Text

Application for Technical Specification Improvement Regarding Steam Generator Tube Integrity
	ML053320303
Person / Time
Site:	Byron, Braidwood
Issue date:	11/18/2005
From:	Bauer J; Exelon Generation Co, Exelon Nuclear
To:	; Document Control Desk, Office of Nuclear Reactor Regulation
References
	RS-05-129
	Download: ML053320303 (161)
	v • d • e

Exek!n.D Exelon Generation www.exeloncorp.com Nu1 4300 Winfield Road uclear Warrenville, L 60555 10 CFR 50.90 RS-05-129 November 18, 2005 U. S. Nuclear Regulatory Commission Attn: Document Control Desk Washington, DC 20555-0001 Braidwood Station, Units 1 and 2 Facility Operating License Nos. NPF-72 and NPF-77 NRC Docket Nos. STN 50-456 and STN 50-457 Byron Station, Units 1 and 2 Facility Operating License Nos. NPF-37 and NPF-66 NRC Docket Nos. STN 50-454 and STN 50-455

Subject:

Application for Technical Specification Improvement Regarding Steam Generator Tube Integrity

References:

(1)

Letter from G. F. Dick (NRC) to C. M. Crane (Exelon Generation Company, LLC), "Braidwood Station, Units 1 and 2-Issuance of Exigent Amendments RE: Revision of Scope of Steam Generator Inspections for Unit 2 Refueling Outage 11," dated April 25, 2005 (2)

Letter from J. B. Hopkins (NRC) to C. M. Crane (Exelon Generation Company, LLC), "Byron Station, Unit 2 ~- Issuance of Amendment," dated September 19, 2005 In accordance with 10 CFR 50.90, 'Application for amendment of license or construction permit," Exelon Generation Company, LLC (EGC) is requesting an amendment to Appendix A, Technical Specifications (TS), of Facility Operating License Nos. NPF-72, NPF-77, NPF-37, and NPF-66 for Braidwood Station, Units 1 and 2, and Byron Station, Units 1 and 2, respectively.

The proposed amendment would revise the TS requirements related to steam generator tube integrity. The change is consistent with NRC-approved Revision 4 to Technical Specification Task Force (TSTF) Standard Technical Specification Change Traveler, TSTF-449, "Steam Generator Tube Integrity," with two exceptions as discussed below. The availability of this TS improvement was announced in the Federal Register on May 6, 2005 (i.e., 70 FR 21426) as part of the consolidated line item improvement process (CLIIP).

EGC proposes to revise the TSTF-449 version of TS 5.5.9, Steam Generator Program, to exclude the portion of the tube below 17 inches from the top of the hot leg tubesheet in the Ap e\\

U. S. Nuclear Regulatory Commission November 18, 2005 Page 2 Braidwood Station, Unit 2, and Byron Station, Unit 2, steam generators. This proposed license amendment request, in effect, redefines the Braidwood Station, Unit 2, and Byron Station, Unit 2, primary pressure boundary from the hot leg tube end weld to 17 inches below the top of the hot leg tube sheet. This change is supported by Westinghouse Electric Company, LLC, LTR-CDME-05-32, "Limited Inspection of the Steam Generator Tube Portion Within the Tubesheet at Byron 2 and Braidwood 2,a Revision 2, dated August 2005. The NRC has previously granted similar amendments, on a one-time basis, for Braidwood Station, Unit 2, and Byron Station, Unit 2, in References 1 and 2, respectively.

EGC also proposes to delete Westinghouse laser welded sleeves as a steam generator tube repair method.

LTR-CDME-05-32 contains information proprietary to Westinghouse Electric Company, LLC; it is supported by an affidavit signed by Westinghouse, the owner of the information. The affidavit sets forth the basis on which the information may be withheld from public disclosure by the NRC and addresses with specificity the considerations listed in paragraph (b)(4) of 10 CFR 2.390, "Public inspections, exemptions, requests for withholding." Accordingly, it is respectfully requested that the information which is proprietary to Westinghouse be withheld from public disclosure in accordance with 10 CFR 2.390.

The attached amendment request is subdivided as shown below. provides an evaluation of the proposed changes.

Attachments 2-A and 2-B include the marked-up TS pages with the proposed changes indicated for Braidwood Station and Byron Station, respectively.

Attachments 3-A and 3-B include the associated typed TS pages with the proposed changes incorporated for Braidwood Station and Byron Station, respectively.

Attachments 4-A and 4-B include the associated revised TS bases for information only. provides an affidavit for withholding signed by Westinghouse Electric Company, LLC, the owner of proprietary information provided in Attachment 7. Also enclosed are'a Westinghouse authorization letter, CAW-05-2047, Proprietary Information Notice and Copyright Notice. provides a non-proprietary version of Westinghouse LTR-CDME-05-32. provides a proprietary version of Westinghouse LTR-CDME-05-32.

EGC requests that this proposed change be approved by September 16, 2006, to support the preparations for Braidwood, Unit 2, Refueling Outage 12. Once approved, the change will be implemented within 60 days.

The proposed amendment has been reviewed by the Braidwood Station and the Byron Station Plant Operations Review Committees and approved by their respective Nuclear Safety Review Boards in accordance with the requirements of the EGC Quality Assurance Program.

Page 2 of 3

U. S. Nuclear Regulatory Commission November 18, 2005 Page 3 EGC is notifying the State of Illinois of this application for a change to the TS by sending a copy of this letter and its attachments to the designated State Official.

Should you have any questions about this letter, please contact J. A. Bauer at (630) 657-2801.

I declare under penalty of perjury that the foregoing is true and correct. Executed on the 18t day of November 2005.

Respectfully, seph A. Bauer Manager, Licensing : Evaluation of Proposed Changes -A: Markup of Proposed Technical Specifications Page Changes for Braidwood Station -B: Markup of Proposed Technical Specifications Page Changes for Byron Station -A: Typed Pages for Technical Specification Changes for Braidwood Station -B: Typed Pages for Technical Specification Changes for Byron Station -A: Revised Technical Specification Bases Pages for Braidwood Station -B: Revised Technical Specification Bases Pages for Byron Station : Application for Withholding and Affidavit : Non-proprietary Version of Westinghouse LTR-CDME-05-32, "Limited Inspection of the Steam Generator Tube Portion Within the Tubesheet at Byron 2 and Braidwood 2," Revision 2, dated August 2005 : Proprietary Version of Westinghouse LTR-CDME-05-32, "Limited Inspection of the Steam Generator Tube Portion Within the Tubesheet at Byron 2 and Braidwood 2," Revision 2, dated August 2005 Page 3 of 3

ATTACHMENT 1 Evaluation of Proposed Changes INDEX

1.0 DESCRIPTION

2.0 PROPOSED CHANGE

3.0 BACKGROUND

4.0 TECHNICAL ANALYSIS

5.0 REGULATORY ANALYSIS

5.1 Verification and Commitments 5.2 No Significant Hazards Consideration 5.3 Applicable Regulatory Requirements/Criteria

6.0 ENVIRONMENTAL CONSIDERATION

7.0 PRECEDENT

8.0 REFERENCES

Page 1 of 17

ATTACHMENT 1 Evaluation of Proposed Changes

1.0 DESCRIPTION

The proposed amendment revises the requirements in Technical Specification (TS) related to steam generator tube integrity for Braidwood Station, Units 1 and 2, and Byron Station, Units 1 and 2. The changes are consistent with NRC-approved Technical Specification Task Force (TSTF) Standard Technical Specification Change Traveler, TSTF-449, "Steam Generator Tube Integrity," Revision 4, except as discussed below. The availability of this TS improvement was announced in the Federal Register on May 6, 2005 (i.e., Reference 1), as part of the consolidated line item improvement process (CLIIP).

The proposed amendment also revises the TSTF-449 version of TS 5.5.9, Steam Generator Program, to exclude the portion of the tube below 17 inches from the top of the hot leg tubesheet in the Braidwood Station, Unit 2, and Byron Station, Unit 2, steam generators from TS 5.5.9.d, "Provisions for SG tube inspections." This proposed license amendment request, in effect, redefines the Braidwood Station, Unit 2, and Byron Station, Unit 2, primary pressure boundary from the hot leg tube end weld to 17 inches below the top of the hot leg tube sheet.

This change is supported by Westinghouse Electric Company, LLC, LTR-CDME-05-32 (i.e.,

Reference 2). In addition, the proposed amendment deletes the current TS 5.5.9.e.6 and TS 5.5.9.e.10 allowance to use Westinghouse laser welded sleeves as a SG tube repair method.

2.0 PROPOSED CHANGE

Consistent with the NRC-approved Revision 4 of TSTF-449, the proposed TS changes include:

Revised TS definition of LEAKAGE, Revised TS 3.4.13, "RCS Operational LEAKAGE,"

New TS 3.4.19, "Steam Generator (SG) Tube Integrity,"

Revised TS 5.5.9, "Steam Generator (SG) Program," and Revised TS 5.6.9, "Steam Generator Tube Inspection Report."

Proposed revisions to the TS Bases are also included in this application. As discussed in the NRC's model safety evaluation, adoption of the revised TS Bases associated with TSTF-449, Revision 4, is an integral part of implementing this TS improvement. The changes to the affected TS Bases pages will be incorporated in accordance with the TS Bases Control Program.

EGC proposes to add the following alternate repair criteria (ARC) to the proposed TS 5.5.9.c:

"For Unit 2 only, degradation found in the portion of the tube below 17 inches from the top of the hot leg tubesheet does not require plugging or repair."

EGC proposes to revise the TS 5.5.9.d, "Provisions for SG tube inspections," to exclude the portion of the tube below 17 inches from the top of the hot leg tubesheet from inspections for Braidwood Station, Unit 2, and Byron Station, Unit 2. The following is added to the TS 5.5.9.d description of the extent of the tube inspections:

Page 2 of 17

ATTACHMENT 1 Evaluation of Proposed Changes "For Unit 2, the portion of the tube below 17 inches from the top of the hot leg tubesheet is excluded."

EGC proposes to revise the existing requirements of TS 5.5.9.e.6 and TS 5.5.9.e.1 0 by deleting the Westinghouse laser welded sleeving repair methodology. The requirements for the proposed TS 5.5.9.c and TS 5.5.9.f do not allow the use of Westinghouse laser welded sleeves.

3.0 BACKGROUND

The background for this application is adequately addressed by the NRC Notice of Availability published on May 6, 2005 (i.e., 70 FR 24126), the NRC Notice for Comment published on March 2, 2005 (i.e., 70 FR 10298), and TSTF-449, Revision 4, except as discussed below.

Braidwood Station, Unit 2, and Byron Station, Unit 2, each contain four Westinghouse Model D5 recirculating, pre-heater type SGs. Each SG contains 4,570 thermally treated Alloy-600 U-tubes that have an outer diameter of 0.750 inch with a 0.043 inch nominal wall thickness.

The support plates are 1.12 inch thick stainless steel and have quatrefoil broached holes.

The tubing within the tubesheet is hydraulically expanded throughout the full thickness of the tubesheet. The tubesheet is approximately 21 inches thick. The low row U-bend region, up through row nine, received additional thermal stress relief following tube bending. The units operate on approximately 1 8-month fuel cycles.

The SG inspection scope is governed by: Braidwood Station TS 5.5.9; Byron Station TS 5.5.9; the Electric Power Research Institute (EPRI) Pressurized Water Reactor (PWR)

SG Examination Guidelines; regulatory documents and commitments; Exelon ER-AP-420 procedure series (Steam Generator Management Program Activities); and the results of Braidwood Station, Unit 2, and Byron Station, Unit 2, degradation assessments. The inspection techniques and equipment are capable of reliably detecting the known and potential specific degradation mechanisms applicable to the Braidwood Station, Unit 2, and Byron Station, Unit 2, SGs. The inspection techniques, essential variables and equipment are qualified to Appendix H, 'Performance Demonstration for Eddy Current Examination," of the EPRI PWR SG Examination Guidelines.

Indications of cracking were reported based on the results from the nondestructive, eddy current examination of the SG tubes during the fall 2004 outage at Catawba Nuclear Station, Unit 2, as described in Reference 3. Tube indications were reported approximately seven inches from the top of the hot leg tubesheet in one tube, and just above the tube-to-tubesheet welds in a region of the tube known as the tack expansion in several other tubes.

Finally, indications were also reported in the tube-end welds (TEWs), also known as tube-to-tubesheet welds, joining the tube to the tubesheet.

Catawba Nuclear Station, Unit 2, has Westinghouse designed Model D5 SGs similar to those in service at Braidwood Station, Unit 2, and Byron Station, Unit 2. Model D5 SGs were fabricated with Alloy 600TT (i.e., thermally treated) tubes. Thus, there is a potential for tube indications similar to those reported at Catawba Nuclear Station, Unit 2, within the hot leg tubesheet region to be identified in the Braidwood Station, Unit 2, and Byron Station, Unit 2, SGs if similar inspections were to be performed. It is noted that the fabrication technique used for the installation of the SG tubes at Braidwood Station, Unit 2, would be expected to Page 3 of 17

ATTACHMENT 1 Evaluation of Proposed Changes lead to a much lower likelihood for crack-like indications to be present in the region known as the tack expansion relative to Catawba Nuclear Station, Unit 2. The Braidwood Station, Unit 2, fabrication technique results in lower residual stress. The fabrication technique used for the installation of the SG tubes at Byron Station, Unit 2, was similar to that used in the Catawba Nuclear Station, Unit 2, SGs. Therefore, the residual stress in the Byron Station, Unit 2, tack expansion region is expected to be similar to the residual stress in the Catawba Nuclear Station, Unit 2, tack expansion region.

Potential inspection plans for the tubes and the welds underwent intensive industry discussions in March 2005. The findings in the Catawba Nuclear Station, Unit 2, SG tubes present three distinct issues with regard to the SG tubes at Braidwood Station, Unit 2, and Byron Station, Unit 2:

1) indications in internal bulges and overexpansions within the hot leg tubesheet;

2) indications at the elevation of the tack expansion transition; and

3) indications in the tube-to-tubesheet welds and propagation of these indications into the adjacent tube material.

In order to preclude unnecessarily plugging tubes in the Braidwood Station, Unit 2, and Byron Station, Unit 2, SGs, an analysis was performed to identify the portion of the tube within the hot leg tubesheet necessary to maintain structural and leakage integrity for both normal operating and accident conditions. Tube inspections will be limited to identifying and repairing degradation in this portion of the tubes. The technical justification for the inspection and repair methodology is provided in Reference 2. The limited hot leg tubesheet inspection criteria were developed for the hot leg tubesheet region of Model D5 SGs considering the most stringent loads associated with plant operation, including transients and postulated accident conditions. The limited hot leg tubesheet inspection criteria were selected to prevent tube burst and axial separation due to axial pullout forces acting on the tube and to ensure that the steam line break (SLB) leakage limits are not exceeded. Reference 2 provides technical justification for allowing tubes with indications that are below 17 inches from the top of the hot leg tubesheet (i.e., within approximately four inches of the tube end) to remain in-service.

Constraint provided by the hot leg tubesheet precludes tube burst for cracks within the tubesheet. The criteria for tube burst described in Nuclear Energy Institute (NEI) 97-06, "Steam Generator Program Guidelines," Revision 1 dated January 2001 (i.e.,

Reference 4), and NRC Regulatory Guide (RG) 1.121, "Bases for Plugging Degraded PWR Steam Generator Tubes," dated August 1976 (i.e., Reference 5), are satisfied due to the constraint provided by the tubesheet. Through application of the limited hot leg tubesheet inspection scope described herein, the existing operating leakage limit provides assurance that excessive leakage (i.e., greater than accident analysis assumptions) will not occur during a postulated SLB event.

Implementation of this proposed methodology involves limited inspection of the tubes within the hot leg tubesheet to depths of 17 inches from the top of the tubesheet using specialized rotating eddy current probes. The limited tubesheet inspection length of tubing must be demonstrated to be non-degraded below the top of the tubesheet interface. If cracks are found within the top of hot leg tubesheet to 17 inches below the top of tubesheet, the tube must be repaired or removed from service.

