449, Rev. 2 the refueling outage nearest the end of the period. No SG shall operate for more than 72 effective full power months or three refueling outages (whichever is less) without being inspected.]

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

e. Provisions for monitoring operational primary to secondary LEAKAGE.

[f. Provisions for SG tube repair methods. Steam generator tube repair methods shall provide the means to reestablish the RCS pressure boundary integrity of SG tubes without removing the tube from service. For the purposes of these Specifications, tube plugging is not a repair. All acceptable tube repair methods are listed below.

Reviewer's Note Tube repair methods currently permitted by plant technical specifications are to be listed here. The description of these tube repair methods should be equivalent to the descriptions in current technical specifications. If there are no approved tube repair methods, this section should not be used.

1.]

Page 3

TSTF-449, Rev. 2 INSERT 5.6.9 A report shall be submitted within 180 days after the initial entry into MODE 4 following completion of an inspection performed in accordance with the Specification 5.5.9, Steam Generator (SG) Program. The report shall include:

a. The scope of inspections performed on each SG,

b. Active degradation mechanisms found,

c. Nondestructive examination techniques utilized for each degradation mechanism,

d. Location, orientation (if linear), and measured sizes (if available) of service induced indications,

e. Number of tubes plugged [or repaired] during the inspection outage for each active degradation mechanism,

f. Total number and percentage of tubes plugged [or repaired] to date,

g. The results of condition monitoring, including the results of tube pulls and in-situ testing,

[h. The effective plugging percentage for all plugging [and tube repairs] in each SG, and]

[i. Repair method utilized and the number of tubes repaired by each repair method.]

Page 4

TSTF-449, Rev. 2 Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.8 Inservice Testing Program' (continued)

ASME Boiler and Pressure Vessel Code and applicable Required Frequencies for, Addenda terminology for performing inservice testing inservice testing activities activities Weekly At least once per 7 days Monthly At least once per 31 days Quarterly or every 3 months At least once per 92 days Semiannually or every 6 months At least once per 184 days Every 9 months At least once per 276 days Yearly or annually At least once per 366 days Biennially or every 2 years At least once per 731 days

b. The provisions of SR 3.0.2'are applicable to the above required' Frequencies for performing inservice testing activities,

c. The provisions of SR 3.0.3 are applicable to inservice testing activities, and

d. Nothing in the ASME Boiler and Pressure Vessel Code shall be construed to supersede the requirements of any TS.

5.5.9 Steam Generator (SG)GancProgram 5.5.10 Secondary Water Chemistry Proa ram This program provides controls for monitoring secondary water chemistry to inhibit SG tube degradation and low pressure turbine disc stress corrosion cracking. The program shall include:

a. Identification of a sampling schedule for the critical variables and control points for these variables,

b. Identification of the procedures used to measure the values of the critical variables, BWOG STS 5.5 - 5 Rev. 2, 04/30/01

TSTF-449, Rev. 2 Reporting Requirements 5.6 5.6 Reporting Requirements 5.6.7 Post Accident Monitoring Report (continued) monitoring, the cause of the inoperability, and the plans and schedule for restoring the instrumentation channels of the Function to OPERABLE status.

5.6.8 [Tendon Surveillance ReDort Any abnormal degradation of the containment structure detected during the tests required by the Pre-stressed Concrete Containment Tendon Surveillance Program shall be reported to the NRC within 30 days. The report shall include a description of the tendon condition, the condition of the concrete (especially at tendon anchorages), the inspection procedures, the tolerances on cracking, and the corrective action taken. ]

5.6.9 Steam Generator Tube Inspection Report EVIEWER'S NOTES -

1. Reports required b e Licensee's current licensing basis regarding stean/

generator tube rveillance requirements shall be included here. An 6 approprt ministrative controls format should be used.

2. The reports may be required covering inspection, test, and intenance vities. These reports are determined on an individual b s for each unit and their preparation and submittal are designated in th echnical Specifications.

REVISION HISTORY REVISION TSTF DESCRIPTION APPROVED 2.1 TSTF419 Revise PTLR Definition and References in 03/21/02 ISTS 5.6.6, RCS PTLR BWOG STS 5.6 -5 Rev. 2.1, 03/21/02

TSTF-449, Rev. 2 Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.8 Inservice Testing Program (continued)

ASME Boiler and Pressure Vessel Code and applicable Required Frequencies for Addenda terminology for performing inservice testing inservice testing activities activities Monthly At least once per 31 days Quarterly or every 3 months At least once per 92 days Semiannually or every 6 months At least once per 184 days Every 9 months At least once per 276 days Yearly or annually At least once per 366 days Biennially or every 2 years At least once per 731 days

b. The provisions of SR 3.0.2 are applicable to the above required Frequencies for performing inservice testing activities,

c. The provisions of SR 3.0.3 are applicable to inservice testing activities, and

d. Nothing in the ASME Boiler and Pressure Vessel Code shall be construed to supersede the requirements of any TS.

5.5.9 Steam Generator (SG) ncoProgram

- REVIEWER'S NOTE -

The Licensee's curre icensing basis steam generator tube surve nce q requirements shale relocated from the LCO and included hereAn appropriate ad nistrative controls program format should be sed.

The p isions of SR 3.0.2 are applicable to the SG Tu Surveillance Program tes requencies.

5.5.10 Secondary Water Chemistry Program This program provides controls for monitoring secondary water chemistry to inhibit SG tube degradation and low pressure turbine disc stress corrosion cracking. The program shall include:

a. Identification of a sampling schedule for the critical variables and control points for these variables,

b. Identification of the procedures used to measure the values of the critical variables, WOG STS 5.5- 6 Rev. 2, 04/30/01

TSTF-449, Rev. 2 Reporting Requirements 5.6 5.6 Reporting Requirements 5.6.7 Post Accident Monitoring Report When a report is required by Condition B or G of LCO 3.3.[3], "Post Accident Monitoring (PAM) Instrumentation," a report shall be submitted within the following 14 days. The report shall outline the preplanned alternate method of monitoring, the cause of the inoperability, and the plans and schedule for restoring the instrumentation channels of the Function to OPERABLE status.

5.6.8 [Tendon Surveillance Report Any abnormal degradation of the containment structure detected during the tests required by the Pre-stressed Concrete Containment Tendon Surveillance Program shall be reported to the NRC within 30 days. The report shall include a description of the tendon condition, the condition of the concrete (especially at tendon anchorages), the inspection procedures, the tolerances on cracking, and the corrective action taken. ]

5.6.9 [Steam Generator Tube Inspection Reportl

/- REVIEWER'S NOTES -

1. Reports require ythe Licensee's current licensing basis regar g steam generator tu?!`surveillance requirements shall be included he . An

- appropri administrative controls format should be used.

2. T e reports may be required covering inspection, t, and maintenance ctivities. These reports are determined on an in idual basis for each unit and their preparation and submittal are design d in the Technical Specifications.

REVISION HISTORY REVISION TSTF DESCRIPTION APPROVED 2.1 TSTF-419 Revise PTLR Definition and References in 03/21/02 ISTS 5.6.6, RCS PTLR WOG STS 5.6 -5 Rev. 2.1, 03/21/02

TSTF-449 Rev 2 Programs and 4anuals 5.5 5.5 Programs and Manuals 5.5.8 Inservice Testing Program (continued)

ASME Boiler and Pressure Vessel Code and applicable Required Frequencies for Addenda terminology for performing inservice testing inservice testing activities activities Weekly At least once per 7 days Monthly At least once per 31 days Quarterly or every 3 months At least once per 92 days Semiannually or every 6 months At least once per 184 days Every 9 months At least once per 276 days Yearly or annually At least once per 366 days Biennially or every 2 years At least once per 731 days

b. The provisions of SR 3.0.2 are applicable to the above required Frequencies for performing inservice testing activities,

c. The provisions of SR 3.0.3 are applicable to inservice testing activities, and

d. Nothing in the ASME Boiler and Pressure Vessel Code shall be construed to supersede the requirements of any TS.

5.5.9 Steam Generator (SG)rTubaeurv ;ance~roqram

,z=z=w-- EVIEWER'S NOTE -

/ The LiceLnsee's current requirerr ients shall nsing basis steam generator tube su relocated from the LCO and included h . An lance appropri ate ad piffistrative controls program format should~ used.

uisions of SR 3.0.2 are applicable to the SG be Surveillance Program uencies.

5.5.10 Secondary Water Chemistry Program This program provides controls for monitoring secondary water chemistry to inhibit SG tube degradation and low pressure turbine disc stress corrosion cracking. The program shall include:

a. Identification of a sampling schedule for the critical variables and control points for these variables, CEOG STS 5.5 - 5 Rev. 2, 04/30/01

TSTF-449, Rev. 2 Reporting Requirements 5.6 5.6 Reporting Requirements 5.6.7 Post Accident Monitoring Report (continued) monitoring, the cause of the inoperability, and the plans and schedule for restoring the instrumentation channels of the Function to OPERABLE status.

5.6.8 Tendon Surveillance Report

[ Any abnormal degradation of the containment structure detected during the tests required by the Pre-stressed Concrete Containment Tendon Surveillance Program shall be reported to the NRC within 30 days. The report shall include a description of the tendon condition, the condition of the concrete (especially at tendon anchorages), the inspection procedures, the tolerances on cracking, and the corrective action taken. l 5.6.9 Steam Generator Tube Inspector Report I /

'I

/- REVIEWER'S NOTES -

1. Reports required,bg`the Licensee's current licensing basis regardir,4steam generator tube-surveillance requirements shall be included here An appropriatekadministrative controls format should be used.

2. Tye~ereports may be required covering inspection, te d maintenance I

,activities. These reports are determined on an indiv ual basis for each unit a' and their preparation and submittal are designate in the Technical k/ _-

Specifications.

zz:

CEOG STS 5.6- 5 Rev. 2, 04/30/01

TSTF-449, Rev.2 SG Tube Integrity 3.4.17 3.4 REACTOR COOLANT SYSTEM (RCS) 3.4.17 Steam Generator (SG) Tube Integrity LCO 3.4.17 SG tube integrity shall be maintained.