Page 4 of 17

ATTACHMENT 1 Evaluation of Proposed Changes The NRC has previously granted similar amendments, on a one-time basis, for Braidwood Station, Unit 2, and Byron Station, Unit 2, in References 6 and 7, respectively.

4.0 TECHNICAL ANALYSIS

Exelon Generation Company, LLC (EGC) has reviewed the safety evaluation (SE) published on March 2, 2005 (i.e., 70 FR 10298), as part of the CLIIP Notice for Comment. This included the NRC staff's SE, the supporting information provided to support TSTF-449, and the changes associated with Revision 4 to TSTF-449. EGC has concluded that the justifications presented in the TSTF proposal and the SE prepared by the NRC staff are applicable to Braidwood Station, Units 1 and 2, and Byron Station, Units 1 and 2, and justify this amendment for the incorporation of the changes to their respective TS, except as discussed below.

A technical justification has been developed to identify the safety significant portion of the tube within the tubesheet. This justification (i.e., Reference 2) has been reviewed and approved in accordance with the requirements of Exelon Generation Company, LLC (EGC) procedures and is provided as Attachment 7. The safety significant portion of the tube is the length of tube that is engaged in the tubesheet from the secondary face that is required to maintain structural and leakage integrity over the full range of steam generator operating conditions, including the most limiting accident conditions. The evaluation determined that degradation in tubing below the safety significant portion of the tube does not require repair and serves as the basis for the tubesheet inspection program.

The bases for determining the safety significant portion of the tube within the tubesheet is based upon analyses and testing programs that quantified the tube-to-tubesheet radial contact pressure for bounding plant conditions as described in Reference 2. The tube-to-tubesheet radial contact pressure provides resistance to tube pull-out and resistance to leakage during plant operation and transients. Temperature effects and upward bending of the tubesheet due to primary and secondary differential pressure during normal and transient conditions, result in the tube-to-tubesheet contact pressure increasing with distance from the top of the tubesheet. Due to these effects, the tubesheet bore tends to dilate near the top of the tubesheet and constricts the tube near the bottom of the tubesheet. Testing and analyses have shown that tube-to-tubesheet engagement lengths of approximately three inches to 8.6 inches were sufficient to maintain structural integrity (i.e., resist tube pull-out resulting from loading considering differential pressures of three times the normal operating pressure difference and considering differential pressures of 1.4 times the limiting accident pressure difference). The variation of the required engagement length is a function of the radial tube location within the tube bundle. EGC has decided to add additional conservatism to the minimum structural distances of three inches to 8.6 inches by performing inspections to depths of 17 inches below the top of the hot leg tubesheet. The increase in contact pressure at this depth significantly increases the tube structural strength and resistance to leakage.

Since the proposed 17-inch tube inspection depth traverses below the mid-plane of the hot leg tubesheet, the tube-to-tubesheet contact pressure significantly aids in restricting primary-to-secondary leakage as differential pressure increases. Based on engineering judgment, given that there is no significant primary-to-secondary leakage during normal operation, there will be no significant leakage during postulated accident conditions from indications located Page 5 of 17

ATTACHMENT 1 Evaluation of Proposed Chihges below the mid-plane of the tubesheet (i.e., greater than approximately 10.5 inches below the top of the tubesheet). The rationale for this conclusion based on engineering judgment is the interaction of temperature and tubesheet bending effects that increase the contact pressure between the tube and the tubesheet, thereby increasing the resistance to primary-to-secondary leakage during normal operating or accident conditions.

Primary-to-secondary leakage from tube degradation in the tubesheet area during the limiting accident (i.e., SLB) is limited by flow restrictions resulting from the crack and tube-to-tubesheet contact pressures that provide a restricted leakage path above the indications and also limit the degree of potential crack face opening as compared to free span indications.

The primary-to-secondary leak rate during postulated SLB accident conditions would be expected to be less than that during normal operation for indications near the bottom of the tubesheet (i.e., including indications in the tube end welds). This conclusion is based on the observation that while the driving pressure causing leakage increases by approximately a factor of two, the flow resistance associated with an increase in the tube-to-tubesheet contact pressure, during a SLB, increases by up to approximately a factor of three. While such a leakage decrease is logically expected, the postulated accident leak rate could be conservatively bounded by twice the normal operating leak rate if the increase in contact pressure is ignored. Since normal operating leakage is limited to less than 0.104 gpm (i.e.,

150 gpd) per TS 3.4.13, "RCS Operational Leakage," the associated accident condition leak rate, assuming all leakage to be from lower tubesheet indications, would be bounded by approximately 0.2 gpm. This value is well within the assumed faulted SG accident leakage rate of 0.5 gpm discussed in Byron/Braidwood Updated Final Safety Analysis Report, Table 15.1-3, "Parameters Used in Steam Line Break Analyses." Hence it is reasonable to omit any consideration of inspection of the tube, tube end weld, bulges/overexpansions or other anomalies below 17 inches from the top of the hot leg tubesheet.

The proposed inspection sampling length of 17 inches from the top of the hot leg tubesheet provides a high level of confidence that the structural and leakage criteria are maintained during normal operating and accident conditions.

Degradation found in the portion of the tube below 17 inches from the top of the hot leg does not require repair or plugging as described in Reference 2.

In summary:

Reference 2 notes that the structural integrity requirements of NEI 97-06 (i.e.,

Reference 4), and RG 1.121 (i.e., Reference 5), are met by sound tube engagement lengths ranging from approximately three to 8.6 inches from the top of the hot leg tubesheet. The region of the tube below those elevations, including the tube-to-tubesheet weld, is not needed for structural integrity during normal operation or accident conditions. Inspections will be performed to a depth of 17 inches from the top of the hot leg tubesheet.

NEI 97-06 defines the tube as extending from the tube-to-tubesheet weld at the tube inlet to the tube-to-tubesheet weld at the tube outlet, but specifically excludes the tube-to-tubesheet weld from the definition of the tube.

The welds were originally designed and analyzed as the primary pressure boundary in accordance with the requirements of Section III of the 1971 edition of the American Page 6 of 17

ATTACHMENT 1 Evaluation of Proposed Changes Society of Mechanical Engineers (ASME) Code, Summer 1972 Addenda and selected paragraphs of the Winter 1974 Addenda for the Braidwood Station, Unit 2 and Byron Station, Unit 2, SGs. This proposed license amendment request, in effect, redefines the primary pressure boundary from the tube end weld to 17 inches below the top of the hot leg tube sheet.

Section Xl of the ASME Code deals with the in-service inspection of nuclear power plant components. The ASME Code (i.e., Editions 1971 through 2004) specifically recognizes that the SG tubes are under the purview of the NRC through the implementation of the requirements of the TS as part of the plant operating license.

Deleting the allowance to use the Westinghouse laser welded sleeving repair methodology results in more conservative requirements for repair of degraded SG tubes. No Westinghouse laser-welded sleeves are currently installed in the Braidwood Station, Unit 2, and Byron Station, Unit 2, SGs. EGC has been informed by Westinghouse Electric Company, LLC, that they (i.e., Westinghouse) no longer possess the technology associated with laser welded sleeves. Reference to Westinghouse laser welded sleeving as a repair methodology is no longer appropriate and is therefore deleted.

Following implementation of this proposed amendment, Braidwood Station, Unit 2, and Byron Station, Unit 2, TS 5.5.9.f will allow use of ABB Combustion Engineering (CE), Inc., TIG welded sleeving methodology for repair of degraded SG tubes. CE Licensing Report CEN-627-P, "Operating Performance of the ABB CENO Steam Generator Tube Sleeve for Use at Commonwealth Edison Byron and Braidwood Units 1 and 2,N dated January 1996 provides limitations on the use of TIG welded sleeves for use in Westinghouse designed Model D SGs. Specifically, only two types of TIG welded sleeves, the roll transition zone sleeve and tube support plate sleeve, are considered for installation in Braidwood Station, Unit 2, and Byron Station, Unit 2, SGs. The tube support plate sleeve is approximately centered at either the first and/or second support plate and does not extend into the tubesheet. The upper end of the roll transition zone sleeve is located above the secondary face of the tubesheet, while the sleeve lower end is located near the neutral axis of the tubesheet. Therefore, the sleeve joint would be located in the portion of the SG tube that is within the proposed inspection length (i.e., in the portion of the tube from the top of the hot leg tubesheet to 17 inches below the top of the tubesheet).

5.0 REGULATORY ANALYSIS

A description of this proposed change and its relationship to applicable regulatory requirements and guidance was provided in the NRC Notice of Availability published on May 6, 2005 (70 FR 10298), and TSTF-449, Revision 4.

5.1 VERIFICATION AND COMMITMENTS The following information is supplied to support the NRC staff's review of this amendment application:

Plant Braldwood, Unit 1 Steam Generator Model(s)

Babcock & Wilcox feedring replacement steam generators Effective Full Power Years (EFPY) of Approximately 5.64 EFPY at time of last inspection in Page 7 of 17

ATTACHMENT1 Evaluation of Proposed Chahges Plant Braidwood, Unit 1 service for currently installed SGs October 2004 (i.e., Refueling Outage Al RI 1)

Tubing Material Alloy 690 Number of tubes per SG 6,633 Number and percentage of tubes SG A SG B SG C SG D plugged in each SG 10 14 5

1

(-0.15%)

(-0.21%)

(-0.08%)

(-0.02%)

Number of tubes repaired in each SG None Degradation mechanisms identified Fan Bar Wear, Lattice Grid Wear, and Foreign Object Wear Current primary-to-secondary leakage limits:

per SG:

150 gallons per day Total:

600 gallons per day Leakage evaluated at:

Room Temperature Approved Alternate Tube Repair Criteria Not Applicable (ARC):

1. None Approved SG Tube Repair Methods:

Not Applicable

1. None Performance criteria for accident leakage:

1. Main Steamline Break Faulted SG - 0.5 gpm at Room Temperature Each intact SG - 0.218 gpm at Room Temperature

2. Locked Rotor Total for all SGs -1.0 gpm at Room Temperature

3. Locked Rotor with Failed Open SG SG with failed open PORV - 0.5 gpm at Room Temperature Power Operated Relief Valve (PORV)

Each intact SG - 0.218 gpm at Room Temperature

4. Rod Cluster Control Assembly Eiection Total for all SGs - 1.0 gpm at Room Temperature

5. Steam Generator Tube Rupture Total for intact SGs -1.0 gpm at Room Temperature (SGTRI Plant Braldwood, Unit2 Steam Generator Model(s)

Westinghouse Model D5 Effective Full Power Years (EFPY) of Approximately 14.16 EFPY at time of last inspection in service for currently installed SGs April 2005 (i.e., Refueling Outage A2R1 1)

Tubing Material Alloy 600TT Number of tubes per SG 4,570 Number and percentage of tubes SG A SG B SG C SG D plugged in each SG 57 48 56 25

(-1.25%)

(-1.05%)

(-1.23%)

(-0.55%)

Number of tubes repaired in each SG None Page 8 of 17

ATTACHMENT I Evaluation of Proposed Changes Plant AdBraldwo d, Unit 2 Degradation mechanisms identified Anti-Vibration Wear, Pre-Heater/Tube Support Plate Wear, Foreign Object Wear, and Outside Diameter Stress Corrosion Cracking (ODSCC) at the tube support plate intersections Current primary-to-secondary leakage limits:

per SG:

150 gallons per day Total:

600 gallons per day Leakage evaluated at:

Room Temperature Approved Alternate Tube Repair Criteria (ARC):

1. Degradation found in the portion of Amendment 135, dated April 25, 2005, approved this the tube below 17 inches from the allowance on a one-time basis for Refueling Outage 11 and top of the hot leg tubesheet does not the subsequent operating cycle.

require plugging or repair.

Approved SG Tube Repair Methods:

1. Laser welded sleeving as described in Amendment No. 46 dated March 4, 1994, approved use of a Westinghouse Technical Report WCAP-1 3698, Revision 1, "Laser Welded Sleeves for 3/4-and subject to the limitations and Inch Diameter Tube Feeding-Type and Westinghouse restrictions as approved by the NRC.

Preheater Steam Generators" Applicability limits: Elevated laser welded tubesheet sleeves (Laser welded sleeving methodology is were not approved for use.

being deleted by this amendment Amendment No. 113 dated May 4, 2001, approved use of request)

WCAP-1 3698, Revision 4 for sleeve plugging criteria Sleeve plugging criteria: 38.7% of the nominal wall thickness.

2. TIG welded sleeving as described in Amendment No. 75 dated April 12, 1996 ABB Combustion Engineering Inc.,

Applicability limits:

Technical Reports: Licensing Report

1) A single tube may contain a maximum of one tubesheet CEN-621-P, Revision 00, sleeve and two support plate sleeves;

'Commonwealth Edison Byron and

2) Post Weld Heat Treatment is required on all freespan Braidwood Unit 1 and Unit 2 Steam welds; and Generators Tube Repair Using Leak

3) Expanded inspections are required for verification of Tight Sleeves, FINAL REPORT," April tube cleaning prior to welding.

1995; and Licensing Report CEN-627-P, "Operating Performance of the Sleeve plugging criteria: 32% of the nominal wall thickness.

ABB CENO Steam Generator Tube Sleeve for use at Commonwealth Edison Byron and Braidwood Units 1 and 2," January 1996; subject to the limitations and restrictions as noted by the NRC Staff.

Page 9 of 17

ATTACHMENT 1 Evaluation of Proposed Changes Plant

------: -l Braidwood, Unit2 Performance criteria for accident leakage:

1. Main Steamline Break Faulted SG - 0.5 gpm at Room Temperature Each intact SG - 0.218 gpm at Room Temperature

2. Locked Rotor Total for all SGs -1.0 gpm at Room Temperature

3. Locked Rotor with Failed Open SG SG with failed open PORV - 0.5 gpm at Room Temperature Power Operated Relief Valve (PORV)

Each intact SG - 0.218 gpm at Room Temperature

4. Rod Cluster Control Assembly Eiection Total for all SGs - 1.0 gpm at Room Temperature

5. Steam Generator Tube Rupture Total for intact SGs - 1.0 gpm at Room Temperature (SGTR)

Plant i-Byron, Unit 1 Steam Generator Model(s)

Babcock & Wilcox feedring replacement steam generators Effective Full Power Years (EFPY) of Approximately 6.684 EFPY at time of last inspection in service for currently installed SGs March 2005 (i.e., Refueling Outage B1 R1 3)

Tubing Material Alloy 690 Number of tubes per SG 6,633 Number and percentage of tubes SG A SG B SG C SG D plugged in each SG 1

1 1

5

(-0.02%)

(-0.08%)

Number of tubes repaired in each SG None Degradation mechanisms identified Fan Bar Wear, Lattice Grid Wear, and Foreign Object Wear Current primary-to-secondary leakage limits:

per SG:

150 gallons per day Total:

600 gallons per day Leakage evaluated at:

Room Temperature Approved Alternate Tube Repair Criteria Not Applicable (ARC):

1. None Approved SG Tube Repair Methods:

Not Applicable

1. None Page 10 of 17

ATTACHMENT 1 Evaluation of Proposed Changes Plant :Byron, Unitli Performance criteria for accident leakage:

1. Main Steamline Break Faulted SG - 0.5 gpm at Room Temperature Each intact SG - 0.218 gpm at Room Temperature

2. Locked Rotor Total for all SGs -1.0 gpm at Room Temperature

3. Locked Rotor with Failed Onen SG SG with failed open PORV - 0.5 gpm at Room Temperature Power Operated Relief Valve (PORV)

Each intact SG - 0.218 gpm at Room Temperature

4. Rod Cluster Control Assembly Total for all SGs -1.0 gpm at Room Temperature Eiection Total for intact SGs - 1.0 gpm at Room Temperature

5. Steam Generator Tube Rupture (SGTR)

Plant';

Byro n, Unit 2 Steam Generator Model(s)

Westinghouse Model D5 Effective Full Power Years (EFPY) of Approximately 15.738 EFPY at time of last inspection in service for currently installed SGs October 2005 (i.e., Refueling Outage B2R1 2)

Tubing Material Alloy 600TT Number of tubes per SG 4,570 Number and percentage of tubes SG A SG B SG C SG D plugged in each SG 144 123 57 25

(-3.15%)

(-2.69%)

(-1.25%)

(-0.55%)

Number of tubes repaired in each SG None Degradation mechanisms identified Anti-Vibration Wear, Pre-Heater/Tube Support Plate Wear, and Foreign Object Wear Current primary-to-secondary leakage limits:

per SG:

150 gallons per day Total:

600 gallons per day Leakage evaluated at:

Room Temperature Approved Alternate Tube Repair Criteria (ARC):

1. Degradation found in the portion of Amendment 144, dated September 19, 2005, approved this the tube below 17 Inches from the allowance on a one-time basis for Refueling Outage 12 and top of the hot leg tubesheet does not the subsequent operating cycle.

require plugging or repair.