AND All SG tubes satisfying the tube repair criteria shall be plugged [or repaired] in accordance with the Steam Generator Program.

APPLICABILITY: MODES 1, 2, 3, and 4.

ACTIONS Separate Condition entry is allowed for each SG tube.

CONDITION REQUIRED ACTION COMPLETION TIME A. One or more SG tubes A.1 Verify tube integrity of the 7 days satisfying the tube repair affected tube(s) is criteria and not plugged maintained until the next

[or repaired] in inspection.

accordance with the Steam Generator AND Program.

A.2 Plug [or repair] the affected Prior to entering tube(s) in accordance with MODE 4 following the the Steam Generator next refueling outage Program. or SG tube inspection B. Required Action and B.1 Be in MODE 3. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months associated Completion Time of Condition A not AND met.

B.2 Be in MODE 5. 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months OR SG tube integrity not maintained.

BWOG STS 3.4.1 7-1 Rev. X.X

TSTF-449, Rev.2 SG Tube Integrity 3.4.17 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.17.1 Verify SG tube integrity in accordance with the In accordance Steam Generator Program. with the Steam Generator Program SR 3.4.17.2 Verify that each inspected SG tube that satisfies the Prior to entering tube repair criteria is plugged [or repaired] in MODE 4 following accordance with the Steam Generator Program. a SG tube inspection BWOG STS 3.4.17-2 Rev. X.X

TSTF-449, Rev. 2 SG Tube Integrity B 3.4.17 B 3.4 REACTOR COOLANT SYSTEM (RCS)

B 3.4.17 Steam Generator (SG) Tube Integrity BASES BACKGROUND Steam generator (SG) tubes are small diameter, thin walled tubes that carry primary coolant through the primary to secondary heat exchangers.

The SG tubes have a number of important safety functions. Steam generator tubes are an integral part of the reactor coolant pressure boundary (RCPB) and, as such, are relied on to maintain the primary system's pressure and inventory. The SG tubes isolate the radioactive fission products in the primary coolant from the secondary system. In addition, as part of the RCPB, the SG tubes are unique in that they act as the heat transfer surface between the primary and secondary systems to remove heat from the primary system. This Specification addresses only the RCPB integrity function of the SG. The SG heat removal function is addressed by LCO 3.4.4,'RCS Loops - MODES I and 2,LCO 3.4.5,'RCS Loops - MODE 3,"LCO 3.4.6,"RCS Loops - MODE 4,and LCO 3.4.7,"RCS Loops - MODE 5, Loops Filled.

SG tube integrity means that the tubes are capable of performing their intended RCPB safety function consistent with the licensing basis, including applicable regulatory requirements.

Steam generator tubing is subject to a variety of degradation mechanisms. Steam generator tubes may experience tube degradation related to corrosion phenomena, such as wastage, pitting, intergranular attack, and stress corrosion cracking, along with other mechanically induced phenomena such as denting and wear. These degradation mechanisms can impair tube integrity if they are not managed effectively.

The SG performance criteria are used to manage SG tube degradation.

Specification 5.5.9,"Steam Generator (SG) Program, requires that a program be established and implemented to ensure that SG tube integrity is maintained. Pursuant to Specification 5.5.9, tube integrity is maintained when the SG performance criteria are met. There are three SG performance criteria: structural integrity, accident induced leakage, and operational LEAKAGE. The SG performance criteria are described in Specification 5.5.9. Meeting the SG performance criteria provides reasonable assurance of maintaining tube integrity at normal and accident conditions.

The processes used to meet the SG performance criteria are defined by the Steam Generator Program Guidelines (Ref. 1).

Rev. X.X B 3.4.17-1 BWOG STSSTS B 3.4.17-1 Rev. X.X

TSTF-449, Rev. 2 SG Tube Integrity B 3.4.17 BASES APPLICABLE The steam generator tube rupture (SGTR) accident is the limiting design SAFETY basis event for SG tubes and avoiding an SGTR is the basis for this ANALYSES Specification. The analysis of a SGTR event assumes a bounding primary to secondary LEAKAGE rate equal to the operational LEAKAGE rate limits in LCO 3.4.13,ORCS Operational LEAKAGE,'plus the leakage rate associated with a double-ended rupture of a single tube. The accident analysis for a SGTR assumes the contaminated secondary fluid is only briefly released to the atmosphere via safety valves and the majority is discharged to the main condenser.

The analysis for design basis accidents and transients other than a SGTR assume the SG tubes retain their structural integrity (i.e., they are assumed not to rupture.) In these analyses, the steam discharge to the atmosphere is based on the total primary to secondary LEAKAGE from all SGs of [1 gallon per minute] or is assumed to increase to [1 gallon per minute] as a result of accident induced conditions. For accidents that do not involve fuel damage, the primary coolant activity level of DOSE EQUIVALENT 1-131 is assumed to be equal to the LCO 3.4.16,"RCS Specific Activity,'limits. For accidents that assume fuel damage, the primary coolant activity is a function of the amount of activity released from the damaged fuel. The dose consequences of these events are within the limits of GDC 19 (Ref. 2), 10 CFR 100 (Ref. 3) or the NRC approved licensing basis (e.g., a small fraction of these limits).

Steam generator tube integrity satisfies Criterion 2 of 10 CFR 50.36(c)(2)(ii).

LCO The LCO requires that SG tube integrity be maintained. The LCO also requires that all SG tubes that satisfy the repair criteria be plugged [or repaired] in accordance with the Steam Generator Program.

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

In the context of this Specification, a SG tube is defined as the entire length of the tube, including the tube wall [and any repairs made to it],

between the tube-to-tubesheet weld at the tube inlet and the tube-to-tubesheet weld at the tube outlet. The tube-to-tubesheet weld is not considered part of the tube.

A SG tube has tube integrity when it satisfies the SG performance criteria.

The SG performance criteria are defined in Specification 5.5.9,"Steam Generator Program, and describe acceptable SG tube performance. The Steam Generator Program also provides the evaluation process for determining conformance with the SG performance criteria.

BWOG STS B 3.4.17-2 Rev. X.X

TSTF-449, Rev. 2 SG Tube Integrity B 3.4.17 BASES LCO (continued) There are three SG performance criteria: structural integrity, accident induced leakage, and operational LEAKAGE. Failure to meet any one of these criteria is considered failure to meet the LCO.

The structural integrity performance criterion provides a margin of safety against tube burst or collapse under normal and accident conditions, and ensures structural integrity of the SG tubes under all anticipated transients included in the design specification. Tube burst is defined as, "The gross structural failure of the tube wall. The condition typically corresponds to an unstable opening displacement (e.g., opening area increased in response to constant pressure) accompanied by ductile (plastic) tearing of the tube material at the ends of the degradations Tube collapse is defined as,"For the load displacement curve for a given structure, collapse occurs at the top of the load versus displacement curve where the slope of the curve becomes zero"The structural integrity performance criterion provides guidance on assessing loads that significant affect burst or collapse. In that context, the term'significantl9 is defined as"An accident loading condition other than differential pressure is considered significant when the addition of such loads in the assessment of the structural integrity performance criterion could cause a lower structural limit or limiting burst/collapse condition to be established" The determination of whether thermal loads are primary or secondary loads is based on the ASME definition in which secondary loads are self-limiting and will not cause failure under single load application. For tube integrity evaluations, except for circumferential degradation, axial thermal loads are classified as secondary loads. For circumferential degradation, the classification of axial thermal loads as primary or secondary loads will be evaluated on a case-by-case basis. The division between primary and secondary classifications will be based on detailed analysis and/or testing.

Structural integrity requires that the primary membrane stress intensity in a tube not exceed the yield strength for all ASME Code,Section III, Service Level A (normal operating conditions) and Service Level B (upset or abnormal conditions) transients included in the design specification.

This includes safety factors and applicable design basis loads based on ASME Code,Section III, Subsection NB (Ref. 4) and Draft Regulatory Guide 1.121 (Ref. 5).

The accident induced leakage performance criterion ensures that the primary to secondary LEAKAGE caused by a design basis accident, other than a SGTR, is within the accident analysis assumptions. The accident analysis assumes that accident induced leakage does not exceed [1 gpm per SG, except for specific types of degradation at specific locations where the NRC has approved greater accident induced leakage.] The accident induced leakage rate includes any primary to secondary LEAKAGE existing prior to the accident in addition to primary to secondary LEAKAGE induced during the accident.

Rev. X.X STS B 3.4.17-3 BWOG STS B 3.4.17-3 Rev. X.X

TSTF-449, Rev. 2 SG Tube Integrity B 3.4.17 BASES LCO (continued) The operational LEAKAGE performance criterion provides an observable indication of SG tube conditions during plant operation. The limit on operational LEAKAGE is contained in LCO 3.4.13,'RCS Operational LEAKAGE,'and limits primary to secondary LEAKAGE through any one SG to 150 gallons per day. This limit is based on the assumption that a single crack leaking this amount would not propagate to a SGTR under the stress conditions of a LOCA or a main steam line break. If this amount of LEAKAGE is due to more than one crack, the cracks are very small, and the above assumption is conservative.

APPLICABILITY Steam generator tube integrity is challenged when the pressure differential across the tubes is large. Large differential pressures across SG tubes can only be experienced in MODE 1, 2, 3, or 4.

RCS conditions are far less challenging in MODES 5 and 6 than during MODES 1, 2, 3, and 4. In MODES 5 and 6, primary to secondary differential pressure is low, resulting in lower stresses and reduced potential for LEAKAGE.

ACTIONS The ACTIONS are modified by a Note clarifying that the Conditions may be entered independently for each SG tube. This is acceptable because the Required Actions provide appropriate compensatory actions for each affected SG tube. Complying with the Required Actions may allow for continued operation, and subsequent affected SG tubes are governed by subsequent Condition entry and application of associated Required Actions.

A.1 and A.2 Condition A applies if it is discovered that one or more SG tubes examined in an inservice inspection satisfy the tube repair criteria but were not plugged [or repaired] in accordance with the Steam Generator Program as required by SR 3.4.17.2. An evaluation of SG tube integrity of the affected tube(s) must be made. Steam generator tube integrity is based on meeting the SG performance criteria described in the Steam Generator Program. The SG repair criteria define limits on SG tube degradation that allow for flaw growth between inspections while still providing assurance that the SG performance criteria will continue to be met. In order to determine if a SG tube that should have been plugged

[or repaired] has tube integrity, an evaluation must be completed that demonstrates that the SG performance criteria will continue to be met until the next SG tube inspection. The tube integrity determination is 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 SG tube inspection. If it is determined that tube integrity is not being maintained, Condition B applies.

Rev. X.X B 3.4.17-4 BWOG STS STS B 3.4.17-4 Rev. X.X

TSTF-449, Rev. 2 SG Tube Integrity B 3.4.17 BASES Actions (continued)

A Completion Time of 7 days is sufficient to complete the evaluation while minimizing the risk of plant operation with a SG tube that may not have tube integrity.

If the evaluation determines that the affected tube(s) have tube integrity, Required Action A.2 allows plant operation to continue until the next refueling outage or SG inspection provided the inspection interval continues to be supported by an operational assessment that reflects the affected tubes. However, the affected tube(s) must be plugged [or repaired] prior to entering MODE 4 following the next refueling outage or SG inspection. This Completion Time is acceptable since operation until the next inspection is supported by the operational assessment.

B.1 and B.2 If the Required Actions and associated Completion Times of Condition A are not met or if SG tube integrity is not being maintained, the reactor must be brought to MODE 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and MODE 5 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months .

The allowed Completion Times are reasonable, based on operating experience, to reach the desired plant conditions from full power conditions in an orderly manner and without challenging plant systems.

SURVEILLANCE SR 3.4.17.1 REQUIREMENTS During shutdown periods the SGs are inspected as required by this SR and the Steam Generator Program. NEI 97-06, Steam Generator Program Guidelines (Ref. 1), and its referenced EPRI Guidelines, establish the content of the Steam Generator Program. Use of the Steam Generator Program ensures that the inspection is appropriate and consistent with accepted industry practices.

During SG inspections a condition monitoring assessment of the SG tubes is performed. The condition monitoring assessment determines the "as founds condition of the SG tubes. The purpose of the condition monitoring assessment is to ensure that the SG performance criteria have been met for the previous operating period.

BWOG STS B 3.4.17-5 Rev. X.X

TSTF-449, Rev. 2 SG Tube Integrity B 3.4.17 BASES SURVEILLANCE REQUIREMENTS (continued)

The Steam Generator Program determines the scope of the inspection and the methods used to determine whether the tubes contain flaws satisfying the tube repair criteria. Inspection scope (i.e., which tubes or areas of tubing within the SG are to be inspected) is a function of existing and potential degradation locations. The Steam Generator Program also specifies the inspection methods to be used to find potential degradation.

Inspection methods are a function of degradation morphology, non-destructive examination (NDE) technique capabilities, and inspection locations.

The Steam Generator Program defines the Frequency of SR 3.4.17.1.

The Frequency is determined by the operational assessment and other limits in the SG examination guidelines (Ref. 6). The Steam Generator Program uses information on existing degradations and growth rates to determine an inspection Frequency that provides reasonable assurance that the tubing will meet the SG performance criteria at the next scheduled inspection. In addition, Specification 5.5.9 contains prescriptive requirements concerning inspection intervals to provide added assurance that the SG performance criteria will be met between scheduled inspections.

SR 3.4.1 7.2 During an SG inspection, any inspected tube that satisfies the Steam Generator Program repair criteria is [repaired or] removed from service by plugging. The tube repair criteria delineated in Specification 5.5.9 are intended to ensure that tubes accepted for continued service satisfy the SG performance criteria with allowance for error in the flaw size measurement and for future flaw growth. In addition, the tube repair criteria, in conjunction with other elements of the Steam Generator Program, ensure that the SG performance criteria will continue to be met until the next inspection of the subject tube(s). Reference 1 and Reference 7 provide guidance for performing operational assessments to verify that the tubes remaining in service will continue to meet the SG performance criteria.

[Steam generator tube repairs are only performed using approved repair methods as described in the Steam Generator Program.]

The Frequency of prior to entering MODE 4 following a SG inspection ensures that the Surveillance has been completed and all tubes meeting the repair criteria are plugged [or repaired] prior to subjecting the SG tubes to significant primary to secondary pressure differential.

Rev. X.X B 3.4.17-6 STS BWOG STS B 3.4.17-6 Rev. X.X

TSTF-449, Rev. 2 SG Tube Integrity B 3.4.17 REFERENCES 1. NEI 97-06,'Steam Generator Program Guidelines"

2. 10 CFR 50 Appendix A, GDC 19.

3. 10 CFR 100.

4. ASME Boiler and Pressure Vessel Code, Section 1II,Subsection NB.

5. Draft Regulatory Guide 1.121,"Basis for Plugging Degraded Steam Generator Tubes, August 1976.

6. EPRI TR-107569,Pressurized Water Reactor Steam Generator Examination Guidelines' Rev. X.X B 3.4.17-7 BWOG STS STS B 3.4.17-7 Rev. X.X

TSTF-449, Rev. 2 SG Tube Integrity 3.4.20 3.4 REACTOR COOLANT SYSTEM (RCS) 3.4.20 Steam Generator (SG) Tube Integrity LCO 3.4.20 SG tube integrity shall be maintained.

AND All SG tubes satisfying the tube repair criteria shall be plugged [or repaired] in accordance with the Steam Generator Program.

APPLICABILITY: MODES 1, 2, 3, and 4.

ACTIONS F IAT

- ---------------------------- I I Separate Condition entry is allowed for each SG tube.

CONDITION REQUIRED ACTION COMPLETION TIME A. One or more SG tubes A.1 Verify tube integrity of the 7 days satisfying the tube repair affected tube(s) is criteria and not plugged maintained until the next

[or repaired] in inspection.

accordance with the Steam Generator AND Program.

A.2 Plug [or repair] the affected Prior to entering tube(s) in accordance with MODE 4 following the the Steam Generator next refueling outage Program. or SG tube inspection B. Required Action and B.1 Be in MODE 3. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months associated Completion Time of Condition A not AND met.

B.2 Be in MODE 5. 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months OR SG tube integrity not maintained.

WOG STS 3.4.20-1 Rev. X.X

TSTF-449, Rev. 2 SG Tube Integrity 3.4.20 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.20.1 Verify SG tube integrity in accordance with the In accordance Steam Generator Program. with the Steam Generator Program SR 3.4.20.2 Verify that each inspected SG tube that satisfies the Prior to entering tube repair criteria is plugged [or repaired] in MODE 4 following accordance with the Steam Generator Program. a SG tube inspection WOG STS 3.4.20-2 Rev. X.X

TSTF-449, Rev. 2 SG Tube Integrity B 3.4.20 B 3.4 REACTOR COOLANT SYSTEM (RCS)

B 3.4.20 Steam Generator (SG) Tube Integrity BASES BACKGROUND Steam generator (SG) tubes are small diameter, thin walled tubes that carry primary coolant through the primary to secondary heat exchangers.

The SG tubes have a number of important safety functions. Steam generator tubes are an integral part of the reactor coolant pressure boundary (RCPB) and, as such, are relied on to maintain the primary system's pressure and inventory. The SG tubes isolate the radioactive fission products in the primary coolant from the secondary system. In addition, as part of the RCPB, the SG tubes are unique in that they act as the heat transfer surface between the primary and secondary systems to remove heat from the primary system. This Specification addresses only the RCPB integrity function of the SG. The SG heat removal function is addressed by LCO 3.4.4,"RCS Loops - MODES 1 and 2, LCO 3.4.5,"RCS Loops - MODE 3, LCO 3.4.6,"RCS Loops - MODE 4, and LCO 3.4.7,'RCS Loops - MODE 5, Loops Filled" SG tube integrity means that the tubes are capable of performing their intended RCPB safety function consistent with the licensing basis, including applicable regulatory requirements.

Steam generator tubing is subject to a variety of degradation mechanisms. Steam generator tubes may experience tube degradation related to corrosion phenomena, such as wastage, pitting, intergranular attack, and stress corrosion cracking, along with other mechanically induced phenomena such as denting and wear. These degradation mechanisms can impair tube integrity if they are not managed effectively.

The SG performance criteria are used to manage SG tube degradation.

Specification 5.5.9,"Steam Generator (SG) Program, requires that a program be established and implemented to ensure that SG tube integrity is maintained. Pursuant to Specification 5.5.9, tube integrity is maintained when the SG performance criteria are met. There are three SG performance criteria: structural integrity, accident induced leakage, and operational LEAKAGE. The SG performance criteria are described in Specification 5.5.9. Meeting the SG performance criteria provides reasonable assurance of maintaining tube integrity at normal and accident conditions.

The processes used to meet the SG performance criteria are defined by the Steam Generator Program Guidelines (Ref. 1).

Rev. X.X B 3.4.20-I WOG STS STS B 3.4.20-1 Rev. X.X

TSTF-449, Rev. 2 SG Tube Integrity B 3.4.20 BASES APPLICABLE The steam generator tube rupture (SGTR) accident is the limiting design SAFETY basis event for SG tubes and avoiding an SGTR is the basis for this ANALYSES Specification. The analysis of a SGTR event assumes a bounding primary to secondary LEAKAGE rate equal to the operational LEAKAGE rate limits in LCO 3.4.13,'RCS Operational LEAKAGE, plus the leakage rate associated with a double-ended rupture of a single tube. The accident analysis for a SGTR assumes the contaminated secondary fluid is only briefly released to the atmosphere via safety valves and the majority is discharged to the main condenser.