Page 11 of 17

ATTACHMENT 1 Evaluation of Proposed Changes Plant Byron, Unit 2 Approved SG Tube Repair Methods:

1. Laser welded sleeving as described in Amendment No. 58 dated March 4, 1994, approved use of a Westinghouse Technical Report WCAP-1 3698, Revision 1, "Laser Welded Sleeves for 3/4-and subject to the limitations and Inch Diameter Tube Feeding-Type and Westinghouse restrictions as approved by the NRC.

Preheater Steam Generators' Applicability limits: Elevated laser welded tubesheet sleeves (Laser welded sleeving methodology is not approved for use.

being deleted by this amendment Amendment No. 119 dated May 4, 2001, approved use of request)

WCAP-13698, Revision 4 for sleeve plugging criteria Sleeve plugging criteria: 38.7% of the nominal wall thickness.

2. TIG welded sleeving as described in Amendment No. 83 dated April 12, 1996 ABB Combustion Engineering Inc.,

Applicability limits:

Technical Reports: Licensing Report

1) A single tube may contain a maximum of one tubesheet CEN-621-P, Revision 00, sleeve and two support plate sleeves; "Commonwealth Edison Byron and

2)

Post Weld Heat Treatment is required on all freespan Braidwood Unit 1 and Unit 2 Steam welds; and Generators Tube Repair Using Leak

3)

Expanded Inspections are required for verification of Tight Sleeves, FINAL REPORT," April tube cleaning prior to welding.

1995; and Licensing Report CEN-627-P, Operating Performance of the Sleeve plugging criteria: 32% of the nominal wall thickness.

ABB CENO Steam Generator Tube Sleeve for use at Commonwealth Edison Byron and Braidwood Units 1 and 2,0 January 1996; subject to the limitations and restrictions as noted by the NRC Staff.

Performance criteria for accident leakage:

1. Main Steamline Break Faulted SG - 0.5 gpm at Room Temperature Each intact SG - 0.218 gpm at Room Temperature

2. Locked Rotor Total for all SGs - 1.0 gpm at Room Temperature

3. Locked Rotor with Failed Open SG SG with failed open PORV - 0.5 gpm at Room Temperature Power ODerated Relief Valve (PORV)

Each intact SG - 0.218 gpm at Room Temperature

4. Rod Cluster Control Assembly Eiection Total for all SGs - 1.0 gpm at Room Temperature

5. Steam Generator Tube Rupture Total for intact SGs - 1.0 gpm at Room Temperature (SGTR)

I 5.2 NO SIGNIFICANT HAZARDS CONSIDERATION Exelon Generation Company, LLC, (EGC) has reviewed the proposed no significant hazards consideration determination published on March 2, 2005 (i.e., 70 FR 10298) as part of the consolidated line item improvement process (CLIIP) item. EGC has concluded that the proposed determination presented in the notice is applicable to Braidwood Station, Units 1 and 2, and Byron Station, Units 1 and 2, and the determination is hereby incorporated by reference to satisfy the requirements of 10 CFR 50.91 (a), except as discussed below.

Page 12 of 17

ATTACHMENT 1 Evaluation of Proposed Changes The proposed amendment also revises the Technical Specification Task Force (TSTF)

Standard Technical Specification Change Traveler, TSTF-449, "Steam Generator Tube Integrity," Revision 4, version of TS 5.5.9, Steam Generator Program, to exclude the portion of the tube below 17 inches from the top of the hot leg tubesheet in the Braidwood Station, Unit 2, and Byron Station, Unit 2, steam generators from TS 5.5.9.d, "Provisions for SG tube inspections." This proposed license amendment request, in effect, redefines the Braidwood Station, Unit 2, and Byron Station, Unit 2, primary pressure boundary from the hot leg tube end weld to 17 inches below the top of the hot leg tube sheet. This proposed license amendment also deletes the current TS 5.5.9.e.6 and TS 5.5.9.e.10 allowance to use Westinghouse laser welded sleeves as a SG tube repair method.

EGC has evaluated whether or not a significant hazards consideration is involved with the proposed TS change by focusing on the three criteria set forth in 10 CFR 50.92 as discussed below:

Criteria

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

Response: No.

The previously analyzed accidents are initiated by the failure of plant structures, systems, or components. The proposed changes that alter the SG inspection criteria and delete the allowance to repair SG tubes using Westinghouse laser welded sleeves do not have a detrimental impact on the integrity of any plant structure, system, or component that initiates an analyzed event. The proposed changes will not alter the operation of, or otherwise increase the failure probability of any plant equipment that initiates an analyzed accident. Therefore, the proposed change does not involve a significant increase in the probability of an accident previously evaluated.

Of the applicable accidents previously evaluated, the limiting transients with consideration to the proposed changes to the SG tube inspection criteria, are the SG tube rupture (SGTR) event and the steam line break (SLB) accident.

During the SGTR event, the required structural integrity margins of the SG tubes will be maintained by the presence of the SG tubesheet. SG tubes are hydraulically expanded in the tubesheet area. Tube rupture in tubes with cracks in the tubesheet is precluded by the constraint provided by the tubesheet. This constraint results from the hydraulic expansion process, thermal expansion mismatch between the tube and tubesheet and from the differential pressure between the primary and secondary side. Based on this design, the structural margins against burst, discussed in Regulatory Guide (RG) 1.121, "Bases for Plugging Degraded PWR SG Tubes," are maintained for both normal and postulated accident conditions.

The proposed changes do not affect other systems, structures, components or operational features. Therefore, the proposed changes result in no significant increase in the probability of the occurrence of a SGTR accident.

Page 13 of 17

ATTACHMENT 1 Evaluation of Proposed Changes At normal operating pressures, leakage from primary water stress corrosion cracking (PWSCC) below the proposed limited inspection depth is limited by both the tube-to-tubesheet crevice and the limited crack opening permitted by the tubesheet constraint.

Consequently, negligible normal operating leakage is expected from cracks within the tubesheet region. The consequences of an SGTR event are affected by the primary-to-secondary leakage flow during the event. Primary-to-secondary leakage flow through a postulated broken tube is not affected by the proposed change since the tubesheet enhances the tube integrity in the region of the hydraulic expansion by precluding tube deformation beyond its initial hydraulically expanded outside diameter.

The probability of a SLB is unaffected by the potential failure of a SG tube as this failure is not an initiator for a SLB.

The consequences of a SLB are also not significantly affected by the proposed changes.

During a SLB accident, the reduction in pressure above the tubesheet on the shell side of the SG creates an axially uniformly distributed load on the tubesheet due to the reactor coolant system pressure on the underside of the tubesheet. The resulting bending action constrains the tubes in the tubesheet thereby restricting primary-to-secondary leakage below the midplane.

Primary-to-secondary leakage from tube degradation in the tubesheet area during the limiting accident (i.e., SLB) is limited by flow restrictions resulting from the crack and tube-to-tubesheet contact pressures that provide a restricted leakage path above the indications and also limit the degree of potential crack face opening as compared to free span indications. The primary-to-secondary leak rate during postulated SLB accident conditions would be expected to be less than that during normal operation for indications near the bottom of the tubesheet (i.e., including indications in the tube end welds). This conclusion is based on the observation that while the driving pressure causing leakage increases by approximately a factor of two, the flow resistance associated with an increase in the tube-to-tubesheet contact pressure, during a SLB, increases by up to approximately a factor of three. While such a leakage decrease is logically expected, the postulated accident leak rate could be conservatively bounded by twice the normal operating leak rate if the increase in contact pressure is ignored. Since normal operating leakage is limited to less than 0.104 gpm (150 gpd) per TS 3.4.13, URCS Operational Leakage," the associated accident condition leak rate, assuming all leakage to be from lower tubesheet indications, would be bounded by approximately 0.2 gpm. This value is well within the assumed accident leakage rate of 0.5 gpm discussed in Updated Final Safety Analysis Table 15.1-3, "Parameters Used in Steam Line Break Analyses." Hence it is reasonable to omit any consideration of inspection of the tube, tube end weld, bulges/overexpansions or other anomalies below 17 inches from the top of the hot leg tubesheet. Therefore, the consequences of a SLB accident remain unaffected.

Based on the above discussion, the proposed changes do not involve an increase in the consequences of an accident previously evaluated.

Page 14 of 17

ATTACHMENT 1 Evaluation of Proposed Changes

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

Response: No.

The proposed changes do not involve the use or installation of new equipment and the currently installed equipment will not be operated in a new or different manner. No new or different system interactions are created and no new processes are introduced. The proposed changes will not introduce any new failure mechanisms, malfunctions, or accident initiators not already considered in the design and licensing bases.

Based on this evaluation, the proposed change does not create the possibility of a new or different kind of accident from any accident previously evaluated.

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

Response: No.

The proposed changes maintain the required structural margins of the SG tubes for both normal and accident conditions. Nuclear Energy Institute (NEI) 97-06, "Steam Generator Program Guidelines," Revision 1 and Regulatory Guide (RG) 1.121, "Bases for Plugging Degraded PWR Steam Generator Tubes," are used as the bases in the development of the limited hot leg tubesheet inspection depth methodology for determining that SG tube integrity considerations are maintained within acceptable limits. RG 1.121 describes a method acceptable to the NRC for meeting General Design Criteria (GDC) 14, "Reactor coolant pressure boundary," GDC 15, "Reactor coolant system design," GDC 31, "Fracture prevention of reactor coolant pressure boundary," and GDC 32, "Inspection of reactor coolant pressure boundary," by reducing the probability and consequences of a SGTR. RG 1.121 concludes that by determining the limiting safe conditions for tube wall degradation the probability and consequences of a SGTR are reduced. This RG uses safety factors on loads for tube burst that are consistent with the requirements of Section III of the American Society of Mechanical Engineers (ASME) Code.

For axially oriented cracking located within the tubesheet, tube burst is precluded due to the presence of the tubesheet. For circumferentially oriented cracking, Westinghouse letter LTR-CDME-05-32, "Limited Inspection of the Steam Generator Tube Portion Within the Tubesheet at Byron Unit 2 and Braidwood Unit 2," Revision 2, dated August 2005, defines a length of degradation free expanded tubing that provides the necessary resistance to tube pullout due to the pressure induced forces, with applicable safety factors applied. Application of the limited hot leg tubesheet inspection depth criteria will preclude unacceptable primary-to-secondary leakage during all plant conditions. The methodology for determining leakage provides for large margins between calculated and actual leakage values in the proposed limited hot leg tubesheet inspection depth criteria.

Therefore, the proposed changes do not involve a significant hazards consideration under the criteria set forth in 10 CFR 50.92(c).

Page 15 of 17

ATTACHMENT 1 Evaluation of Proposed Changes 5.3 APPLICABLE REGULATORY REQUIREMENTS/CRITERIA The applicable regulatory requirements and guidance associated with this application are adequately addressed by the NRC Notice of Availability published on May 6, 2005 (i.e.,

70 FR 24126), the NRC Notice for Comment published on March 2,2005 (i.e., 70 FR 10298),

and TSTF-449, Revision 4, except as discussed below.

Section 182a of the Atomic Energy Act requires applicants for nuclear power plant operating licenses to include technical specifications (TS) as part of the license. The Commission's regulatory requirements related to the content of the TS are contained in Title 10, Code of Federal Regulations (10 CFR), Section 50.36, "Technical specifications." The TS requirements in 10 CFR 50.36 include the following categories: (1) safety limits, limiting safety systems settings and control settings, (2) limiting conditions for operation (LCO),

(3) surveillance requirements, (4) design features, and (5) administrative controls. The SG tube inspection requirements are included in the TS in accordance with 10 CFR 50.36(c)(5),

"Limiting Conditions for Operation."

As stated in 10 CFR 50.59, "Changes, tests, and experiments," paragraph (c)(1)(i), a licensee is required to submit a license amendment pursuant to 10 CFR 50.90, "Application for amendment of license or construction permit," if a change to the TS is required.

Furthermore, the requirements of 10 CFR 50.59 necessitate that the NRC approve the TS changes before the TS changes are implemented. EGC's submittal revising the requirements of TS 5.5.9, Steam Generator Program, as provided in TSTF-449, to exclude the portion of the tube below 17 inches from the top of the hot leg tubesheet in the Braidwood Station, Unit 2, and Byron Station, Unit 2, steam generators from TS 5.5.9.d, Provisions for SG tube inspections," and to delete Westinghouse laser welded sleeves as an approved SG tube repair method meets the requirements of 10 CFR 50.59(c)(1)(i) and 10 CFR 50.90.

RG 1.121 margins against burst are maintained for both normal and postulated accident conditions due to the constraint provided by the tubesheet.

NRC Information Notice 2005-09, "Indications in Thermally Treated Alloy 600 Steam Generator Tubes and Tube-to-Tubesheet Welds," dated April 7, 2005, provides additional regulatory insight regarding SG tube degradation.

6.0 ENVIRONMENTAL CONSIDERATION

EGC has reviewed the environmental evaluation included in the model SE published on March 2, 2005 (i.e., 70 FR 10298) as part of the CLIIP. EGC has concluded that the staff's findings presented in that evaluation are applicable to Braidwood Station and Byron Station, Units 1 and 2, and the evaluation is hereby incorporated by reference for this application, except as discussed below.

A review has determined that the proposed amendment revising the Technical Specification Task Force (TSTF) Standard Technical Specification Change Traveler, TSTF-449, "Steam Generator Tube Integrity," Revision 4, version of TS 5.5.9, Steam Generator Program, to exclude the portion of the tube below 17 inches from the top of the hot leg tubesheet in the Braidwood Station, Unit 2, and Byron Station, Unit 2, steam generators from TS 5.5.9.d, "Provisions for SG tube inspections," and to delete Westinghouse laser welded sleeves as an Page 16 of 17

ATTACHMENT 1 Evaluation of Proposed Changes approved SG tube repair method would change a requirement with respect to installation or use of a facility component located within the restricted area, as defined in 10 CFR 20, "Standards for protection against radiation," or would change an inspection or surveillance requirement. However, the proposed amendment 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 amendment meets the eligibility criterion for categorical exclusion set forth in paragraph (c)(9) of 10 CFR 51.22, "Criterion for categorical exclusion; identification of licensing and regulatory actions eligible for categorical exclusion or otherwise not requiring environmental review." Therefore, pursuant to 10 CFR 51.22(b), no environmental impact statement or environmental assessment need be prepared in connection with the proposed amendment.

7.0 PRECEDENT This application is being made in accordance with the CLIIP. EGC is, however, proposing a variation or deviation from the TS changes described in TSTF-449, Revision 4, or the NRC staff's model SE published on March 2, 2005 (i.e., 70 FR 10298). One variation revises the requirements of TS 5.5.9, Steam Generator Program, as provided in TSTF-449, to exclude the portion of the tube below 17 inches from the top of the hot leg tubesheet in the Braidwood Station, Unit 2, and Byron Station, Unit 2, steam generators from TS 5.5.9.d, "Provisions for SG tube inspections." The NRC has previously granted similar amendments, on a one-time basis, for Braidwood Station, Unit 2, and Byron Station, Unit 2, in References 6 and 7, respectively. A second variation deletes the allowance to use Westinghouse laser welded sleeves as a repair method.

8.0 REFERENCES

1.

Federal Register Notices:

Notice for Comment published on March 2, 2005 (i.e., 70 FR 10298).

Notice of Availability published on May 6, 2005 (i.e., 70 FR 24126).

2.

LTR-CDME-05-32, "Limited Inspection of the Steam Generator Tube Portion Within the Tubesheet at Byron 2 and Braidwood 2," Revision 2, dated August 2005

3.