The analysis for design basis accidents and transients other than a SGTR assume the SG tubes retain their structural integrity (i.e., they are assumed not to rupture.) In these analyses, the steam discharge to the atmosphere is based on the total primary to secondary LEAKAGE from all SGs of [1 gallon per minute] or is assumed to increase to [1 gallon per minute] as a result of accident induced conditions. For accidents that do not involve fuel damage, the primary coolant activity level of DOSE EQUIVALENT 1-131 is assumed to be equal to the LCO 3.4.16,'RCS Specific Activity, limits. For accidents that assume fuel damage, the primary coolant activity is a function of the amount of activity released from the damaged fuel. The dose consequences of these events are within the limits of GDC 19 (Ref. 2), 10 CFR 100 (Ref. 3) or the NRC approved licensing basis (e.g., a small fraction of these limits).

Steam generator tube integrity satisfies Criterion 2 of 10 CFR 50.36(c)(2)(ii).

LCO The LCO requires that SG tube integrity be maintained. The LCO also requires that all SG tubes that satisfy the repair criteria be plugged [or repaired] in accordance with the Steam Generator Program.

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

In the context of this Specification, a SG tube is defined as the entire length of the tube, including the tube wall land any repairs made to it],

between the tube-to-tubesheet weld at the tube inlet and the tube-to-tubesheet weld at the tube outlet. The tube-to-tubesheet weld is not considered part of the tube.

A SG tube has tube integrity when it satisfies the SG performance criteria.

The SG performance criteria are defined in Specification 5.5.9,"Steam Generator Program, and describe acceptable SG tube performance. The Steam Generator Program also provides the evaluation process for determining conformance with the SG performance criteria.

Rev. X.X B 3.4.20-2 WOG STS STS B 3.4.20-2 Rev. X.X

TSTF-449, Rev. 2 SG Tube Integrity B 3.4.20 BASES LCO (continued) There are three SG performance criteria: structural integrity, accident induced leakage, and operational LEAKAGE. Failure to meet any one of these criteria is considered failure to meet the LCO.

The structural integrity performance criterion provides a margin of safety against tube burst or collapse under normal and accident conditions, and ensures structural integrity of the SG tubes under all anticipated transients included in the design specification. Tube burst is defined as,

'The gross structural failure of the tube wall. The condition typically corresponds to an unstable opening displacement (e.g., opening area increased in response to constant pressure) accompanied by ductile (plastic) tearing of the tube material at the ends of the degradation' Tube collapse is defined as,BFor the load displacement curve for a given structure, collapse occurs at the top of the load versus displacement curve where the slope of the curve becomes zeroThe structural integrity performance criterion provides guidance on assessing loads that significant affect burst or collapse. In that context, the term 'significantl9' is defined as"An accident loading condition other than differential pressure is considered significant when the addition of such loads in the assessment of the structural integrity performance criterion could cause a lower structural limit or limiting burst/collapse condition to be established.'

The determination of whether thermal loads are primary or secondary loads is based on the ASME definition in which secondary loads are self-limiting and will not cause failure under single load application. For tube integrity evaluations, except for circumferential degradation, axial thermal loads are classified as secondary loads. For circumferential degradation, the classification of axial thermal loads as primary or secondary loads will be evaluated on a case-by-case basis. The division between primary and secondary classifications will be based on detailed analysis and/or testing.

Structural integrity requires that the primary membrane stress intensity in a tube not exceed the yield strength for all ASME Code,Section III, Service Level A (normal operating conditions) and Service Level B (upset or abnormal conditions) transients included in the design specification.

This includes safety factors and applicable design basis loads based on ASME Code, Section 1II,Subsection NB (Ref. 4) and Draft Regulatory Guide 1.121 (Ref. 5).

The accident induced leakage performance criterion ensures that the primary to secondary LEAKAGE caused by a design basis accident, other than a SGTR, is within the accident analysis assumptions. The accident analysis assumes that accident induced leakage does not exceed [1 gpm per SG, except for specific types of degradation at specific locations where the NRC has approved greater accident induced leakage.] The accident induced leakage rate includes any primary to secondary LEAKAGE existing prior to the accident in addition to primary to secondary LEAKAGE induced during the accident.

WOG STS B 3.4.20-3 Rev. X.X

TSTF-449, Rev. 2 SG Tube Integrity B 3.4.20 BASES LCO (continued) The operational LEAKAGE performance criterion provides an observable indication of SG tube conditions during plant operation. The limit on operational LEAKAGE is contained in LCO 3.4.13,"RCS Operational LEAKAGE,:and limits primary to secondary LEAKAGE through any one SG to 150 gallons per day. This limit is based on the assumption that a single crack leaking this amount would not propagate to a SGTR under the stress conditions of a LOCA or a main steam line break. If this amount of LEAKAGE is due to more than one crack, the cracks are very small, and the above assumption is conservative.

APPLICABILITY Steam generator tube integrity is challenged when the pressure differential across the tubes is large. Large differential pressures across SG tubes can only be experienced in MODE 1, 2, 3, or 4.

RCS conditions are far less challenging in MODES 5 and 6 than during MODES 1, 2, 3, and 4. In MODES 5 and 6, primary to secondary differential pressure is low, resulting in lower stresses and reduced potential for LEAKAGE.

ACTIONS The ACTIONS are modified by a Note clarifying that the Conditions may be entered independently for each SG tube. This is acceptable because the Required Actions provide appropriate compensatory actions for each affected SG tube. Complying with the Required Actions may allow for continued operation, and subsequent affected SG tubes are governed by subsequent Condition entry and application of associated Required Actions.

A.1 and A.2 Condition A applies if it is discovered that one or more SG tubes examined in an inservice inspection satisfy the tube repair criteria but were not plugged [or repaired] in accordance with the Steam Generator Program as required by SR 3.4.20.2. An evaluation of SG tube integrity of the affected tube(s) must be made. Steam generator tube integrity is based on meeting the SG performance criteria described in the Steam Generator Program. The SG repair criteria define limits on SG tube degradation that allow for flaw growth between inspections while still providing assurance that the SG performance criteria will continue to be met. In order to determine if a SG tube that should have been plugged

[or repaired] has tube integrity, an evaluation must be completed that demonstrates that the SG performance criteria will continue to be met until the next SG tube inspection. The tube integrity determination is 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 SG tube inspection. If it is determined that tube integrity is not being maintained, Condition B applies.

WOG STS B 3.4.20-4 Rev. X.X

TSTF-449, Rev. 2 SG Tube Integrity B 3.4.20 BASES Actions (continued)

A Completion Time of 7 days is sufficient to complete the evaluation while minimizing the risk of plant operation with a SG tube that may not have tube integrity.

If the evaluation determines that the affected tube(s) have tube integrity, Required Action A.2 allows plant operation to continue until the next refueling outage or SG inspection provided the inspection interval continues to be supported by an operational assessment that reflects the affected tubes. However, the affected tube(s) must be plugged [or repaired] prior to entering MODE 4 following the next refueling outage or SG inspection. This Completion Time is acceptable since operation until the next inspection is supported by the operational assessment.

B.1 and B.2 If the Required Actions and associated Completion Times of Condition A are not met or if SG tube integrity is not being maintained, the reactor must be brought to MODE 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and MODE 5 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months .

The allowed Completion Times are reasonable, based on operating experience, to reach the desired plant conditions from full power conditions in an orderly manner and without challenging plant systems.

SURVEILLANCE SR 3.4.20.1 REQUIREMENTS During shutdown periods the SGs are inspected as required by this SR and the Steam Generator Program. NEI 97-06, Steam Generator Program Guidelines (Ref. 1), and its referenced EPRI Guidelines, establish the content of the Steam Generator Program. Use of the Steam Generator Program ensures that the inspection is appropriate and consistent with accepted industry practices.

During SG inspections a condition monitoring assessment of the SG tubes is performed. The condition monitoring assessment determines the gas found'condition of the SG tubes. The purpose of the condition monitoring assessment is to ensure that the SG performance criteria have been met for the previous operating period.

WOG STS B 3.4.20-5 Rev. X.X

TSTF-449, Rev. 2 SG Tube Integrity B 3.4.20 BASES SURVEILLANCE REQUIREMENTS (continued)

The Steam Generator Program determines the scope of the inspection and the methods used to determine whether the tubes contain flaws satisfying the tube repair criteria. Inspection scope (i.e., which tubes or areas of tubing within the SG are to be inspected) is a function of existing and potential degradation locations. The Steam Generator Program also specifies the inspection methods to be used to find potential degradation.

Inspection methods are a function of degradation morphology, non-destructive examination (NDE) technique capabilities, and inspection locations.

The Steam Generator Program defines the Frequency of SR 3.4.20.1.

The Frequency is determined by the operational assessment and other limits in the SG examination guidelines (Ref. 6). The Steam Generator Program uses information on existing degradations and growth rates to determine an inspection Frequency that provides reasonable assurance that the tubing will meet the SG performance criteria at the next scheduled inspection. In addition, Specification 5.5.9 contains prescriptive requirements concerning inspection intervals to provide added assurance that the SG performance criteria will be met between scheduled inspections.

SR 3.4.20.2 During an SG inspection, any inspected tube that satisfies the Steam Generator Program repair criteria is [repaired or] removed from service by plugging. The tube repair criteria delineated in Specification 5.5.9 are intended to ensure that tubes accepted for continued service satisfy the SG performance criteria with allowance for error in the flaw size measurement and for future flaw growth. In addition, the tube repair criteria, in conjunction with other elements of the Steam Generator Program, ensure that the SG performance criteria will continue to be met until the next inspection of the subject tube(s). Reference 1 and Reference 7 provide guidance for performing operational assessments to verify that the tubes remaining in service will continue to meet the SG performance criteria.

[Steam generator tube repairs are only performed using approved repair methods as described in the Steam Generator Program.]

The Frequency of prior to entering MODE 4 following a SG inspection ensures that the Surveillance has been completed and all tubes meeting the repair criteria are plugged [or repaired] prior to subjecting the SG tubes to significant primary to secondary pressure differential.

Rev. X.X B 3.4.20-6 WOG STS B 3.4.20-6 Rev. X.X

TSTF-449, Rev. 2 SG Tube Integrity B 3.4.20 REFERENCES 1. NEI 97-06, Steam Generator Program Guidelines"

2. 10 CFR 50 Appendix A, GDC 19.