NRC Information Notice 2005-09, "Indications in Thermally Treated Alloy 600 Steam Generator Tubes and Tube-to-Tubesheet Welds," dated April 7, 2005

4.

NEI 97-06, "Steam Generator Program Guidelines," Revision 1, dated January 2001

5.

Regulatory Guide 1.121, "Bases for Plugging Degraded PWR Steam Generator Tubes, " dated August 1976

6.

Letter from G. F. Dick (NRC) to C. M. Crane (Exelon Generation Company, LLC),

"Braidwood Station, Units 1 and 2 - Issuance of Exigent Amendments RE: Revision of Scope of Steam Generator Inspections for Unit 2 Refueling Outage 11," dated April 25, 2005

7.

Letter from J. B. Hopkins (NRC) to C. M. Crane (Exelon Generation Company, LLC),

"Byron Station, Unit 2 - Issuance of Amendment," dated September 19, 2005 Page 17of 17

-A BRAIDWOOD STATION UNITS 1 AND 2 Docket Nos. STN 50-456 and STN 50-457 License Nos. NPF-72 and NPF-77 Application for Technical Specification Improvement Regarding Steam Generator Tube Integrity Markup of Technical Specifications Pages ii 1.1-4 3.4.13-1 3.4.13-2 3.4.19-1 (new page) 3.4.19-2 (new page) 5.5-7 5.5-8 5.5-9 5.5-10 5.5-11 5.5-12 5.5-13 5.5-14 5.5-26 5.5-27 5.6-6

TABLE OF CONTENTS - TECHNICAL SPECIFICATIONS 3.4 REACTOR COOLANT SYSTEM (RCS) 3.4.1 RCS Pressure, Temperature, and Flow Departure from Nucleate Boiling (DNB) Limits............... 3.4.1-1 3.4.2 RCS Minimum Temperature for Criticality.............. 3.4.2-1 3.4.3 RCS Pressure and Temperature (P/T) Limits 3.4.3-1 3.4.4 RCS Loops-MODES 1 and 2.............................. 3.4.4-1 3.4.5 RCS Loops-MODE 3............................

3.4.5-1 3.4.6 RCS Loops-MODE 4...............................3.4.6-1 3.4.7 RCS Loops-MODE 5, Loops Filled........................ 3.4.7-1 3.4.8 RCS Loops-MODE 5, Loops Not Filled.................... 3.4.8-1 3.4.9 Pressurizer................................

3.4.9-1 3.4.10 Pressurizer Safety Valves...........................

3.4.10-1 3.4.11 Pressurizer Power Operated Relief Valves (PORVs)..... 3.4.11-1 3.4.12 Low Temperature Overpressure Protection (LTOP)

System....

3.4.12-1 3.4.13 RCS Operational LEAKAGE....

3.4.13-1 3.4.14 RCS Pressure Isolation Valve (PIV) Leakage.3.4.14-1 3.4.15 RCS Leakage Detection Instrumentation....

3.4.15-1 3.4.16 RCS Specific Activity....

3.4.16-1 3.4.17 RCS Loop Isolation Valves....

3.4.17-1 3.4.18 RCS LooDs-Isolated.....

3.4.18-1 13.4.19 Steam Generator (SG) Tube Integrity......

3.4.19-1 3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS) 3.5.1 Accumulators...

3.5.1-1 3.5.2 ECCS-Operating....

3.5.2-1 3.5.3 ECCS-Shutdown...

3.5.3-1 3.5.4 Refueling Water Storage Tank (RWST)....

3.5.4-1 3.5.5 Seal Injection Flow...

3.5.5-1 3.6 CONTAINMENT SYSTEMS 3.6.1 Containment....

3.6.1-1 3.6.2 Containment Air Locks....

3.6.2-1 3.6.3 Containment Isolation Valves....

3.6.3-1 3.6.4 Containment Pressure....

3.6.4-1 3.6.5 Containment Air Temperature....

3.6.5-1 3.6.6 Containment Spray and Cooling Systems....

3.6.6-1 3.6.7 Spray Additive System....

3.6.7-1

.3.6.8 (Deleted)............................................3.6.8-1 3.7 PLANT SYSTEMS 3.7.1 Main Steam Safety Valves (MSSVs)...

3.7.1-1 3.7.2 Main Steam Isolation Valves (MSIVs)...

3.7.2-1 3.7.3 Secondary Specific Activity...

3.7.3-1 3.7.4 Steam Generator (SG) Power Operated Relief Valves (PORVs)...

3.7.4-1 3.7.5 Auxiliary Feedwater (AF) System...

3.7.5-1 3.7.6 Condensate Storage Tank (CST)...

3.7.6-1 BRAIDWOOD -

UNITS 1 & 2 ATmendmTent F[3

Definitions 1.1 1.1 Definitions LEAKAGE LEAKAGE shall be:

a. Identified LEAKAGE

1. LEAKAGE, such as that from pump seals or valve packing (except Reactor Coolant pump (RCP) seal water injection or-leakoff),

that is captured and conducted to collection systems or a sump or collecting tank;

2. LEAKAGE into the containment atmosphere from sources that are both specifically located and known either not to interfere with the operation of leakage detection systems or not to be pressure boundary LEAKAGE; or

3. Reactor Coolant System (RCSLIEAKAGE through a $team Venerator Lp% to the Secondary System (primary to

b. Unidentified LEAKAGE secondary LEAKAGE)

All LEAKAGE (except RCP seal water injection or leakoff) that is not identified LEAKAGE;

c. Pressure Boundary LEAKAGE

[primary to secondary]l LEAKAGE (except LEAKAGE) through a nonisolable fault in an RCS component body, pipe wall, or vessel wall.

MASTER RELAY TEST A MASTER RELAY TEST shall consist of energizing each master relay and verifying the OPERABILITY of each relay. The MASTER RELAY TEST shall include a continuity check of each associated slave relay.

BRAIDWOOD - UNITS 1 & 2 1.1 - 4 Amendment D 3

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;Fe ay totaE enraos Se)

A 150 gallons per day primary to secondary LEAKAGE through any one e

r r

-3SG APPLICABILITY:

MODES 1, 2, operational ACTIONS 3, and 4.

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

other than pressure or primary to 1

boundary LEAKAGE*-

-(s~econdary 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 AND not 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.

LPrimary to secondary LEAKAGE not within Limit.

BRAIDWOOD - UNITS 1 & 2 3.4.13 - 1 Amendment F991

RCS Operationa1 LEAKAGE 3.4.13 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.13.1

-1PJ-

NOTEI J -------------

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.

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

72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months verify primary to secondary LEAKAGE is

150 gallons per day through any one SG.

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.

I 172 hours0.00199 days 0.0478 hours 2.843915e-4 weeks 6.5446e-5 months 12.

Not applicable to primary secondary LEAKAGE.

to I BRAIDWOOD - UNITS 1 & 2 3.4.13 - 2 Amendment X

INSERT NEW SPECIFICATION 3.4.19 SG Tube 3.4.19 I

3.4 REACTOR COOLANT SYSTEM (RCS) 3.4.19 Steam Generator (SG) Tube Integrity LCO 3.4.19 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

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

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 7 days satisfying the tube repair the affected tube(s) is criteria and not plugged or maintained until the next repaired in accordance with refueling outage or SG the Steam Generator tube inspection.

Program.

AND A.2 Plug or repair the affected tube(s) in Prior to entering accordance with the Steam MODE 4 following Generator Program.

the next refueling outage or SG tube inspection B.

Required Action and B.1 Be in MODE 3.

associated Completion Time 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months of Condition A not met.

AND OR B.2 Be in MODE 5.

36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months SG tube integrity not maintained.

I

\\ RAIDWOODB UNITS 1 & 2 3.4.19 - 1 Am(?ndment

INSERT NEW SPECIFICATION 3.4.19 SG Tube Ir)tegrit 3.4.19 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.19.1 Verify SG tube integrity in accordance with the Steam In accordance with Generator Program.

the Steam Generator Program SR 3.4.19.2 Verify that each inspected SG tube that satisfies the Prior to entering tube repair criteria is plugged or repaired in MODE 4 following a accordance with the Steam Generator Program.

SG tube inspection RAD I)OD - UNITS 1 & 2 3.4. 19 - 2 Amendment

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.9

[ INSERT 5.5 - 7 }-

Steam Generator (SG)ITube,8frveiltkinceiProcram Each SG shall be demonstrated 0 RABLE by performance of an Each SG shall be demonstrated Oft:RABLE by performance of an

/

augmented inservice inspectio program.

a.

SG Sample Selection nd Inspection Each SG shall b determined OPERABLE during shutdo by selecting and nspecting at least the minimum nu er of SGs specified t ale 5.5.9-1./

b.

SG Tube am le Selection and Inspection

/-----------------------NOTE ------- /------------

W n referring to an SG tube, the slede shall be considered part of the tube if the tube has en repaired per Specification 5.5.9.e.10.

/-

The SG tube minimum sample sze, inspection result.

classification, and the co esponding action required sha be as specified in Table.5.9-2. The inservice inspec on of SG tubes shall be p formed at the frequencies spec'fied in Specification 5.5.d and the inspected tubes sha be verified acceptablVper the acceptance criteria of Specification 5.

..e. When applying the expecta ons of Specification 5.9.b.1 through 5.5.9.b.3, previ us defects or imperfecti s in the area repaired by the s eve are not considered area requiring reinspection.

e tubes selected r each inservice inspection shal include 2 3% of the tot number of tubes in all SGs. Th tubes selected for t se inspections shall be selected n a random basis exc f Where experience in similar p nts with similar water chemistry indicates critical areas to be inspected, then 2 50% of the tubes inpected shall be from these critical areas; BRAIDWOOD - UNITS 1 & 2 5.5 - 7 AmendmentRI

Steam Generator Program (Braidwood)

INSERT 5.5-7 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.

Programs and Manuals

'5.5

5.5 Programs and Manuals 5.5.9 Si INSERT 5.5 - 8 team Generator (SG)1Tube,&Y`rvei nRcel ProQram (continued)

2.

The first sample of tube./selected for each inservice inspection (subsequent o the preservice inspection) of each SG shall inc Ahde:

i.

All tubes at previously had detectable e

wall pe rations > 20% that have not bon plugg or sleeved in the affected ar, and all tub that previously had detectabl sleeve wall p etrations that have not been p gged, ii. Tubes in those areas where ex rience has indicated potential problem iii. A tube inspection (purs nt to Specification 5;5.9.e ) shall be performed on each selected tube. If any selected tube does not permit the pacage of the eddy current probe for a tube insp tion, this shall be recorded and an adjace tube shall be selected and subjected t a tube inspection;

3.

The tubes sel ted as the second and third sames (if required by able 5.5.9-2) during each inservi e inspectio may be subjected to a partial tu inspec t n provided:

i.

The tubes selected for these sam es include the tubes from those areas of the e sheet array where tubes with imperfectio were previously found, and

/ i. The inspections include hose portions of the tubes where imperfect ns were previously found; BRAIDWOOD - UNITS 1 & 2 5.5 - 8 Amendment Fol]

Steam Generator Program (Braidwood)

INSERT 5.5-8

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 a total of 1 gpm for all SGs.

3.

The operational LEAKAGE performance criteria 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. For Unit 2 only, degradation identified in the portion of the tube from the top of the hot leg tubesheet to 17 inches below the top of the tubesheet shall be plugged or repaired upon detection. TIG welded sleeves found by inservice inspection to contain flaws with a depth equal to or exceeding 32% of the nominal wall thickness shall be plugged.

The following alternate tube repair criteria may be applied as an alternative to the 40% depth-based criteria:

1.

For Unit 2 only, degradation found in the portion of the tube below 17 inches from the top of the hot leg tubesheet does not require plugging or repair.

d.

Provisions for SG tube inspections.

Periodic SG tube inspections shall be performed. 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. For Unit 2, the portion of the tube below 17 inches from the top of the hot leg tubesheet is excluded. 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

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.9 Steam Generator (SG) [ube-&frvetJAUiEncelProaram (continued)

I INSERT 5.5 -9 J_

4. A random sample of > 2V of the total number of laser welded sleeves and > 4% of the total number of Tungsten Inert Gas VIG) welded sleeves installed shall be inspected or axial and circumferential indications at t end of each cycle. In the even that an imperfe ion exceeding the repair limit i detected, an ditional 20% of the unsampled sl yes shall be ins cted and if an imperfection exce ing the repair imit is detected in the second s ple, all remaining leeves shall be inspected. Thes inservice inspections will include the entire sleev, the tube at the eat treated area, and the tube-t -sleeve joint.

The inservice inspection for t e sleeves is req ired on all types of sleeves inst led in the SGs t demonstrate acceptable structural ntegrity;

5.

or Unit 2 during Refueling Outag 11, a 20% minimum sample of all inservice tubes fr the top of the hot leg tubesheet to 17 inches bel the top of the tubesheet shall be inspected rotating probe. This sample shall include a 20%

nimum sample of the total population of bulges and o rexpansions within the SG from the top of the hot 1Ig tubesheet to 17 inches below the top of the tu sheet..

Inspection Results Classif ation The results of each samp inspection shall be classified into one of the follow g three categories:'

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

Previously degradedtubes or sleeves must exhibit significant (> 10 of wall thickness) further wall penetrations to e included in the percentage cal ations.

Cateqorv nspection Results C-1

< 5% of the total tubes inspec d are degraded tubes and none-of the inspect tubes are defective.

C-2 One or more tubes, but <

of the total tubes inspected are defective or > 5% and

10% of the total tubes inspe ed are degraded tubes.

C-3

> 10% of the total ubes inspected are degraded tubes or > 1% of e inspected tubes are defective.

BRAIDWOOD - UNITS 1 & 2 5.5 - 9 Amendment F3q

Steam Generator Program (Braidwood)

INSERT 5.5-9 determine which inspection methods need to be employed and at what locations.

1.

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

2.

Inspect 100% of the Unit 1 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.

Inspect 100% of the Unit 2 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.

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 Unit 2 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

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.9 Steam Generator (SG) ITube,8-rvei-TrnceI Procram (continued)

d.

Inspection Frequencies

/

The inservice inspec *ons of SG tubes (dependent upon inspection results lassification) shall be performed a he following frequ cies:/

1.

The f st inservice inspection shall be per rmed af r 6 Effective Full Power months but 24 calendar months of initial critic ty.

Subsequent inservice inspections sha be performed at intervals > 12 calendar months and 24 calendar months after the previous inspec on; Extension Criteria: If two c secutive inspections, not including the preservi inspection, result in all inspection results fallVg into the C-1 category or if two consecutive inspe ions demonstrate that previously observed egradation has not continued and no additional deg dation has occurred, the inspection interval may be xtended to a maximum of once per 40 months.

exception to this Extension Criteria i that for Br dwood Unit 1 a one-time inspection interval xtension of a maximum of once per 40 mons is alloed for the inspection performed immedia y

folling the AlRO8 inspection. This is an e eption to whe Extension Criteria in that the inspe ion terval extension is based on the result f only one inspection result falling into the C-1 tegory; If the results of the inservice ins ction of an SG conducted in accordance with Tabl

.5.9-2 at 40 month intervals fall in Category C-3 he inspection frequency shall be increased o at least once per 20 months. The increase i inspection frequency shall apply until the subseque inspections satisfy the criteria of Specificatin 5.5.9.d.2; the interval may then be extended to maximum of once per 40 months; and i

i BRAIDWOOD -

UNITS 1 & 2 5.5 - 10 Amendment Fzf

Steam Generator Program (Braidwood)

INSERT 5.5-10 these Specifications, tube plugging is not a repair. All acceptable repair methods are listed below.

1. TIG welded sleeving as described in ABB Combustion Engineering Inc., Technical Reports:

Licensing Report CEN-621-P, Revision 00, "Commonwealth Edison.Byron and Braidwood Unit 1 and 2 Steam Generators Tube Repair Using Leak Tight Sleeves, FINAL REPORT," April 1995; and Licensing Report CEN-627-P, "Operating Performance of the ABB CENO Steam Generator Tube Sleeve for Use at Commonwealth Edison Byron and Braidwood Units 1 and 2," January 1996; subject to the limitations and restrictions as noted by the NRC Staff.