3. 10 CFR 100.

4. ASME Boiler and Pressure Vessel Code,Section III, Subsection NB.

5. Draft Regulatory Guide 1.121,"Basis for Plugging Degraded Steam Generator Tubes, August 1976.

6. EPRI TR-1 07569,"Pressurized Water Reactor Steam Generator Examination Guidelines' WOG STS B 3.4.20-7 Rev. X.X

TSTF-449, Rev. 2 SG Tube Integrity 3.4.18 3.4 REACTOR COOLANT SYSTEM (RCS) 3.4.18 Steam Generator (SG) Tube Integrity LCO 3.4.18 SG tube integrity shall be maintained.

AND All SG tubes satisfying the tube repair criteria shall be plugged [or repaired] in accordance with the Steam Generator Program.

APPLICABILITY: MODES 1, 2, 3, and 4.

ACTIONS KII ^TCI V ILi I _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _

Separate Condition entry is allowed for each SG tube.

CONDITION REQUIRED ACTION COMPLETION TIME A. One or more SG tubes A.1 Verify tube integrity of the 7 days satisfying the tube repair affected tube(s) is criteria and not plugged maintained until the next

[or repaired] in inspection.

accordance with the Steam Generator AND Program.

A.2 Plug [or repair] the affected Prior to entering tube(s) in accordance with MODE 4 following the the Steam Generator next refueling outage Program. or SG tube inspection B. Required Action and B.1 Be in MODE 3. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months associated Completion Time of Condition A not AND met.

B.2 Be in MODE 5. 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months OR SG tube integrity not maintained.

CEOG STS 3.4. 18-1 Rev. X.X

TSTF-449, Rev. 2 SG Tube Integrity 3.4.18 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.18.1 Verify SG tube integrity in accordance with the In accordance Steam Generator Program. with the Steam Generator Program SR 3.4.18.2 Verify that each inspected SG tube that satisfies the Prior to entering tube repair criteria is plugged [or repaired] in MODE 4 following accordance with the Steam Generator Program. a SG tube inspection CEOG STS 3.4.1 8-2 Rev. X.X

TSTF-449, Rev. 2 SG Tube Integrity B 3.4.18 B 3.4 REACTOR COOLANT SYSTEM (RCS)

B 3.4.18 Steam Generator (SG) Tube Integrity BASES BACKGROUND Steam generator (SG) tubes are small diameter, thin walled tubes that carry primary coolant through the primary to secondary heat exchangers.

The SG tubes have a number of important safety functions. Steam generator tubes are an integral part of the reactor coolant pressure boundary (RCPB) and, as such, are relied on to maintain the primary system's pressure and inventory. The SG tubes isolate the radioactive fission products in the primary coolant from the secondary system. In addition, as part of the RCPB, the SG tubes are unique in that they act as the heat transfer surface between the primary and secondary systems to remove heat from the primary system. This Specification addresses only the RCPB integrity function of the SG. The SG heat removal function is addressed by LCO 3.4.4,"RCS Loops - MODES I and 2,'LCO 3.4.5,/RCS Loops - MODE 3,LCO 3.4.6,'RCS Loops - MODE 4,and LCO 3.4.7,"RCS Loops - MODE 5, Loops Filled.

SG tube integrity means that the tubes are capable of performing their intended RCPB safety function consistent with the licensing basis, including applicable regulatory requirements.

Steam generator tubing is subject to a variety of degradation mechanisms. Steam generator tubes may experience tube degradation related to corrosion phenomena, such as wastage, pitting, intergranular attack, and stress corrosion cracking, along with other mechanically induced phenomena such as denting and wear. These degradation mechanisms can impair tube integrity if they are not managed effectively.

The SG performance criteria are used to manage SG tube degradation.

Specification 5.5.9,"Steam Generator (SG) Program, requires that a program be established and implemented to ensure that SG tube integrity is maintained. Pursuant to Specification 5.5.9, tube integrity is maintained when the SG performance criteria are met. There are three SG performance criteria: structural integrity, accident induced leakage, and operational LEAKAGE. The SG performance criteria are described in Specification 5.5.9. Meeting the SG performance criteria provides reasonable assurance of maintaining tube integrity at normal and accident conditions.

The processes used to meet the SG performance criteria are defined by the Steam Generator Program Guidelines (Ref. 1).

3..18- Rev X.

CEOGSTS CEOG STS B 3.4.18-1 Rev. X.X

TSTF-449, Rev. 2 SG Tube Integrity B 3.4.18 BASES APPLICABLE The steam generator tube rupture (SGTR) accident is the limiting design SAFETY basis event for SG tubes and avoiding an SGTR is the basis for this ANALYSES Specification. The analysis of a SGTR event assumes a bounding primary to secondary LEAKAGE rate equal to the operational LEAKAGE rate limits in LCO 3.4.13,'RCS Operational LEAKAGE, plus the leakage rate associated with a double-ended rupture of a single tube. The accident analysis for a SGTR assumes the contaminated secondary fluid is only briefly released to the atmosphere via safety valves and the majority is discharged to the main condenser.

The analysis for design basis accidents and transients other than a SGTR assume the SG tubes retain their structural integrity (i.e., they are assumed not to rupture.) In these analyses, the steam discharge to the atmosphere is based on the total primary to secondary LEAKAGE from all SGs of [1 gallon per minute] or is assumed to increase to [1 gallon per minute] as a result of accident induced conditions. For accidents that do not involve fuel damage, the primary coolant activity level of DOSE EQUIVALENT 1-131 is assumed to be equal to the LCO 3.4.16,"RCS Specific Activity, limits. For accidents that assume fuel damage, the primary coolant activity is a function of the amount of activity released from the damaged fuel. The dose consequences of these events are within the limits of GDC 19 (Ref. 2), 10 CFR 100 (Ref. 3) or the NRC approved licensing basis (e.g., a small fraction of these limits).

Steam generator tube integrity satisfies Criterion 2 of 10 CFR 50.36(c)(2)(ii).

LCO The LCO requires that SG tube integrity be maintained. The LCO also requires that all SG tubes that satisfy the repair criteria be plugged [or repaired] .in accordance with the Steam Generator Program.

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

In the context of this Specification, a SG tube is defined as the entire length of the tube, including the tube wall [and any repairs made to it],

between the tube-to-tubesheet weld at the tube inlet and the tube-to-tubesheet weld at the tube outlet. The tube-to-tubesheet weld is not considered part of the tube.

A SG tube has tube integrity when it satisfies the SG performance criteria.

The SG performance criteria are defined in Specification 5.5.9,"Steam Generator Program, and describe acceptable SG tube performance. The Steam Generator Program also provides the evaluation process for determining conformance with the SG performance criteria.

Rev. X.X B 3.4.18-2 CEOG STS STS B 3.4.1 8-2 Rev. X.X

TSTF-449, Rev. 2 SG Tube Integrity B 3.4.18 BASES LCO (continued) There are three SG performance criteria: structural integrity, accident induced leakage, and operational LEAKAGE. Failure to meet any one of these criteria is considered failure to meet the LCO.

The structural integrity performance criterion provides a margin of safety against tube burst or collapse under normal and accident conditions, and ensures structural integrity of the SG tubes under all anticipated transients included in the design specification. Tube burst is defined as,

'The gross structural failure of the tube wall. The condition typically corresponds to an unstable opening displacement (e.g., opening area increased in response to constant pressure) accompanied by ductile (plastic) tearing of the tube material at the ends of the degradation' Tube collapse is defined as,'For the load displacement curve for a given structure, collapse occurs at the top of the load versus displacement curve where the slope of the curve becomes zero"The structural integrity performance criterion provides guidance on assessing loads that significant affect burst or collapse. In that context, the term significantlyf is defined as"An accident loading condition other than differential pressure is considered significant when the addition of such loads in the assessment of the structural integrity performance criterion could cause a lower structural limit or limiting burst/collapse condition to be established' The determination of whether thermal loads are primary or secondary loads is based on the ASME definition in which secondary loads are self-limiting and will not cause failure under single load application. For tube integrity evaluations, except for circumferential degradation, axial thermal loads are classified as secondary loads. For circumferential degradation, the classification of axial thermal loads as primary or secondary loads will be evaluated on a case-by-case basis. The division between primary and secondary classifications will be based on detailed analysis and/or testing.

Structural integrity requires that the primary membrane stress intensity in a tube not exceed the yield strength for all ASME Code, Section 1I1, Service Level A (normal operating conditions) and Service Level B (upset or abnormal conditions) transients included in the design specification.

This includes safety factors and applicable design basis loads based on ASME Code, Section 1I1,Subsection NB (Ref. 4) and Draft Regulatory Guide 1.121 (Ref. 5).

The accident induced leakage performance criterion ensures that the primary to secondary LEAKAGE caused by a design basis accident, other than a SGTR, is within the accident analysis assumptions. The accident analysis assumes that accident induced leakage does not exceed [1 gpm per SG, except for specific types of degradation at specific locations where the NRC has approved greater accident induced leakage.] The accident induced leakage rate includes any primary to secondary LEAKAGE existing prior to the accident in addition to primary to secondary LEAKAGE induced during the accident.

Rev. X.X B 3.4.18-3 CEOG STS STS B 3.4.18-3 Rev. X.X

TSTF-449, Rev. 2 SG Tube Integrity B 3.4.18 BASES LCO (continued) The operational LEAKAGE performance criterion provides an observable indication of SG tube conditions during plant operation. The limit on operational LEAKAGE is contained in LCO 3.4.13,'RCS Operational LEAKAGE, and limits primary to secondary LEAKAGE through any one SG to 150 gallons per day. This limit is based on the assumption that a single crack leaking this amount would not propagate to a SGTR under the stress conditions of a LOCA or a main steam line break. If this amount of LEAKAGE is due to more than one crack, the cracks are very small, and the above assumption is conservative.

APPLICABILITY Steam generator tube integrity is challenged when the pressure differential across the tubes is large. Large differential pressures across SG tubes can only be experienced in MODE 1, 2, 3, or 4.

RCS conditions are far less challenging in MODES 5 and 6 than during MODES 1, 2, 3, and 4. In MODES 5 and 6, primary to secondary differential pressure is low, resulting in lower stresses and reduced potential for LEAKAGE.

ACTIONS The ACTIONS are modified by a Note clarifying that the Conditions may be entered independently for each SG tube. This is acceptable because the Required Actions provide appropriate compensatory actions for each affected SG tube. Complying with the Required Actions may allow for continued operation, and subsequent affected SG tubes are governed by subsequent Condition entry and application of associated Required Actions.

A.1 and A.2 Condition A applies if it is discovered that one or more SG tubes examined in an inservice inspection satisfy the tube repair criteria but were not plugged [or repaired] in accordance with the Steam Generator Program as required by SR 3.4.18.2. An evaluation of SG tube integrity of the affected tube(s) must be made. Steam generator tube integrity is based on meeting the SG performance criteria described in the Steam Generator Program. The SG repair criteria define limits on SG tube degradation that allow for flaw growth between inspections while still providing assurance that the SG performance criteria will continue to be met. In order to determine if a SG tube that should have been plugged

[or repaired] has tube integrity, an evaluation must be completed that demonstrates that the SG performance criteria will continue to be met until the next SG tube inspection. The tube integrity determination is 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 SG tube inspection. If it is determined that tube integrity is not being maintained, Condition B applies.

Rev. X.X STS B 3.4.18-4 CEOG STS B 3.4.18-4 Rev. X.X

TSTF-449, Rev. 2 SG Tube Integrity B 3.4.18 BASES Actions (continued)

A Completion Time of 7 days is sufficient to complete the evaluation while minimizing the risk of plant operation with a SG tube that may not have tube integrity.

If the evaluation determines that the affected tube(s) have tube integrity, Required Action A.2 allows plant operation to continue until the next refueling outage or SG inspection provided the inspection interval continues to be supported by an operational assessment that reflects the affected tubes. However, the affected tube(s) must be plugged [or repaired] prior to entering MODE 4 following the next refueling outage or SG inspection. This Completion Time is acceptable since operation until the next inspection is supported by the operational assessment.

B.1 and B.2 If the Required Actions and associated Completion Times of Condition A are not met or if SG tube integrity is not being maintained, the reactor must be brought to MODE 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and MODE 5 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months .

The allowed Completion Times are reasonable, based on operating experience, to reach the desired plant conditions from full power conditions in an orderly manner and without challenging plant systems.

SURVEILLANCE SR 3.4.18.1 REQUIREMENTS During shutdown periods the SGs are inspected as required by this SR and the Steam Generator Program. NEI 97-06, Steam Generator Program Guidelines (Ref. 1), and its referenced EPRI Guidelines, establish the content of the Steam Generator Program. Use of the Steam Generator Program ensures that the inspection is appropriate and consistent with accepted industry practices.

During SG inspections a condition monitoring assessment of the SG tubes is performed. The condition monitoring assessment determines the

'as founds condition of the SG tubes. The purpose of the condition monitoring assessment is to ensure that the SG performance criteria have been met for the previous operating period.

CEOG STS B 3.4.18-5 Rev. X.X

TSTF-449, Rev. 2 SG Tube Integrity B 3.4.18 BASES SURVEILLANCE REQUIREMENTS (continued)

The Steam Generator Program determines the scope of the inspection and the methods used to determine whether the tubes contain flaws satisfying the tube repair criteria. Inspection scope (i.e., which tubes or areas of tubing within the SG are to be inspected) is a function of existing and potential degradation locations. The Steam Generator Program also specifies the inspection methods to be used to find potential degradation.

Inspection methods are a function of degradation morphology, non-destructive examination (NDE) technique capabilities, and inspection locations.

The Steam Generator Program defines the Frequency of SR 3.4.18.1.

The Frequency is determined by the operational assessment and other limits in the SG examination guidelines (Ref. 6). The Steam Generator Program uses information on existing degradations and growth rates to determine an inspection Frequency that provides reasonable assurance that the tubing will meet the SG performance criteria at the next scheduled inspection. In addition, Specification 5.5.9 contains prescriptive requirements concerning inspection intervals to provide added assurance that the SG performance criteria will be met between scheduled inspections.

SR 3.4.18.2 During an SG inspection, any inspected tube that satisfies the Steam Generator Program repair criteria is [repaired or] removed from service by plugging. The tube repair criteria delineated in Specification 5.5.9 are intended to ensure that tubes accepted for continued service satisfy the SG performance criteria with allowance for error in the flaw size measurement and for future flaw growth. In addition, the tube repair criteria, in conjunction with other elements of the Steam Generator Program, ensure that the SG performance criteria will continue to be met until the next inspection of the subject tube(s). Reference 1 and Reference 7 provide guidance for performing operational assessments to verify that the tubes remaining in service will continue to meet the SG performance criteria.

[Steam generator tube repairs are only performed using approved repair methods as described in the Steam Generator Program.]

The Frequency of prior to entering MODE 4 following a SG inspection ensures that the Surveillance has been completed and all tubes meeting the repair criteria are plugged [or repaired] prior to subjecting the SG tubes to significant primary to secondary pressure differential.

CEOG STS B 3.4.18-6 Rev. X.X

TSTF-449, Rev. 2 SG Tube Integrity B 3.4.18 REFERENCES 1. NEI 97-06, Steam Generator Program Guidelines'

2. 10 CFR 50 Appendix A, GDC 19.

3. 10 CFR 100.

4. ASME Boiler and Pressure Vessel Code,Section III, Subsection NB.

5. Draft Regulatory Guide 1.121,"Basis for Plugging Degraded Steam Generator Tubes, August 1976.

6. EPRI TR-107569,"Pressurized Water Reactor Steam Generator Examination Guidelines" CEOG STS B 3.4.18-7 Rev. X.X

TSTF-449, Rev. 2 RCS Loops - MODE 3 B 3.4.5 BASES LCO (continued) natural circulation flow provides adequate removal. A minimum of one running RCP meets the LCO requirement for one loop in operation.

The Note permits a limited period of operation without RCPs. All RCPs may not be in operation for s 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months per 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months period for the transition to or from the Decay Heat Removal (DHR) System, and otherwise may be de-energized for s 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months per 8 hour9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months period. This means that natural circulation has been established. When in natural circulation, boron reduction with coolant at boron concentrations less than required to assure the SDM of LCO 3.1.1, is prohibited because an even concentration distribution throughout the RCS cannot be ensured. Core outlet temperature is to be maintained at least [10]0F below the saturation temperature so that no vapor bubble may form and possibly cause a natural circulation flow obstruction.

In MODES 3, 4, and 5, it is sometimes necessary to stop all RCP or DHR pump forced circulation (e.g., change operation from one DHR train to the other, to perform surveillance or startup testing, to perform the transition to and from DHR System cooling, or to avoid operation below the RCP minimum net positive suction head limit). The time period is acceptable because natural circulation is adequate for heat removal, or the reactor coolant temperature can be maintained subcooled and boron stratification affecting reactivity control is not expected.

An OPERABLE RCS loop consists of at least one OPERABLE RCP and an SG that rOPERABLE(in Vance with team Generato-Tbe)

. An RCP is OPERA=C if it is capable of being powered and is able to provide forced flow if required.

APPLICABILITY In MODE 3, the heat load is lower than at power; therefore, one RCS loop in operation is adequate for transport and heat removal. A second RCS loop is required to be OPERABLE but not in operation for redundant heat removal capability.

Operation in other MODES is covered by:

LCO 3.4.4, "RCS Loops - MODES 1 and 2,"

LCO 3.4.6, "RCS Loops - MODE 4,"

LCO 3.4.7, "RCS Loops - MODE 5, Loops Filled,"

LCO 3.4.8, "RCS Loops - MODE 5, Loops Not Filled,"

LCO 3.9.4, "Decay Heat Removal (DHR) and Coolant Circulation - High Water Level" (MODE 6), and BWOG STS B 3.4.5 - 2 Rev. 2, 04/30/01

TSTF-449, Rev. 2 RCS Loops - MODE 4 B 3.4.6 BASES LCO (continued)

The Note also permits the DHR pumps to be stopped for s 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months per 8 hour9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months period. When the DHR pumps are stopped, no alternate heat removal path exists, unless the RCS and SGs have been placed in service in forced or natural circulation. The response of the RCS without the DHR System depends on the core decay heat load and the length of time that the DHR pumps are stopped. As decay heat diminishes, the effects on RCS temperature and pressure diminish. Without cooling by DHR, higher heat loads will cause the reactor coolant temperature and pressure to increase at a rate proportional to the decay heat load.

Because pressure can increase, the applicable system pressure limits (pressure and temperature (PIT) or low temperature overpressure protection (LTOP) limits) must be observed and forced DHR flow or heat removal via the SGs must be re-established prior to reaching the pressure limit. The circumstances for stopping both DHR trains are to be limited to situations where:

a. Pressure and pressure and temperature increases can be maintained well within the allowable pressure (PIT and LTOP) and 10'F subcooling limits or

b. An alternate heat removal path through the SG is in operation.

An OPERABLE RCS loop consists of at eat one OPERABLE RCP and an SG that is OPERABLE n amf65nce with t am Gen ube (S -uNRc ogra.

Similarly for the DHR System, an OPERABLE DHR loop is comprised of the OPERABLE DHR pump(s) capable of providing forced flow to the DHR heat exchanger(s). DHR pumps are OPERABLE if they are capable of being powered and are able to provide flow if required.

APPLICABILITY In MODE 4, this LCO applies because it is possible to remove core decay heat and to provide proper boron mixing with either the RCS loops and SGs or the DHR System.