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.9 Steam Generator (SG) Tube ~urveillance Program (continued)

4.

Additi unscheduled inservice inspections s be perfmed on each SG in accordance with the rst ple inspection specified in Table 5.5 -2 during the shutdown subsequent to any of the ollowing conditions:

i.

Reactor to secondary e leaks (not including leaks originating m tube to tube sheet welds) in excess of th imits of LCO 3.4.13.d and LCO 3.4.13.e RCS Operational LEAKAGE",

ii. A seis 'c occurrence greater than the Operat' Ba Earthquake (OBE),/

ii. A Condition IV Loss Of Coolant Acci t CLOCA) requiring actuation of the Engin ed Safety Features, or iv. A Condition IV main ste line or feedwater line break.

The provisions of SR 3.0.

re not applicable to SG Tube Surveillance Program i ection frequencies.

BRAIDWOOD - UNITS 1 & 2 5.5 - 11 Amendment 0

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.9 Steam Generator (SG) Tube'Surveillance Pro ram (continued)

e.

Acceptance C eria

1.

erfection means an exception to the

ensions, fsinis or contour of a tube or sleev rom that required by fabrication drawings s

ecifications.

Eddy current testing indicatio'< 20 of the nominal tube or sleeve wall thickne

, if detectable, may be considered as imperfecti

2.

Degradation means ervice induced cracking, wastage, wear or general orrosion occurring on either inside or outside o a tube or sleeve;

3.

De rad ube means a tube or sleeve contain' unr ired imperfections 2 20% of the nom tube or eeve wall thickness caused by degrad on;

% Degradation means the percenta of the tube or sleeve wall thickness affecte r removed by degradation;

5.

Defect means an impe ction of such severity that it exceeds the plug '

or repair limit. A tube or sleeve containW an unrenaired defect is defective:

6.

Pl uqqin means the inAm:1 et

___--XtLOUbeyond whi ch 1 nx-~U ermvdEo-servic ao e

ie PEFripri-5;rra 0 The plugging or repair limit imperfection deth for the tubinq is equal to 40% of the nominal wall thickness. IThe pluqq g1Ei lidep~b~osillevesi The plugging limit imperfection depth for TIG welded sleeves is equal to 32% of the nominal wall thickness.

[

C~

C, Retained as 5.5.9.c in INSERT 5.5.8.

Editorial changes incorporated Retained as 5.5.9.c.1 in INSERT 5.5.8.

Editorial changes incorporated Retained as 5.5.9.c in INSERT 5.5.8.

Editorial changes incorporated

'For Unit 2ldurinn Outage 11 and t Subsqg~~pPtn cyce, thisghstn doe not "X~tD-t° dgaation hytrR in the p~orti-DoJF tube be o LL-v r om teol e

b~esteFet. Degradation found in the portion of the tube below 17 inches from the top of the hot leg tubesheet does not require plugging or repair.

For Unit 2g ef n

an t ilL eratin c cle idegradation identified in the portion of the tube from the top of the hot leg tubesheet to 17 inches below the top of the tubesheet shall be plugged or repaired upon detection; I/

i BRAIDWOOD - UNITS 1 & 2 5.5 - 12 Amendment Pq

Programs and Manuals

5.5 5.5 Programs and Manuals 5.5.9

Steam Generator (SG) Tube -urveillance Program (continued)

7.

ceable describes the condition of if it leaks or contains a defect large e to affect its structural integrity in the of an OBE, LOCA, or a steam line or feedwat me break as specified in Specification 5.5

..4;

8.

Tube I ction means an inspection of the SG the point of entry (hot leg side) c etely

,,-'Taround the U-bend to the top suppo the cold leg.

For a tube that has been re by sleeving, the tube inspection shall i e the sleeved portion of

,,,--'~

the tube._,-

I Retained in 5.5.9.d in INSERT 5.5-8

9.

Preservice Inspection means an. inspection of the full length of each tu.ri each SG performed by eddy current techniques prior to service to establ a

baseline cdition of the tubing. This i ection shall performed prior to initial M 1 operation us the equipment and technique pected to be-used ring subsequent inservice ctions;

10.

Tube'Repair refers to rocess that reestablishes tube serviceabilit.Acceptable.tube repairs wil e

performed by t ollowing processes:

i.

r~welded sleeving as describ n a estinghouse Technical Repor nd subject to the limitations and restrict s as approved.by the NRC, or I

Retained in 5.5.9.f in INSERT 5.5-9

}

TIG welded sleeving as described in ABB Combustion Engineering Inc., Technical Reports:

Licensing Report CEN-621-P, Revision 00, "Commonwealth Edison Byron and Braidwood Unit 1 and 2 Steam Generators Tube Repair Using Leak Tight Sleeves, FTNAL REPORT," April 1995; and Licensing Report CEN-627-P Operating Performance of the ABB CENO Steam Generator Tube Sleeve for Use at Commonwealth Edison Byron.and Braidwood Units 1 and 2," January 1996; subject to the limitations and restrictions as noted by the NRC Staff.

BRAIDWOOD - UNITS 1 & 2 5.5 - 13 Amendment PM

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.9 Steam Generator (SG) Tubq !Surveillance Pro ram (continued)

Tube air includes the removal of plugs tha ere pr ously installed as a corrective or pr entative easure. A tube inspection per Specification 5.5.9.e.8 is require ior to returning previously plugged tubes to ser

11.

The SG shall be determin PEPABLE after completing the corresponding act (s

(plug or repair in the affected area all es exceeding the plugging or repair limit) uired by Table 5.5.9-2; and

12.

For Uni during Refueling Outage 11 and the sub uent operating cycle:

/Bulce refers to a tube diameter devia n within the tubesheet of 18 volts or greater asured by bobbin coil probe; and Overexpansion refers to ube diameter deviation within the tubesheet 1.5 mils or greater as measured by bobV coil probe.

5.5.10 Secondary Water'Chemistrv Procram This program provides controls for monitoring secondary water chemistry to inhibit SG tube degradation. 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;

c.

Identification of process sampling points, which shall include monitoring the discharge of the condensate pumps for evidence of condenser inleakage;

d.

Procedures for the recording and management of data;

e.

Procedures defining corrective actions for all off control point chemistry conditions; and

f. *A procedure identifying the authority responsible for the interpretation of the data and the sequence and timing of administrative events, which is required to initiate corrective action.

BRAIDWOOD -

UNITS 1 & 2 5.5 -14 Amendment Im

Programs and Manuals 5.5 Table 5.5.9-1 (page 1 of 1)

Mi mum Number of Steam Generators to be nspected During Inservice Inspection Pr ervice Inspection Yes

o. of Steam Generators per Unit Four

/ First Inservice Inspection/

Two Second & Subsequent Inservice Inspections One W)

(a) The inservice inspection may be imited to one steam generator on a rotating schedule encomp sing 3 N % of the tubes (where N is the number of steam gen ators in the unit) if the results of the first or pr ious inspections indicate that all steam generators are perf ming in a like manner. Note that under some circumstances the operating conditions in one or more steam generators y be found to be more severe than those in other steam nerators. Under such circumstances the sample sequence shal be modified to inspect the most severe conditions.

Each the other two steam generators not inspected during e first inservice inspections shall.be inspected durinthe second and third inspections. The fourt and subsequent nspections shall follow the instructions described abo e.

RAIDWOOD - UNITS 1 & 2 5.5 - 26 Amendment 98

Table 5.5.9-2 (page 1 of 1)

Steam Generator Tube Inspection Programs and Manuals 5.

1st Sample Inspectfon 2nd Sample Inspection 3rd Sample jzspection Result Action Nuired Result Action Required Result Actign Required C-1 None N/A N/A N/A N/P C-2 P1 ug repair C-1 None N/A A

defe ive tubes, C-2 Plug or repair C-1 None and nspect defective tubes,

/

ad itional and inspect C-Plug or repair 2 tubes in this additional defective tubes 4G.45 tubes in this

-3 Perform action SG.

for C-3 result I /of first sample.

C-3 Perform action N/A N/A for C-3 result

/_. ___

of first sam e.

/ C-3 inspect all tubes in this SG, plug or rep air defective tubes, and inspect 2S tubes in each other SG.

Al I other SGs C-1 None N/A N/A Any Perfor action N/A N/A other SC for -2 result C-2 but of econd no other s ple.

SG C-3 I

Any other/SE A

Inspect all tubes in each'SG and plug or regair defective tubes.

N/A N/A

+/-

(a)

Sample size s Where:

N =

e number n =

he number RAIDWOOD - UNITS 1 & 2 11 be a minimum of S t S = 3 N %

n of SGs in the unit (4) of SGs inspected durin 5.5 - 27 ubes per SG:

, and g an inspecti Amendment 98

Reporting Requirements 5.6 5.6 Reporting Requirements 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 in the Inservice Inspection Summary Report in accordance with 10 CFR 50.55a and ASME Section XI,'1992 Edition with the 1992 Addenda.

5.6.9 I INSERT 5.6-6 Steam Generator (SG) Tube Inspection Report1

a.

Following each inservice pection of SG tubes, the number tubes plugged or repai in each SG shall be reported t he NRC within 15 days

b.

The complet esults of the SG tube inservice pection shall be submi d to the NRC within 12 months fo owing the compl on of the inspection. The repo shall include:

Number and extent of tubes

pected,

2.

Location and percent wall thickness penetration for each indication o n imperfection, and

3.

Identific t of tubes plugged or repaired.

c.

Results of tube ins ections that fall into egory C-3 shall b eported to te NRC within 30 day nd prior to resu ion of unit operation. The repo1shall provide a cri tion of investigations conduc to determine cause of he tube degradation and correcti'measures taken to prevent recurrence.

BRAIDWOOD -

UNITS 1 & 2 5.6 - 6 Amendment ffz

Steam Generator (SG) Tube Inspection Report INSERT 5.6-6 A report shall be submitted within 180 days after the initial entry into MODE 4 following completion of an inspection performed in accordance with 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.

-B BYRON STATION UNITS 1 AND 2 Docket Nos. STN 50-454 and STN 50-455 License Nos. NPF-37 and NPF-66 Application for Technical Specification Improvement Regarding Steam Generator Tube Integrity Markup of Technical Specifications Pages ii 1.1-4 3.4.13-1 3.4.13-2 3.4.19-1 (new page) 3.4.19-2 (new page) 5.5-7 5.5-8 (Byron Unit 1) 5.5-9 (Byron Unit 2) 5.5-9 5.5-10 5.5-11 (Byron Unit 1) 5.5-12 (Byron Unit 2) 5.5-12 (Byron Unit 1) 5.5-13 (Byron Unit 2) 5.5-13 (Byron Unit 1) 5.5-14 (Byron Unit 2) 5.5-14 5.5-26 5.5-27 5.6-6

TABLE OF CONTENTS - TECHNICAL SPECIFICATIONS 3.4 REACTOR COOLANT SYSTEM (RCS) 3.4.1 RCS Pressure, Temperature, and Flow Departure from Nucleate Boiling (DNB) Limits............... 3.4.1-1 3.4.2 RCS Minimum Temperature for Criticality..............

3.4.2-1 3.4.3 RCS Pressure and Temperature (P/T) Limits........

3.4.3-1 3.4.4 RCS Loops-MODES 1 and 2............................. 3.4.4-1 3.4.5 RCS Loops-MODE 3.....................................

3.4.5-1 3.4.6 RCS Loops-MODE 4.....................................

3.4.6-1 3.4.7 RCS Loops-MODE 5, Loops Filled....................... 3.4.7-1 3.4.8 RCS Loops-MODE 5, Loops Not Filled.................... 3.4.8-1 3.4.9 Pressurizer.....................................

3.4.9-1 3.4.10 Pressurizer Safety Valves............................. 3.4.10-1 3.4.11 Pressurizer Power Operated Relief Valves (PORVs).....

3.4.11-1 3.4.12 Low Temperature Overpressure Protection (LTOP)

System................................. 3.4.12-1 3.4.13 RCS Operational LEAKAGE..............

3.4.13-1 3.4.14 RCS Pressure Isolation Valve (PIV) Leakage........... 3.4.14-1 3.4.15 RCS Leakage Detection Instrumentation.......

........ 3.4.15-1 3.4.16 RCS Specific Activity................................ 3.4.16-1 3.4.17 RCS Loop Isolation Valves............................. 3.4.17-1 3.4.18 RCS LoODS-Isolated.................................

3.4.18-1 13.4.19 Steam Generator (SG) Tube Interity.................

t 3.4.19-1 3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS) 3.5.1 Accumulators.3.5.1-1 3.5.2 ECCS-O erating.3.52-1 3.5.3 ECCS-Shut..wn.3.5.3-1 3.5.4 Refueling Water Storage Tank

.RWT..

3.5.4-1 3.5.5 Seal Injection Flow.3.5.5-1 3.6 CONTAINMENT SYSTEMS 3.6.1 Containment......................

3.6.1-1 3.6.2 Containment Air Locks.......................

3.6.2-1 3.6.3 Containment Isolation Valves......................

3.6.3-1 3.6.4 Containment Pressure......................

3.6.4-1 3.6.5 Containment Air Temperature......................

3.6.5-1 3.6.6 Containment Spray and Cooling Systems.......

3.6.6-1 3.6.7 Spray Additive System............................

3.6.7-1 3.6.8 (Deleted)............................

3.6.8-1 3.7 PLANT SYSTEMS 3.7.1 Main Steam Safety Valves (MSSVs)..................... 3.7.1-1 3.7.2 Main Steam Isolation Valves (MSIVs).................. 3.7.2-1 3.7.3 Secondary Specific Activity.......................... 3.7.3-1 3.7.4 Steam Generator (SG) Power Operated Relief Valves (PORVs).......................

3.7.4-1 3.7.5 Auxiliary Feedwater (AF) System..........

3.7.5-1 3.7.6 Condensate Storage Tank (CST)............

........ 3.7.6-1 BYRON -

UNITS 1 & 2 ii Amrendment PM

Definitions 1.

1.1 Definitions LEAKAGE LEAKAGE shall be:

a. Identified LEAKAGE

1. LEAKAGE, such as that from pump seals or valve packing (except Reactor Coolant pump (RCP) seal water injection or-leakoff),

that is captured and conducted to collection systems or a sump or collecting tank;

2. LEAKAGE into the containment atmosphere from sources that are both specifically located and known either not to interfere with the operation of leakage detection systems or not to be pressure boundary LEAKAGE; or

3. Reactor Coolant System (RCS1_LEAKAGE through a Steam Aenerator LEG] to the Secondary System (primary to

b. Unidentified LEAKAGE secondary LEAKAGE)

All LEAKAGE (except RCP seal water injection or leakoff) that is not identified LEAKAGE;

c. Pressure Boundary LEAKAGE primary to secondaryl LEAKAGE (except ELEAKAGE) through a nonisolable fault in an RCS component body, pipe wall, or vessel wall.

MASTER RELAY TEST A MASTER RELAY TEST shall consist of energizing each master relay and verifying the OPERABILITY of each relay. The MASTER RELAY TEST shall include a continuity check of each associated slave relay.

BYRON - UNITS 1 & 2 1.1 - 4 Amendment ZW

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;fii 600 yallonS per day total y

KAGE

A Ul

150 gallons per day primary to secondary LEAKAGE through any one g rS or(G APPLICABILITY:

MODES 1, 2,

_ operational I 1ACTIONS 3, and 4.

CONDITION REQUIRED ACTION COMPLETION TIME A.

RCS LEAKAGE not within A.1 Reduce LEAKAGE to 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months limits for reasons within limits.

other than pressure _

or primary to boundary LEAKAGE.-----

secondary 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 AND not 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.

\\O Piary_

to secondary.

LEAKAGE not within

,i mi t.

BYRON - UNITS 1 & 2 3.4.13 - 1 Amendment W

RCS Operational LEAKAGE 3.4.13 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.13.1

NOTE S -------------

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.

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

72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months SR 3.4.13.2 Verif e nerator tube in I

ccrE dance wit h

eneJ~UG~rator Tub w 4ith the Skam eera ube lVerify primary to secondary LEAKAGE is.

p grm X

Ls 150 gallons per day through any one SG.

J I

I

5rs

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.3 F2.

Not applicable to secondary LEAKAGE.

primary toI BYRON - UNITS 1 & 2 3.4.13 - 2 Amendment W

INSERT NEW SPECIFICATION 3.4.19

/

3.4 REACl SG Tube Integrity 3.4.19 FOR COOLANT SYSTEM (RCS) 3.4.19 Steam Generator (SG) Tube Integrity LCO 3.4.19 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 NOTE-----------------------------------------

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 7 days satisfying the tube repair the affected tube(s) is criteria and not plugged or maintained until the next repaired in accordance with refueling outage or SG the Steam Generator tube inspection.

Program.

AND A.2 Plug or repair the affected tube(s) in Prior to entering accordance with the Steam MODE 4 following Generator Program.

the next refueling outage or SG tube inspection B. Required Action and B.1 Be in MODE 3.

associated Completion Time 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months of Condition A not met.

AND B.2 Be in MODE 5.

36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months SG tube integrity not maintained.

I BYRON -

UNITS 1 & 2 3 4 1 m n m n 3.4.19 - 1 Amendment/

INSERT NEW SPECIFICATION 3.4.19 SG Tube Integri t 3.4.19 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.19.1 Verify SG tube integrity in accordance with the Steam In accordance with Generator Program.

the Steam Generator Program SR 3.4.19.2 Verify that each inspected SG tube that satisfies the Prior to entering tube repair criteria is plugged or repaired in MODE 4 following a accordance with the Steam Generator Program.

SG tube inspection YRON -

UNITS 1 & 2 3.4. 19 - 2 Amendment

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.9

[ INSERT 5.5-7 }J Steam Generator (SG)1Tubea frvei;Jk~nce Procram Each SG shall be demonstrated 0 RABLE by performance of an augmented inservice inspectio program.

a.

SG Sample Selection d Inspection Each SG-shall be etermined OPERABLE during shutdo by selecting and specting at least the minimum nu er of SGs specified ink ble 5.5.9-1./

b.

SG Tube SD le Selection and Inspection

-NOTE -- ---

--e- -----

Whe referring to an SG tube, the sleee shall be considered a art of the tube if the tube has en repaired per pecification 5.5.9.e.10.

The SG tube minimum sample s e, inspection result classification, and the co esponding action required shall be as specified in Table

.5.9-2. The inservice inspectio of SG tubes shall be p formed at the frequencies specif-d in Specification 5.5.d and the inspected tubes shall e verified acceptabl per the acceptance criteria of Specification 5.5.e. When applying the expectat ns of Specification 5.9.b.1 through 5.5.9.b.3, previo s defects or imperfecti s in the area repaired by the sle are not considered area requiring reinspection. T tubes selected r each inservice inspection shal include 2 3% of the tot number of tubes in all SGs. Th tubes selected for t se inspections shall be selected n a random basis Where experience in similar ants with similar water chemistry indicates critic areas to be inspected, then -

50% of the tubes i spected shall be from these critical areas; BYRON - UNITS 1 & 2 5.5 - 7 Amendment Om

Steam Generator Program (Byron)

INSERT 5.5-7 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.

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.9 S.

[ INSERT 5.5 -8 }

team Generator (SG) Tube,8 1rvei.2iknce1 ProQram (continued)

2.

The first sample of t bes selected for each inservice inspection (subsequF t to the preservice inspection) of each SG shall dclude:

i.

All tub that previously had detectable e

wall netrations,> 20% that have not b plu ed or sleeved in the affected ar

, and all t es that previously had detectabl sleeve wall enetrations that have not been p gged, i.

Tubes in those areas where ex rience has indicated potential problem iii. A tube inspection (purs nt to Specification 55.9.e

) shall be performed on each selected tube.

f any selected tube does not permit the pa age of the eddy current probe for a tube insp tion, this shall be recorded and an adjace tube shall be selected and subjected t a tube inspection;

3.

The tubes sel ted as the second and third samp s (if required by able 5.5.9-2) during each inserv ce inspectio' may be subjected to a partial t e inspec t n provided:

i.

The tubes selected for these s les include the tubes from those areas of th u e sheet array where tubes with imperfecti s were previously found, and ii. The inspections inc those portions of the tubes where imperf ions were previously found; BYRON - UNITS 1 & 2 5.5 - -8 Amendment PZ

Steam Generator Program (Byron)

INSERT 5.5-8

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 a total of 1 gpm for all SGs.

3.

The operational LEAKAGE performance criteria 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.

For Unit 2 only, degradation identified in the portion of the tube from the top of the hot leg tubesheet to 17 inches below the top of the tubesheet shall be plugged or repaired upon detection. TIG welded sleeves found by inservice inspection to contain flaws with a depth equal to or exceeding 32% of the nominal wall thickness shall be plugged.

The following alternate tube repair criteria may be applied as an alternative to the 40% depth-based criteria:

1.

For Unit 2 only, degradation found in the portion of the tube below 17 inches from the top of the hot leg tubesheet does not require plugging or repair.

d.

Provisions for SG tube inspections.

Periodic SG tube inspections shall be performed.

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.

For Unit 2, the portion of the tube below 17 inches from the top of the hot leg tubesheet is excluded. 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

Programs and Manuals

.5.5 5.5 Programs and Manuals 5.5.9 Steam Generator (SG) Nube-,SvetiTSnce Proqram (continued)

C INSERT 5.5 - 9 }

4.

A random sample of 20 of the total number of laser welded sleeves and Ž 0% of the total number of Tungsten Inert Gas IG) welded sleeves installed shall be inspecte for axial and circumferential indications at t e end of each cycle. In the even that an imperf tion exceeding the repair limit i detected, an dditional 20% of the unsampled sl ves shall be in ected and if an imperfection exce ing the repair imit is detected in the second s ple, all remainingsleeves shall be inspected. 'Thes inservice inspect ns will include the entire sleev, the tube at th eat treated area, and the tube-t -sleeve join.

The inservice inspection for t e sleeves is re ired on all types of s eeves inst led in the SGs t demonstrate acceptable structural ntegrity.

Ins tion Results Classification T results of each sample inspectio shall be classified to one of the following three ca gories:

/-----------------------------NOT Previously degraded tubes or s eves must exhibit significant (> 10% of wall t ckness) further wall penetrations to be included n the percentage calculations.

Categorv Inspection sults C-1

< 5% of e total tubes inspected are degra ed tubes aid none of the inspected tubes are defecX e./

C-2 On r more tubes, but < 1%

of the to 1 tubes i pected are defective, or 2 5% and/< 10% of e total tubes inspected are degr ed tubes.

C-3

> 10% of the total tubes inspec d are degraded tubes or > 1% of the inspected ubes are defective.

BYRON - DU T25 9A n

t 5.5 - 9 Amendment W

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.9 Steam Generator (SG) [ubeSd'rveiJAsf nce Program (continued)

4.

A random sample of >

of the total number of laser welded sleeves and Ž 0% of the total number of Tungsten Inert Gas IG) welded sleeves installed shall be inspecte for axial and circumferential indications at t e end of each cycle. In the even that an imperf tion exceeding the repair limit i detected, an dditional 20% of the unsampled sl yes shall be insected and if an imperfection exce ing the repair imit is detected in the second sa ple, all remainin sleeves shall be inspected. Thes inservice inspectins will include the entire sleeve the tube at the/eat treated area; and the tube-t sleeve joint.

The inservice inspection for t e sleeves is-re ired on all types of sleeves inst led in the SGs tf demonstrate acceptable structural ntegrity;

5.

or Unit 2 during Refueling Outag 12, a 20% minimum sample of all inservice tubes fr the top of the hot leg tubesheet to 17 inches bel the top of the tubesheet shall be inspected rotating probe. This sample shall include a 20%

nimum sample of the total population of bulges and o rexpansions within the SG from the top of the hot 1g tubesheet to 17 inches

/~1,., 4thI,

-Xn 4n" 4-k

+

4h.hn 7

I INSERT 5.5 -9 }

/: I UW Lile LUp UT LI IC LU bI=L.-

Inspection Results Classifi ation The results of each samp e inspection shall be classified into one of the follow' g three categories:

-~-------------------/ ------NOTE -------------

Previously degrade tubes or sleeves must exhibit significant (> 10 of wall thickness) further wall penetrations to e included in the percentage calc ations.

Catec orv nspection Results C-1

< 5% of the total tubes inspect are degraded tubes and none of the inspecte tubes are defective.

C-2 One or more tubes, but < 1% of the total tubes inspected are defective, r 2 5% and < 10% of the total tubes inspect d are degraded tubes.

C-3

> 10% of the total t es inspected are degraded tubes or > 1% of t inspected tubes are defective.

BYRON -

UNIT1&

5 5.5 - 9 Amendment WI

Steam Generator Program (Byron)

INSERT 5.5-9 determine which inspection methods need to be employed and at what locations.

1.

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

2.

Inspect 100% of the Unit 1 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.

Inspect 100% of the Unit 2 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.

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 Unit 2 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

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.9 INSERT 5.5 - 1O0 Steam Generator (SG)WTube 8rrveij i PceIProaram (continued)

d.

Inspection Frequencies The inservice inspect s of SG tubes (dependent upon inspection results assification) shall be performed the following frequen es:

1.

The fir inservice inspection shall be pe ormed after Effective Full Power months but calendar months of initial criti'ity.

tsequent inservice inspections sh be performed at intervals 2 12 calendar months ant* 24 calendar months after the previous inspe ion;

2.

Extension Criteria: If two onsecutive inspections, not including the preser ce inspection, result in all inspection results fallng into the C-1 category or if two consecutive insp tions demonstrate that previously observ degradation has not continued an no additional d radation has occurred, the inspec on interval may extended to a maximum of once p 40 months;

3.

If the esults of the inservice inspectio of an SG cond ted in accordance with Table 5.5. -2 at 40 month i rvals fall in Category C-3, the ipection equency shall be increased to at east once per 20 months. The increase in insp tion frequency shall apply until the subsequent ins ctions satisfy the criteria of Specification 5..9.d.2; the interval may then be extended to a maxi m of once per 40 months; and

/

BYRON -

UNITS 1 & 2 5.5 - 10 Amendment W

Steam Generator Program (Byron)

INSERT 5.5-10 these Specifications, tube plugging is not a repair.

All acceptable repair methods are listed below.

1.

TIG welded sleeving as described in ABB Combustion Engineering Inc., Technical Reports: Licensing Report CEN-621-P, Revision 00, "Commonwealth Edison Byron and Braidwood Unit 1 and 2 Steam Generators Tube Repair Using Leak Tight Sleeves, FINAL REPORT," April 1995; and Licensing Report CEN-627-P, "Operating Performance of the ABB CENO Steam Generator Tube Sleeve for Use at Commonwealth Edison Byron and Braidwood Units 1 and 2," January 1996; subject to the limitations and restrictions as noted by the NRC Staff.

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.9 Steam Generator (SG) Tube,86rveillance Pro ram (continued)

4.

Additio a unscheduled inservice inspections s 1 be perf fmied on each SG in accordance with the rst pie inspection specified in Table 5.5 -2 during the shutdown subsequent to any of th ollowing conditions:

i.

Reactor to secondary e leaks (not including leaks originating tube to tube sheet welds) in excess of th imits of LCO 3.4.13.d and LCO 3.4.13.

RCS Operational LEAKAGE",

ii. A sei

c occurrence greater than the Operati Ba Earthquake (OBE),/

ii A Condition IV Loss Of Coolant Accid (LOCA) requiring actuation of the Engine d Safety Features, or iv. A Condition IV main ste ne or feedwater line break.

The provisions of SR 3.0. M not applicable to SG Tube Surveillance Program i ection frequencies.

BYRON -

UNITS 1 & 2 5.5 - 11 Amendment El

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.9 Steam Generator (SG) Tube urveillance Pro ram (continued)

e.

Acceptance C eria

1.

erfection means an exception to the

nsions, finisn or contour of a tube or sleev rom that required by fabrication drawings s

ecifications.

Eddy current testing indicatio

< 20 of the nominal tube or sleeve wall thickne

, if detectable, may be considered as imperfecti s;

2.

Degradation means service induced cracking, wastage, wear or general orrosion occurring on either inside or outside o tube or sleeve;

3.

De rad Tube means a tube or sleeve containi unr ired imperfections 2 20% of the nomi tube or eeve wall thickness caused by degrada n;

% Degradation means the percentag f the tube or sleeve wall thickness affected removed by.

degradation;

5.

Defect means an imper tion of such severity that it exceeds the pluggi or repair limit. A tube or sleeve containi an unrepaired-defect is defective; serv orreairedb slh The plugging or repair limit imperfection de th for the tubing is equal to 40% of the nominal wall thickness IThe lain mt

]

imperfection deo ded>

-rewTIEs eevoi-q~~

t3te o al wall-tjh+<Fn-

-IThe plugging limit imperfection depth for TIG welded sleeves is equal to 32% of the nominal wall thickness; C

Retained as 5.5.9.c in INSERT 5.5.8.

Editorial changes incorporated 7.

BYRON -

5 5 - 1A e d nt 5.5 - 12 Amendment m

Programs and Manuals

.5.5 5.5 Programs and Manuals 5.5.9 Steam Generator (SG) Tube urveillance Program (continued)

e.

Acceptance C Xeria

1.

erfection means an exception to the

nsions, finish or contour of a tube or sleev rom that required by fabrication drawings s ecifications.

Eddy current testing indicatio

< 20t of the nominal tube or sleeve wall thickne

, if detectable, may be considered as imperfect s;

2.

Degradation means service induced cracking, wastage, wear or general orrosion occurring on either inside or outside o tube or sleeve;

3.

De rad Tube means a tube or sleeve containi unr aired imperfections 2 20% of the nomi tube or eeve wall thickness caused by degrada

% Degradation means the percenta f the tube or sleeve wall thickness affected removed by degradation;

5.

Defect means an imper ction of such severity that it exceeds the pluggi or repair limit. A tube or sleeve containi an unrepaired defect is defective:

6. 1lu Lmtmeans the.

iper becyonde Ate remove seri pirdb e

ugging or repair limit imperfection et for the tubinq is egual to 40% of_

the nominal wlthickness.l The Dlgia_4mrl Rit

'on Setr-dezt u rt-Lr Wer-waed Slevsi-:f ll;:¢b~lavrzP_ n oml!nal wal~

isE lTepugn

.limit imperfection depth for TIG welded sleeves is

, equal to 32% of the nominal wall thickness.

C, Retained as 5.5.9.c in INSERT 5.5.8.

Editorial changes incorporated Retained as 5.5.9.c.1 in INSERT 5.5.8.

Editorial changes incorporated Retained as 5.5.9.c in INSERT 5.5.8.

Editorial changes incorporated For Unit 2lduring Refuelng Outage 12 and te Subeu etoerin cle, this~dfnt~ does not aeration C cle egrada the portioniedin t

e belor o *t e from the top of thehoetlTe g

bubehE~tI Degradation found in the portion of the tube below 17 inches from the top of the hot leg tubesheet does not require plugging or repair.

iFor Unit 21 the portion of the tuefo he top of the hot leg tubesheet to 17 inches below the top of the tubesheet shall be plugged or repaired upon detection; C

BYRON -

5.5 - 12 AmendmentPri

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.9 Steam Generator (SG) Tube S<rveillance Pro ram (continued)

8.

Tube I ion means an inspection of the SG tu from the nt of entry (hot leg side) completely und the end to the top support of the cold leg.

or a tube that has been repaired by sleeving, th ube inspection shall include the sleeved portion o he tube;

9.

Preservice Inspection means nspection of the full length of each tube in e SG performed by eddy current techniWques prior to sehic Ro establish a baseline

/lcondition of the aond This inspection shall be performed prior,,edq initial MODE 1 operation using the Combusent ion Engiqes Incted to be used durits:

subseq inservice inspec ions; 0

10.

T en ePair refers to a process that reesaidwoo es tube r and2Sty.

Acceptable tube repai Using Le Lieerforsed by the following process r

o

i.

Laser welded sleeving Gnscribed in a Westinghouse Technia port and subject to t he limitations and restrictions as approved by the

/

~NRC, or

/

ii. TIG welded sleeving as described in ABB Combustion Engineering Inc., Technical Reports:

Retie in 5.5.