Operation in other MODES is covered by:

LCO 3.4.4, "RCS Loops - MODES 1 and 2,"

LCO 3.4.5, "RCS Loops - MODE 3,"

LCO 3.4.7, "RCS Loops - MODE 5, Loops Filled,"

LCO 3.4.8, "RCS Loops - MODE 5, Loops Not Filled,"

LCO 3.9.4, "Decay Heat Removal (DHR) and Coolant Circulation -

High Water Level" (MODE 6), and BWOG STS B 3.4.6 - 2 Rev. 2, 04/30/01

TSTF-449, Rev. 2 RCS Loops - MODE 5, Loops Filled B 3.4.7 BASES LCO (continued)

Note 2 allows one DHR loop to be inoperable for a period of up to 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months provided that the other loop is OPERABLE and in operation. This permits periodic surveillance tests to be performed on the inoperable loop during the only time when such testing is safe and possible.

Note 3 provides for an orderly transition from MODE 5 to MODE 4 during a planned heatup by permitting DHR loops to not be in operation when at least one RCP is in operation. This Note provides for the transition to MODE 4 where an RCP is permitted to be in operation and replaces the RCS circulation function provided by the DHR loops.

An OPERABLE DHR loop is composed of an OPERABLE DHR pump and an OPERABLE DHR heat exchanger.

DHR pumps are OPERABLE if they are capable of being powered and are able to provide flow if required. A gP L SG can perform as a heat sink when it has an adequate water level and is OPERABLE Mii accpFdSnce wih he StorT 7ra APPLICABILITY In MODE 5 with loops filled, forced circulation is provided by this LCO to remove decay heat from the core and to provide proper boron mixing.

One loop of DHR provides sufficient circulation for these purposes.

Operation in other MODES is covered by:

LCO 3.4.4, "RCS Loops - MODES 1 and 2,"

LCO 3.4.5, "RCS Loops - MODE 3,"

LCO 3.4.6, "RCS Loops - MODE 4,"

LCO 3.4.8, "RCS Loops - MODE 5, Loops Not Filled,"

LCO 3.9.4, "Decay Heat Removal (DHR) and Coolant Circulation -

High Water Level" (MODE 6), and LCO 3.9.5, "Decay Heat Removal (DHR) and Coolant Circulation -

Low Water Level" (MODE 6).

ACTIONS A.I. A.2. B.1. and B.2 If one DHR loop is OPERABLE and any required SG has secondary side water level < [50]%, redundancy for heat removal is lost. Action must be initiated to restore the inoperable (non-operating) DHR loop to OPERABLE status or initiate action to restore the secondary side water level in the SGs, and action must be taken immediately. Either Required Action will restore redundant decay heat removal paths. The immediate BWOG STS B 3.4.7 - 3 Rev. 2, 04/30/01

TSTF-449, Rev. 2 RCS Loops - MODES 1 and 2 B 3.4.4 BASES APPLICABLE SAFETY ANALYSES (continued) safety analyses are based on initial conditions at high core power or zero power. The accident analyses that are most important to RCP operation are the [four] pump coastdown, single pump locked rotor, single pump (broken shaft or coastdown), and rod withdrawal events (Ref. 1).

Steady state DNB analysis has been performed for the [four] RCS loop operation. For [four] RCS loop operation, the steady state DNB analysis, which generates the pressure and temperature Safety Limit (SL) (i.e., the departure from nucleate boiling ratio (DNBR) limit) assumes a maximum power level of 109% RTP. This is the design overpower condition for

[four] RCS loop operation. The value for the accident analysis setpoint of the nuclear overpower (high flux) trip is 107% and is based on an analysis assumption that bounds possible instrumentation errors. The DNBR limit defines a locus of pressure and temperature points that result in a minimum DNBR greater than or equal to the critical heat flux correlation limit.

The plant is designed to operate with all RCS loops in operation to maintain DNBR above the SL, during all normal operations and anticipated transients. By ensuring heat transfer in the nucleate boiling region, adequate heat transfer is provided between the fuel cladding and the reactor coolant.

RCS Loops - MODES I and 2 satisfy Criterion 2 of 10 CFR 50.36(c)(2)(ii).

LCO The purpose of this LCO is to require an adequate forced flow rate for core heat removal. Flow is represented by the number of RCPs in operation for removal of heat by the SGs. To meet safety analysis acceptance criteria for DNB, [four] pumps are required at rated power.

An OPERABLE RCS loop consists of an OPERABLE RCP in op ration providing forced flow for heat transport and an OPERABLE SG5,S (accorLonce with the eam Gene Kor Tube Surwyellance Praafo .

APPLICABILITY In MODES 1 and 2, the reactor is critical and thus has the potential to produce maximum THERMAL POWER. Thus, to ensure that the assumptions of the accident analyses remain valid, all RCS loops are required to be OPERABLE and in operation in these MODES to prevent DNB and core damage.

WOG STS B 3.4.4 - 2 Rev. 2, 04130/01

TSTF-449, Rev. 2 RCS Loops - MODE 3 B 3.4.5 BASES LCO (continued) shown that boron stratification is not a problem during this short period with no forced flow.

Utilization of the Note is permitted provided the following conditions are met, along with any other conditions imposed by initial startup test procedures:

a. No operations are permitted that would dilute the RCS boron concentration with coolant at boron concentrations less than required to assure the SDM of LCO 3.1.1, thereby maintaining the margin to criticality. Boron reduction with coolant at boron concentrations less than required to assure SDM is maintained is prohibited because a uniform concentration distribution throughout the RCS cannot be ensured when in natural circulation and

b. Core outlet temperature is maintained at least 100F below saturation temperature, so that no vapor bubble may form and possibly cause a natural circulation flow obstruction.

An OPERABLE RCS loo1consists of one OPERABLE RCP and one OPRALES~ac~coance with tha~bgim GeneratorTubj kSureTLance rogr wic as the minimum water level specified in SR 3.4.5.2. An RCP is OPERABLE if it is capable of being powered and is able to provide forced flow if required.

APPLICABILITY In MODE 3, this LCO ensures forced circulation of the reactor coolant to remove decay heat from the core and to provide proper boron mixing.

The most stringent condition of the LCO, that is, two RCS loops OPERABLE and two RCS loops in operation, applies to MODE 3 with the Rod Control System capable of rod withdrawal. The least stringent condition, that is, two RCS loops OPERABLE and one RCS loop in operation, applies to MODE 3 with the Rod Control System not capable of rod withdrawal.

Operation in other MODES is covered by:

LCO 3.4.4, "RCS Loops - MODES 1 and 2,"

LCO 3.4.6, "RCS Loops - MODE 4,"

LCO 3.4.7, "RCS Loops - MODE 5, Loops Filled,"

LCO 3.4.8, "RCS Loops - MODE 5, Loops Not Filled,"

LCO 3.9.5, "Residual Heat Removal (RHR) and Coolant Circulation -

High Water Level" (MODE 6), and WOG STS B 3.4.5 - 3 Rev. 2, 04/30/01

TSTF-449, Rev. 2 RCS Loops - MODE 4 B 3.4.6 BASES LCO (continued) the tests performed during the startup testing program is the validation of rod drop times during cold conditions, both with and without flow. The no flow test may be performed in MODE 3, 4, or 5 and requires that the pumps be stopped for a short period of time. The Note permits the stopping of the pumps in order to perform this test and validate the assumed analysis values. If changes are made to the RCS that would cause a change to the flow characteristics of the RCS, the input values must be revalidated by conducting the test again. The 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months time period is adequate to perform the test, and operating experience has shown that boron stratification is not a problem during this short period with no forced flow.

Utilization of Note 1 is permitted provided the following conditions are met along with any other conditions imposed by initial startup test procedures:

a. No operations are permitted that would dilute the RCS boron concentration with coolant with boron concentrations less than required to meet SDM of LCO 3.1.1, therefore maintaining the margin to criticality. Boron reduction with coolant at boron concentrations less than required to assure SDM is maintained is prohibited because a uniform concentration distribution throughout the RCS cannot be ensured when in natural circulation and

b. Core outlet temperature is maintained at least 100F below saturation temperature, so that no vapor bubble may form and possibly cause a natural circulation flow obstruction.

Note 2 requires that the secondary side water temperature of each SG be s [50]OF above each of the RCS cold leg temperatures before the start of an RCP with any RCS cold leg temperature . [275 0F] [Low Temperature Overpressure Protection (LTOP) arming temperature specified in the PTLR]. This restraint is to prevent a low temperature overpressure event due to a thermal transient when an RCP is started.

An OPERABLE RCS loop comprises an OPERABLE RCP and an OPERABLE SGn arftlme btearrneratorLo

%crac (Su nce Prog ~ich has the minimum water level specified in SR 3.4.6.2.

Similarly for the RHR System, an OPERABLE RHR loop comprises an OPERABLE RHR pump capable of providing forced flow to an OPERABLE RHR heat exchanger. RCPs and RHR pumps are WOG STS B 3.4.6 - 2 Rev. 2, 04/30/01

TSTF-449, Rev. 2 RCS Loops - MODE 5, Loops Filled B 3.4.7 BASES LCO (continued)

b. Core outlet temperature is maintained at least 10F below saturation temperature, so that no vapor bubble may form and possibly cause a natural circulation flow obstruction.

Note 2 allows one RHR loop to be inoperable for a period of up to 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months , provided that the other RHR loop is OPERABLE and in operation. This permits periodic surveillance tests to be performed on the inoperable loop during the only time when such testing is safe and possible.

Note 3 requires that the secondary side water temperature of each SG be s [5010F above each of the RCS cold leg temperatures before the start of a reactor coolant pump (RCP) with an RCS cold leg temperature

[2750F] [Low Temperature Overpressure Protection (LTOP) arming temperature specified in the PTLR]. This restriction is to prevent a low temperature overpressure event due to a thermal transient when an RCP is started.

Note 4 provides for an orderly transition from MODE 5 to MODE 4 during a planned heatup by permitting removal of RHR loops from operation when at least one RCS loop is in operation. This Note provides for the transition to MODE 4 where an RCS loop is permitted to be in operation and replaces the RCS circulation function provided by the RHR loops.

RHR pumps are OPERABLE if they are capable of being powered and are able to provide flow if required. J SG can perform as a heat sink via natural circulation when it has an adequate water level and is OPERABLE n acc ce withba-Steam Genera beg (u ance Prrr APPLICABILITY In MODE 5 with RCS loops filled, this LCO requires forced circulation of the reactor coolant to remove decay heat from the core and to provide proper boron mixing. One loop of RHR provides sufficient circulation for these purposes. However, one additional RHR loop is required to be OPERABLE, or the secondary side water level of at least [two) SGs is required to be 2 [17]%.