Licensing Report CEN-621-P, Revision 00, L Reta"Commonwealth Edison Byron and Braidwood Unit 1 and 2 Steam Generators Tube Repair Using Leak Tight Sleeves, FINAL REPORT," April 1995; and Licensing Resort CEN-627-P, Operating Performance of the ABB CENO Steam Generator Tube Sleeve for Use at Commonwealth Edison Byron and Braidwood Units 1 and 2," January 1996; subject to the limitations and restrictions as noted by the NRC Staff.

Tube repair incl d

~moval of plugs prev csy~~alled as a correct'Xen~ peventative emEsre. A tube inspecto Specification 5.5.9.egB_

is required pjiug-b neturning previously bes tos

,and BYRON 5.5 - 13 Amendment I

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.9 Steam Generator (SG) uT~e-Srveillance Procram (continued)

7.

erviceable describes the condition leaks or contains a defect large gh to affect its structural integrity in th nt of an OBE, LOCA, or a steam line or fee line break as specified in Specificat d.4;

8. T ection means an inspection of th be from he point of entry (hot leg side) co e

tely around the U-bend to the top support of cold leg.

For a tube that has been repaired seeving, the tube inspection shall include th e yed ortion of the tube.

l Retained in 5.5.9.d in INSERT 5.5-8 Y_

below 17 inches from the top of the hot leg tut is excluded; I

tube

)esheet

9.

Preservice Inspection Dns an inspection of the full length of each tub n each SG performed by eddy rent techniques pri o service to establish a ba me condition the tubing. This inspection >iall be perfor prior to initial MODE 1 ope ion using the e

ment and techniques expectedW be used during ubsequent inservice inspecti

10.

Tube Repair refers to rocess that reestablishes tubed serviceability. A ta le tube repairs will be performed by t ollowing processes:

i.

L welded sleeving as describ na estinghouse Technical Repor d subject to the limitations and restricti as approved by the NRC, or C

Retained in 5.5.9.J in I

INSERT 5.5-9 TIG welded sleeving as described in ABB Combustion Engineering Inc., Technical Reports:

Licensing Report CEN-621-P, Revision 00, "Commonwealth Edison Byron and Braidwood Unit 1 and 2 Steam Generators Tube Repair Using Leak Tight Sleeves. FINAL R

" April 1995; and Licensing Report CEN-627-P, Operating Performance of the ABB CENO Steam Generator Tube Sleeve for Use at Commonwealth Edison Byron and Braidwood Units 1 and 2," January 1996; subject to the limitations and restrictions as noted by the NRC Staff.

BYRON -

5.5 - 13 Amendment 01

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.9 Steam Generatoird G-Tby TlSurveillance Program (c

11.

The SG shall b e i JPR Eater completing the co as~nin~ctions (plug or repair in the d~~e~~

____---~~ raal tbs exceeding theI p~sS~s Ea r lmit

____-----~~~-required by Table i-ir--

5.5.10 Secondary Water Chemistry Proaram This program provides controls for monitoring secondary water chemistry to inhibit SG tube degradation. 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;

c.

Identification of process sampling points, which shall include monitoring the discharge of the condensate pumps for evidence of condenser inleakage;

d.

Procedures for the recording and management of data;

e.

Procedures defining corrective actions for all off control point chemistry conditions; and

f.

A procedure identifying the authority responsible for the interpretation of the data and the sequence and timing of administrative events, which is required to initiate corrective action.

BYRON -

5.5 - 14 Amendment 0

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.9 Steam Generator (SG) Tu urveillance Pro ram (continued)

Tube Xa ir includes the removal of plugs tha e

p eously installed as a corrective or pr ntative asure.

A tube inspection per Specifi ion 5.5.9.e.8 is required prior to returning prev sly plugged tubes to service;

11.

The SG shall be detemine ERABLE after completing the corresponding actions ug or repair in the affected area all tubes exc ing the plugging or repair limit) required by Tab 5.5.9-2; and

12.

For Unit during Refueling Outage 12 and the subs ent operating cycle:

ulge refers to a tube diameter deviat' within the tubesheet of 18 volts or greater as asured by bobbin coil probe; and Overexpansion refers to be diameter deviation within the tubesheet

.5 mils or greater as measured by bobbin coil pro 5.5.10 Secondary Water Chemistry Program This program provides controls for monitoring secondary water chemistry to inhibit SG tube degradation. 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;

c.

Identification of process sampling points, which shall include monitoring the discharge of the condensate pumps for evidence of condenser inleakage;

d.

Procedures for the recording and management of data;

e.

Procedures defining corrective actions for all off control point chemistry conditions; and

f.

A procedure identifying the authority responsible for the interpretation of the data and the sequence and timing of administrative events, which is required to initiate corrective action.

BYRON - U N

- 1 A

2 5.5 - 14 Amendment VE

Programs and Manuals 5.5 Table 5.5.9-1 (page 1 of 1)

Mi *mum Number of Steam Generators to be nspected During Inservice Inspection P /ervice Inspection

/

Yes

o. of Steam Generators pei First Inservice Inspection Second & Subsequent Inservi r Unit Four Two ice Inspections Oneta)

(a) The inservice inspection may be mited to one steam generator on a rotating schedule encompas ing 3 N % of the tubes (where N is the number of steam gener tors in the unit) if the results of the first or prev ous inspections indicate that all steam generators are perfo ing in a like manner. Note that under some circumstances, he operating conditions in one or more steam generators ma be found to be more severe than those in other steam g erators. Under such circumstances the.

sample sequence shall/e modified to inspect the most severe conditions. Each of the other two steam generators not inspected during t first inservice inspections shall be inspected during e second and third inspections. The fourth and subsequent i spections shall follow the instructions described abov

/YRON - UNITS 1 & 2 5.5 -

26 Amendment 106

Table 5.5.9-2 Steam Generator Programs and Manuals 5.

(page 1 of 1)

Tube Inspection 1st Sample Inspectfon'a) 2nd Sample Inspection 3rd Sample gspection Result Action Wquired Result Action Required Result Actin Required C-1 None N/A N/A N/A NIK C-2 Plug repair C-1 None N/A YA defe ive tubes, C-2 Plug or repair C-1

'None and nspect defective tubes,

/

ad itional and inspect C-Plug or repair 2 tubes in this additional

/

defective tubes 4S tubes in this

-3 Perform action SG.

.for C-3 result

/__,___of first sample.

C-3 Perform action N/A N/A for C-3 result

/_____ of first sampe.

C-3 Inspect all All None N/A N/A tubes in this other SG, plug or SGs repair defective C-1 tubes, and Any Perforc action N/A N/A nspect 2$ tubes other SC for -2 result in each other C-2 but of econd SG.

no other s ple.

SG C-3 /

Any Inspect all N/A N/A other/SE tubes in each SG/

C

~and plug or/

m eair defective/

/ tubes./

(a)

Sample size s all be a minimum of S tubes per SG:

/

S =3 N%

n Where:/

N =

e number of SGs in the unit (4), and n = he number of SGs inspected during an inspecti

/YRON - UNITS 1 & 2 5.5 - 27

/

Amendment 106

Reporting Requirements 5.6 5.6 Reporting Requirements 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 in the Inservice Inspection Summary Report in accordance with 10 CFR 50.55a and ASME Section XI, 1992 Edition with the 1992 Addenda.

5.6.9 Steam Generator (SG) Tube Inspection Report C

INSERT 5.6-6

a.

Following each inservice p'ection of SG tubes, the number of tubes plugged or r ired in each SG shall be reporte o

the NRC within 15 s.

b.

The complet esults of the SG tube inservice ection shall be itted to the NRC within 12 moing the comp on of the inspection. The re shall include:

Number and extent of tubes

pected,

2.

Location and percent' wall thickness penetration for each indication o n imperfection, and

3.

Identificat of tubes plugged, or repaired.

c.

Results of tube inspections that fall into egory C-3 shall b eported to the NRC within 30 day hnd prior to resu ion of unit operation. The repo 1shall provide a cription of investigations conduc to determine cause of the tube degradation and corre ye measures taken to prevent recurrence.

BYRON - UNITS 1 & 2 5.6 - 6 Amendment tfub

Steam Generator (SG) Tube Inspection Report INSERT 5.6-6 A report shall be submitted within 180 days after the initial entry into MODE 4 following completion of an inspection performed in accordance with 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 eac SG, and

i.

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

-A BRAIDWOOD STATION UNITS 1 AND 2 Docket Nos. STN 50-456 and STN 50-457 License Nos. NPF-72 and NPF-77 Application for Technical Specification Improvement Regarding Steam Generator Tube Integrity Typed Technical Specifications Pages ii 1.1-4 3.4.13-1 3.4.13-2 3.4.19-1 3.4.19-2 5.5-7 5.5-8 5.5-9 5.5-10 5.5-11 5.5-12 5.5-13 5.5-14 5.5-15 5.5-16 5.5-17 5.5-18 5.5-19 5.5-20 5.5-21 5.6-6

TABLE OF CONTENTS - TECHNICAL SPECIFICATIONS 3.4

'REACTOR COOLANT SYSTEM (RCS) 3.4.1 RCS Pressure, Temperature, and Flow Departure from Nucleate Boiling (DNB) Limits 3.4.1-1 3.4.2 RCS Minimum Temperature for Criticality

.3.4.2-1 3.4.3 RCS Pressure and Temperature (P/T) Limits............ 3.4.3-1 3.4.4 RCS Loops-MODES 1 and 2

.............................. 3.4.4-1 3.4.5 RCS Loops-MODE 3.....................................

3.4.5-1 3.4.6 RCS Loops-MODE 4.....................................

3.4.6-1 3.4.7 RCS Loops-MODE 5, Loops Filled....................... 3.4.7-1 3.4.8 RCS Loops-MODE 5, Loops Not Filled..........

. 3.4.8-1 3.4.9 Pressurizer................................

3.4.9-1 3.4.10 Pressurizer Safety Valves...................

' 3.4.10-1 3.4.11 Pressurizer Power Operated Relief Valves (PORVs)..... 3.4.11-1 3.4.12 Low Temperature Overpressure Protection (LTOP)

System..............

......... 3.4.12-1 3.4.13 RCS Operational LEAKAGE.3.4.13-1 3.4.14 RCS Pressure Isolation Valve '(PIV) Leakage........... 3.4.14-1 3.4.15 RCS Leakage Detection Instrumentation............... 3.4.15-1 3.4.16 RCS Specific Activity......................

3.4.16-1 3.4.17 RCS Loop Isolation Valves...................

3.4.17-1 3.4.18 RCS Loops-Isolated..........................

3.4.18-1 3.4.19 Steam Generator (SG) Tube Integrity.3.4.19-1 3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS) 3.5.1 Accumulators............................

3.5.1-1 3.5.2 ECCS-Operating..........................

3.5.2-1 3.5.3 ECCS-Shutdown.3.5.3-1 3.5.4 Refueling Water Storage Tank (RWST).3.5.4-1 3.5.5 Seal Injection Flow.3.5.5-1 3.6 CONTAINMENT SYSTEMS 3.6.1 Containment.....................

3.6.1-1 3.6.2 Containment Air Locks.....................

3.6.2-1 3.6.3 Containment Isolation Valves.....................

3.6.3-1 3.6.4 Containment Pressure... '

3.6.4-1 3.6.5 Containment Air Temperature.

3.6.5-1 3.6.6 Containment Spray and Cooling Systems

...... 3.6.6-1 3.6.7 Spray Additive System.............................

-.3.6.7-1 3.6.8 (Deleted)........................................... 3.6.8-1 3.7 PLANT SYSTEMS 3.7.1 Main Steam Safety Valves (MSSVs).

3.7.1-1 3.7.2 Main Steam Isolation Valves (MSIVs) 3.7.2-1 3.7.3 Secondary Specific Activity.3.7.3-1 3.7.4 Steam Generator (SG) Power Operated Relief Valves (PORVs)................

3.7.4-1 3.7.5 Auxiliary Feedwater (AF) System..

3.7.5-1 3.7.6 Condensate Storage Tank (CST)....

3.7.6-1 BRAIDWOOD -

UNITS 1 & 2 ii Amnendment

Definitions 1.1 1.1 Definitions LEAKAGE LEAKAGE shall be:

a. Identified LEAKAGE

1. LEAKAGE, such as that from pump seals or valve packing (except Reactor Coolant pump (RCP) seal water injection or leakoff),

that is captured and conducted to collection systems or a sump or collecting tank;

2. LEAKAGE into the containment atmosphere from sources that are both specifically located and known either not to interfere with the operation of leakage detection systems or not to be pressure boundary LEAKAGE; or

3. Reactor Coolant System (RCS) LEAKAGE through a steam generator to the Secondary System (primary to secondary.LEAKAGE);

b. Unidentified LEAKAGE All LEAKAGE (except RCP seal water injection or leakoff) that is not identified LEAKAGE;

c. Pressure Boundary LEAKAGE LEAKAGE (except primary to secondary LEAKAGE) through a nonisolable fault in an RCS component body,'pipe wall, or vessel wall.

MASTER RELAY TEST A MASTER RELAY TEST shall consist of energizing each master relay and verifying the OPERABILITY of each relay. The MASTER RELAY TEST shall include a continuity check of each associated slave relay.

BRAIDWOOD -

UNITS i & 2 1.1 - 4 Amendment

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; and

d. 150 gallons per day primary to secondary LEAKAGE through any one steam generator (SG).

I I

APPLICABILITY:

MODES 1, 2, 3, and 4.

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

limits for reasons other than pressure boundary LEAKAGE or primary to secondary 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 AND not 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.

OR Primary to secondary LEAKAGE not within limit.

BRAIDWOOD - UNITS 1 & 2 3.4.13 - 1 Amendment

RCS Operational LEAKAGE 3.4.13 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY

+

SR 3.4.13.1

NOTES-------------------

1. 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.

2. Not applicable to primary to secondary LEAKAGE.

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

72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months SR 3.4.13.2

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.

Verify primary to secondary LEAKAGE is 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months

< 150 gallons per day through any one SG.

BRAIDWOOD -

UNITS 1 & 2 3.4.13 - 2 Amendment

SG Tube Integrity 3.4.19 3.4 REACTOR COOLANT SYSTEM (RCS) 3.4.19 Steam Generator (SG) Tube Integrity LCO 3.4.19 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 NOTE-----------------------------------------

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 7 days satisfying the tube of the affected repair criteria and tube(s) is maintained not plugged or until the-next repaired in accordance refueling outage or with the Steam SG tube inspection..

Generator Program.

AND A.2 Plug or repair the Prior to affected tube(s) in entering MODE 4 accordance with the following the Steam Generator next refueling Program. -

outage 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 AND not 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.

BRAIDWOOD -

UNITS 1 & 2 3.4.19 - 1 Amendment I

SG Tube Integrity 3.4.19 SURVEILLANCE REQUIREMENTS __

SURVEILLANCE FREQUENCY SR 3.4.19.1 Verify SG tube integrity in accordance with In accordance the Steam Generator Program.

with the Steam Generator Program SR 3.4.19.2 Verify that each inspected SG tube that Prior to satisfies the tube repair criteria is entering MODE 4 plugged or-repaired in accordance with the following a SG Steam Generator Program.

tube inspection BRAIDWOOD -

UNITS 1 & 2 3.4.19 Amendment I

Programs and Manuals

5. 5 5.5 Programs and Manuals 5.5.9 Steam Generator (SG) Program 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.

BRAIDWOOD -

UNITS 1 & 2 5.5 - 7 Amendment

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.9 Steam Generator (SG) ProQram (continued)

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 a total of 1 gpm for all SGs.

3.

The operational LEAKAGE performance criteria 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.

For Unit 2 only, degradation identified in the portion of the tube from the top of the hot leg tubesheet to 17 inches below the top of the tubesheet shall be plugged or repaired upon detection. TIG welded sleeves found by inservice inspection to contain flaws with a depth equal to or exceeding 32% of the nominal wall thickness shall be plugged.

The following alternate tube repair criteria may be applied as an alternative to the 40% depth-based criteria:

1.

For Unit 2 only, degradation found in the portion of the tube below 17 inches from the top of the hot leg tubesheet does not require plugging or repair.

d.