Operation in other MODES is covered by:

LCO 3.4.4, "RCS Loops - MODES I and 2;"

LCO 3.4.5, "RCS Loops - MODE 3;"

LCO 3.4.6, "RCS Loops - MODE 4;"

LCO 3.4.8, "RCS Loops - MODE 5, Loops Not Filled;"

WOG STS B 3.4.7 - 3 Rev. 2, 04/30101

TSTF-449, Rev. 2 RCS Loops - MODES 1 and 2 B 3.4.4 BASES APPLICABLE SAFETY ANALYSES (continued) majority of the plant safety analyses are based on initial conditions at high core power or zero power. The accident analyses that are of most importance to RCP operation are the four pump coastdown, single pump locked rotor, single pump (broken shaft or coastdown), and rod withdrawal events (Ref. 1).

Steady state DNB analysis had been performed for the [four] pump combination. For [four] pump operation, the steady state DNB analysis, which generates the pressure and temperature and Safety Limit (i.e., the departure from nucleate boiling ratio (DNBR) limit), assumes a maximum power level of 107% RTP. This is the design overpower condition for four pump operation. The 107% value is the accident analysis setpoint of the nuclear overpower (high flux) trip and is based on an analysis assumption that bounds possible instrumentation errors. The DNBR limit defines a locus of pressure and temperature points that result in a minimum DNBR greater than or equal to the critical heat flux correlation limit.

RCS Loops - MODES 1 and 2 satisfy Criteria 2 and 3 of 10 CFR 50.36(c)(2)(ii).

LCO The purpose of this LCO is to require adequate forced flow for core heat removal. Flow is represented by having both RCS loops with both RCPs in each loop in operation for removal of heat by the two SGs. To meet safety analysis acceptance criteria for DNB, four pumps are required at rated power.

Each OPERABLE loop consists of two RCPs providin forced flow for heat trnsport to an SG that is OPE 'r~emranc~wh-M&teamD (Glaor Tbe~ n v G, ad hnce RCS loop, OPERABILITY with regard to SG water level is ensured by the Reactor Protection System (RPS) in MODES 1 and 2. A reactor trip places the plant in MODE 3 if any SG level is * [25]% as sensed by the RPS. The minimum water level to declare the SG OPERABLE is [25]%.

APPLICABILITY In MODES 1 and 2, the reactor is critical and thus has the potential to produce maximum THERMAL POWER. Thus, to ensure that the assumptions of the accident analyses remain valid, all RCS loops are required to be OPERABLE and in operation in these MODES to prevent DNB and core damage.

The decay heat production rate is much lower than the full power heat rate. As such, the forced circulation flow and heat sink requirements are CEOG STS B 3.4.4 - 2 Rev. 2, 04/30/01

TSTF-449, Rev. 2 RCS Loops - MODE 3 8 3.4.5 BASES LCO (continued)

The Note permits a limited period of operation without RCPs. All RCPs may be not in operation for

1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months per 8 hour9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months period. This means that natural circulation has been established. When in natural circulation, a reduction in boron concentration with coolant at boron concentrations less than required to assure the SDM of LCO 3.1.1 is maintained is prohibited because an even concentration distribution throughout the RCS cannot be ensured. Core outlet temperature is to be maintained at least 100F below the saturation temperature so that no vapor bubble may form and possibly cause a natural circulation flow obstruction.

In MODES 3, 4, and 5, It is sometimes necessary to stop all RCPs or shutdown cooling (SDC) pump forced circulation (e.g., to change operation from one SDC train to the other, to perform surveillance or startup testing, to perform the transition to and from SDC System cooling, or to avoid operation below the RCP minimum net positive suction head limit). The time period is acceptable because natural circulation is adequate for heat removal, or the reactor coolant temperature can be maintained subcooled and boron stratification affecting reactivity control is not expected.

An OPERABLE RCS Ioop consists of at least one OPERABLE RCP and a SG thatisOPERABL Ea w Sm G e A RCP is OPERABLE if it is capable of being powered and is able to provide forced flow if required.

APPLICABILITY In MODE 3, the heat load is lower than at power; therefore, one RCS loop in operation is adequate for transport and heat removal. A second RCS loop is required to be OPERABLE but not in operation for redundant heat removal capability.

Operation in other MODES is covered by:

LCO 3.4.4, "RCS Loops - MODES 1 and 2,"

LCO 3.4.6, "RCS Loops - MODE 4,"

LCO 3.4.7, "RCS Loops - MODE 5, Loops Filled,"

LCO 3.4.8, "RCS Loops - MODE 5, Loops Not Filled,"

LCO 3.9.4, "Shutdown Cooling (SDC) and Coolant Circulation - High Water Level" (MODE 6), and LCO 3.9.5, "Shutdown Cooling (SDC) and Coolant Circulation - Low Water Level" (MODE 6).

CEOG STS B 3.4.5 - 2 Rev. 2, 04/30/01

TSTF-449, Rev. 2 RCS Loops - MODE 4 B 3.4.6 BASES LCO (continued) higher heat loads will cause the reactor coolant temperature and pressure to increase at a rate proportional to the decay heat load.

Because pressure can increase, the applicable system pressure limits (pressure and temperature (PIT) limits or low temperature overpressure protection (LTOP) limits) must be observed and forced SDC flow or heat removal via the SGs must be re-established prior to reaching the pressure limit. The circumstances for stopping both RCPs or SDC pumps are to be limited to situations where:

a. Pressure and temperature increases can be maintained well within the allowable pressure (PIT limits and LTOP) and 10F subcooling limits or

b. An alternate heat removal path through the SGs is in operation.

Note 2 requires that either of the following two conditions be satisfied before an RCP may be started with any RCS cold leg temperature s 2850 F:

a. Pressurizer water level is < [60]% or

b. Secondary side water temperature in each SG is < [100]'F above each of the RCS cold leg temperatures.

Satisfying either of the above conditions will preclude a large pressure surge in the RCS when the RCP is started.

An OPERABLE RCS loop consists of at least one OPERABLE RCP and an SG that is OPERABLE th m Gene _with

__Ibe)

(S i8;;ra and has the minimum water level specified in SR 3.4.6.2.

Similarly, for the SDC System, an OPERABLE SDC train is composed of the OPERABLE SDC pump(s) capable of providing forced flow to the SDC heat exchanger(s). RCPs and SDC pumps are OPERABLE if they are capable of being powered and are able to provide flow if required.

APPLICABILITY In MODE 4, this LCO applies because it is possible to remove core decay heat and to provide proper boron mixing with either the RCS loops and SGs or the SDC System.

Operation in other MODES is covered by:

CEOG STS B 3.4.6 - 2 Rev. 2, 04/30/01

TSTF-449, Rev. 2 RCS Loops - MODE 5, Loops Filled B 3.4.7 BASES LCO (continued)

a. Pressurizer water level must be < [60]% or

b. Secondary side water temperature in each SG must be < [1003'F above each of the RCS cold leg temperatures.

Satisfying either of the above conditions will preclude a low temperature overpressure event due to a thermal transient when the RCP is started.

Note 4 provides for an orderly transition from MODE 5 to MODE 4 during a planned heatup by permitting SDC trains to not be in operation when at least one RCP is in operation. This Note provides for the transition to MODE 4 where an RCP is permitted to be in operation and replaces the RCS circulation function provided by the SDC trains.

An OPERABLE SDC train is composed of an OPERABLE SDC pump and an OPERABLE SDC heat exchanger.

SDC pumps are OPERABLE if they are capable of being powered and are able to provide flow if required. ^ D-eLES SG can perform as a heat sink via natura irculation when it has an adequate water level and is OPERABLE Lm ccejjdffnce-with te ub rveii'rogrard.

APPLICABILITY In MODE 5 with RCS loops filled, this LCO requires forced circulation to remove decay heat from the core and to provide proper boron mixing.

One SDC train provides sufficient circulation for these purposes.

Operation in other MODES is covered by:

LCO 3.4.4, "RCS Loops - MODES 1 and 2,"

LCO 3.4.5, "RCS Loops - MODE 3," LCO 3.4.6, "RCS Loops -

MODE 4,"

LCO 3.4.8, "RCS Loops - MODE 5, Loops Not Filled,"

LCO 3.9.4, "Shutdown Cooling (SDC) and Coolant Circulation - High Water Level" (MODE 6), and LCO 3.9.5, "Shutdown Cooling (SDC) and Coolant Circulation - Low Water Level" (MODE 6).

ACTIONS A.1. A.2. B.1 and B.2 If one SDC train is OPERABLE and any required SGs has secondary side water levels < [25%], redundancy for heat removal is lost. Action must be initiated immediately to restore a second SDC train to CEOG STS B 3.4.7 - 3 Rev. 2, 04/30/01

TSTF-04-13, TSTF-449, Revision 2, Steam Generator Tube Integrity.

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SUBJECT:

Dear Mr. Boyce:

Contact:

Description:

Description:

Description:

Description:

Description:

Description:

Description:

Description:

Description:

Description:

1.0 DESCRIPTION

2.0 PROPOSED CHANGE

3.0 BACKGROUND

4.0 TECHNICAL ANALYSIS

5.0 REGULATORY ANALYSIS

6.0 ENVIRONMENTAL CONSIDERATION

7.0 REFERENCES

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TSTF-04-13, TSTF-449, Revision 2, Steam Generator Tube Integrity.

Text

SUBJECT:

Dear Mr. Boyce:

Contact:

Description:

Description:

Description:

Description:

Description:

Description:

Description:

Description:

Description:

Description:

1.0 DESCRIPTION

2.0 PROPOSED CHANGE

3.0 BACKGROUND

4.0 TECHNICAL ANALYSIS

5.0 REGULATORY ANALYSIS

6.0 ENVIRONMENTAL CONSIDERATION

7.0 REFERENCES

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