Provisions for SG tube inspections.

Periodic SG tube inspections shall be performed. 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. For Unit 2 the portion of the tube below 17 inches from the top of the hot leg tubesheet is excluded. 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 BRAIDWOOD - UNITS 1 & 2 5.5 - 8 Amendment

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.9 Steam Generator (SG) Program (continued) determine which inspection methods need to be employed and at what locations.

1.

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

2.

Inspect 100% of the Unit 1 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.

Inspect 100% of the Unit 2 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.

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 Unit 2 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 BRAIDWOOD - UNITS 1 & 2 5.5 - 9 Amendment

Programs and Manuals

.5.5 5.5 Programs and Manuals 5.5.9 Steam Generator (SG) Program (continued) these Specifications, tube plugging is not a repair.- All acceptable repair methods are listed below.

1.

TIG welded sleeving as described in ABB Combustion Engineering Inc., Technical Reports:

Licensing Report CEN-621-P, Revision 00, "Commonwealth Edison Byron and.

Braidwood Unit 1 and 2 Steam Generators Tube Repair Using Leak Tight Sleeves, FINAL REPORT," April 1995; and Licensing Report CEN-627-P, "Operating Performance of the ABB CENO Steam Generator Tube Sleeve for Use at Commonwealth Edison Byron and Braidwood Units 1 and 2," January 1996; subject to the limitations and restrictions as noted by the NRC Staff.

5.5.10 Secondary Water Chemistry Program This program provides controls for monitoring secondary water chemistry to inhibit SG tube degradation. 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;

c.

Identification of process sampling points, which shall include monitoring the discharge of the condensate pumps for evidence of condenser inleakage;

d.

Procedures for the recording and management of data;

e.

Procedures defining corrective actions for all off control point chemistry conditions; and

f.

A procedure identifying the authority responsible for the interpretation of the data and the sequence and timing of administrative events, which is required to initiate corrective action.

BRAIDWOOD - UNITS 1 & 2 5.5 - 10 Amendment

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.11 Ventilation Filter Testina Proaram (VFTP)

A program shall be established to implement the following required testing of Engineered Safety Feature (ESF) filter ventilation systems at the frequencies specified in conformance with Regulatory Guide'1.52, Revision 2, and ANSI N510-1980, with any exceptions noted in Appendix A of the UFSAR.

BRAIDWOOD - UNITS 1 & 2

.5.5 - 11

. Amendment I

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.11 Ventilation Filter Testing Program (VFTP)

(continued)

a.

Demonstrate for each of the ESF filter systems that an inplace test of the High Efficiency Particulate Air (HEPA) filters shows a penetration specified below when tested in conformance with Regulatory Guide 1.52, Revision 2, and ANSI N510-1980, with any exceptions noted in Appendix A of the UFSAR, at the system flow rate specified below. Verification of the specified flow rates may be accomplished during the performance of SRs 3.7.10.4, 3.7.12.4, and 3.7.13.5,.as applicable:

ESF Ventilation System Flow Rate Penetration Control Room Ventilation (VC)

Filtration System (makeup)

Nonaccessible Area Exhaust Filter Plenum Ventilation System (after structural maintenance of the HEPA filter housings)

Nonaccessible Area Exhaust Filter Plenum Ventilation System (for reasons other than structural maintenance of the HEPA filter housings)

Fuel Handling Building Exhaust Filter Plenum (FHB)

Ventilation System 2 5400 cfm and

< 6600 cfm 2 60,210 cfm and

' 73,590 cfm per train, and 2 20,070 cfm and

< 24,530 cfm per bank 2 60,210 cfm and

< 73,590 cfm per train 2 18,900 cfm and

< 23,100 cfm

< 0.05%

< 1%

BRAIDWOOD - UNITS 1 & 2 5.5 - 12 Amendment I

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.11 Ventilation Filter Testing Program (VFTP) (continued)

b.

Demonstrate for each of the ESF filter systems that an inplace test of the charcoal adsorber shows a bypass specified below when-tested in conformance with Regulatory Guide 1.52, Revision 2, and ANSI N510-1980, with any exceptions noted in Appendix A of the UFSAR, at the system flow rate specified below. Verification of the specified flow rates may be accomplished during the performance of SRs 3.7.10.4, 3;7.12.4, and 3.7.13.5, as applicable:

ESF Ventilation System Flow Rate 2 5400 cfm and

< 6600 cfm Bypass

< 0.05%

VC Filtration System (makeup)

VC Filtration System

.(recirculation, charcoal bed after complete or partial replacement)

VC Filtration System (recirculation for reasons other than complete or partial charcoal bed replacement)

Nonaccessible Area Exhaust Filter Plenum Ventilation System (after structural maintenance of the charcoal adsorber housings)

Nonaccessible Area Exhaust Filter Plenum Ventilation System (for reasons other than structural maintenance of the charcoal adsorber

-housings)

FHB Ventilation System 2 44,550 cfm and

< 54,450 cfm 2 44,550 cfm and

< 54,450 cfm 2 60,210 cfm and

< 73,590 cfm per train, and 2 20,070 cfm and.

< 24,530 cfm per bank

< 0.1%

< 2%

< 1%

2 60,210

< 73,590 train cfm and cfm per 2 18,900 cfm and

< 23,100 cfm per train BRAIDWOOD - UNITS 1 & 2

.5.5 - 13 Amendment I

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.11 Ventilation Filter Testing Program (VFTP) (continued)

c.

Demonstrate for each of the ESF filter systems that a laboratory test of a sample of the charcoal adsorber, when

-obtained as described in Regulatory Guide 1.52, Revision 2, shows the methyl iodide penetration less than the value specified below when tested in conformance with Regulatory Guide 1.52, Revision 2, ANSI N510-1980, and ASTM D3803-1989, with any exceptions noted in Appendix A of the UFSAR, at a temperature of.300C and a Relative Humidity (RH) specified below:

ESF Ventilation System Penetration RH VC Filtration System 0.5%

70%

(makeup)

VC Filtration System 4%.

70%

(recirculation)

Nonaccessible Area 4.5%

70%

Exhaust Filter Plenum Ventilation System FHB Ventilation System 10%

95%

d.

Demonstrate for each of the ESF filter systems that the pressure drop across the combined HEPA filters and the charcoal adsorbers is < 6 inches of water gauge when tested in conformance with Regulatory Guide 1.52, Revision 2, and ANSI N510-1980, with any exceptions noted in Appendix A of the UFSAR, at the system flow rate specified below. Verification of the specified flow rates may be accomplished during the performance of SRs 3.7.10.4, 3.7.12.4, and 3.7.13.5, as applicable:

ESF Ventilation System Flow Rate VC Filtration System 2Ž5400 cfm and < 6600 cfm (makeup)

Nonaccessible Area -

60,210 cfm and

-Exhaust Filter Plenum

< 73,590 cfm per train Ventilation System FHB Ventilation System 2 18,900 cfm and

< 23,100 cfm BRAIDWOOD - UNITS 1 & 2 5.5 - 14 Amendment I

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.11 Ventilation Filter Testing Program (VFTP) (continued)

e.

Demonstrate for each of the ESF filter systems that a bypass test of the combined HEPA filters and damper leakage shows a total bypass specified below at the system flow rate specified below. Verification of the specified flow rates may be accomplished during the performance of SRs 3.7.12.4 and 3.7.13.5, as applicable:

ESF Ventilation System Nonaccessible Area Exhaust Filter Plenum Ventilation System FHB Ventilation System Flow Rate 2> 60,210 cfm and

< 73,590 cfm per train 2 18,900 cfm and

< 23,100 cfm Bypass

< 1%

f.

Demonstrate that the heaters for each of the ESF filter systems dissipate the value specified below when tested in conformance with ANSI N510-1980, with any exceptions noted Appendix A of the UFSAR.

in ESF Ventilation System Wattage VC Filtration System The provisions of SR 3.0.2 test frequencies.

< 29.9 kW and 2 24.5 kW and SR 3.0.3 are applicable to the VFTP BRAIDWOOD -

UNITS 1 & 2 5.5 - 15 Amendment I

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.12 Explosive Gas and StoraQe Tank Radioactivity Monitoring Program This program provides controls for potentially explosive gas mixtures contained in the waste gas system, the quantity of radioactivity contained in gas-decay tanks-or fed into the off gas treatment system, and the quantity of radioactivity contained in unprotected outdoor liquid storage tanks. The gaseous radioactivity quantities shall be determined following the methodology in Branch Technical Position (BTP) ETSB 11-5, "Postulated Radioactive Release due to Waste Gas System Leak or Failure." The liquid radwaste quantities shall be determined in accordance with the ODCM.

The program shall include:

a.

The limits for concentrations of hydrogen and oxygen in the waste gas system and a surveillance program to ensure the limits are maintained. Such limits shall be appropriate to the system's design criteria (i.e., whether or not the system is designed to withstand a hydrogen explosion);

b.

A surveillance program to ensure that the quantity of radioactivity contained in each gas decay tank and fed into the offgas treatment system is less than the amount that would result in a whole body exposure of 2 0.5 rem to any individual in an unrestricted area, in the event of an uncontrolled release of the tanks' contents; and

c.

A surveillance program to ensure that the quantity of radioactivity contained in all outdoor liquid radwaste tanks that are not surrounded by liners, dikes, or walls, capable of holding the tanks' contents and that do not have tank overflows and surrounding area drains connected to the liquid radwaste treatment system is less than the amount that would result in concentrations less than the limits of 10 CFR 20, Appendix B, Table 2, Column 2, at the nearest potable water supply and the nearest surface water supply in an unrestricted area, in the event of an uncontrolled release of the tanks'.

contents.

The provisions of SR 3.0.2 and SR 3.0.3 are applicable to the Explosive Gas and Storage Tank Radioactivity Monitoring Program surveillance frequencies.

BRAIDWOOD -

UNITS 1 & 2 5.5 -

16 Amendment

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.13 Diesel Fuel Oil Testing Program A diesel fuel oil testing program to implement required testing of both new fuel oil and stored fuel oil shall be established. The

--program shall-include sampling and testing requirements, and acceptance criteria, all in accordance with applicable ASTM Standards. The purpose of the program is to establish the following:

a.

Acceptability of new fuel oil for use prior to addition to storage tanks by determining that the fuel oil has:

1.

an API gravity or an absolute specific gravity within

limits,

2.

a flash point and kinematic viscosity within limits, and

3.

a clear and bright appearance with proper color or a water and sediment content within limits;

b.

Other properties of new fuel oil are within limits within 30 days following sampling and addition to storage tanks; and

c.

Total particulate concentration of the fuel oil is < 10 mg/l when tested every 31 days.

The provisions of SR 3.0.2 and SR 3.0.3 are applicable to the Diesel Fuel Oil Testing Program test frequencies.

BRAIDWOOD - UNITS 1 & 2 5.5 - 17 Amendment Il

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.14 Technical Specifications (TS) Bases Control Program This program provides a means for processing changes to the Bases of these Technical Specifications.

a.

Changes to the Bases of the TS shall be made under appropriate administrative controls and reviews.

b.

Licensees may make changes to Bases without prior NRC approval provided the changes do not require either of the following:

1.

a change in the TS incorporated in the license; or

2.

a change to the UFSAR or Bases that requires NRC approval pursuant-to 10 CFR 50.59.

c.

The Bases Control Program shall contain provisions to ensure that the Bases are maintained consistent with the UFSAR.

d.

Proposed changes that meet the criteria of Specification 5.5.14.b above shall be reviewed and approved by the NRC prior to implementation. Changes to the Bases implemented without prior NRC approval shall be provided to the NRC on a frequency consistent with 10 CFR 50.71(e) as modified by approved exemptions.

BRAIDWOOD - UNITS 1 & 2 5.5 - 18 Amendment I

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.15 Safety Function Determination Program (SFDP)

This program ensures loss of safety function is detected and appropriate actions taken.

Upon entry into LCO 3.0.6, an evaluation shall be made to determine if loss of safety function exists.

Additionally, other appropriate actions may.be taken as a result of the support system inoperability and corresponding exception to entering supported system Condition and Required Actions. This program implements the requirements of LCO 3.0.6. The SFDP shall contain the following:

a.

Provisions for cross train checks to ensure a loss of the capability to perform-the safety function assumed in the accident analysis does not go undetected;

b.

Provisions for ensuring the plant is maintained in a safe condition if a loss of function condition exists;

c.

Provisions to ensure that an inoperable supported system's Completion Time is not inappropriately extended as a result of multiple support system inoperabilities; and

d.

Other appropriate limitations and remedial or compensatory actions.

A loss of safety function exists when, assuming no concurrent single failure, a safety function assumed in the accident analysis cannot be performed.

For the purpose of this program, a loss of safety function may exist when a support system is inoperable, and:

a.

A required system redundant to the system(s) supported by the inoperable support system is also inoperable; or

b.

A required system redundant to the system(s) in turn supported by the inoperable supported system is also inoperable; or

c.

A required system redundant to the support system(s) for the supported systems (a) and (b) above is also inoperable.

BRAIDWOOD -

UNITS 1 & 2 5.5 - 19 Amendment I

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.15 Safety Function Determination Program (SFDP) (continued)

The SFDP identifies where a loss of safety function exists. If a loss of safety function is determined to exist by this program, the appropriate Conditions and Required Actions of the LCO in which the loss of safety function exists are required to be entered.

5.5.16 Containment Leakage Rate Testing Program A program shall be established to implement the leakage rate testing of the containment as required by 10 CFR 50.54(o) and 10 CFR 50, Appendix J, Option B, as modified by approved exemptions. This program shall be in accordance with the guidelines contained in Regulatory Guide 1.163, September 1995 and NEI 94-01, Revision 0.

The peak calculated containment basis loss of coolant accident, 38.4 psig for Unit 2 internal pressure for the design Pa, is 42.8 psig for Unit 1 and The maximum allowable containment leakage rate, L., at Pa, shall be 0.10% of containment air weight per day.

Leakage Rate acceptance criteria are:

a.

Containment leakage rate acceptance criterion is < 1.0 La.

During the first unit startup following testing in accordance with this program, the leakage rate acceptance criteria are

< 0.60 La for the Type B and C tests and < 0.75 La for Type A tests; and BRAIDWOOD -

UNITS 1 & 2

.5.5 - 20 Amendment Il

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.16 Containment Leakage Rate Testing Proaram (continued)

b.

Air lock testing acceptance criteria are:

1.

Overall air lock leakage rate is < 0.05 La when tested at 2 Pa; and

2.

For each door, seal leakage rate is:

i. < 0.0024 La, when pressurized to 2 3 psig, and ii.

< 0.01 La, when pressurized to 2 10 psig.

The provisions of SR 3.0.2 do not apply to the test frequencies specified in the Containment Leakage Rate Testing Program.

The provisions of SR 3.0.3 are applicable to the Containment Leakage Rate Testing Program.

5.5.17 Battery Monitoring and Maintenance Program This program provides for restoration and maintenance, based on the recommendations of IEEE Standard 450, "IEEE Recommended Practice for Maintenance, Testing, and Replacement of Vented Lead-Acid Batteries For Stationary Applications," or of the battery manufacturer of the following:

a.

Actions to restore battery cells with float voltage

< 2.13 V, and

b.

Actions to equalize and test battery cells that had been discovered with electrolyte-level below the minimum-established design limit.

BRAIDWOOD -

UNITS 1 & 2 5.5 - 21 Amendment I

Reporting Requirements 5.6 5.6 Reporting Requirements 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 in the Inservice Inspection Summary Report in accordance with 10 CFR 50.55a and ASME Section XI, 1992 Edition with the 1992 Addenda.

5.6.9 Steam Generator (SG) Tube Inspection Report I

A report shall be submitted within 180 days after the initial entry into MODE 4 following completion of an inspection performed in accordance with 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 repairs in each SG, and

i.

Repair method utilized and the number each repair method.

all plugging and tube of tubes repaired by BRAIDWOOD -

UNITS 1 & 2 5.6 - 6 Amendment

-B BYRON STATION UNITS 1 AND 2 Docket Nos. STN 50-454 and STN 50-455 License Nos. NPF-37 and NPF-66 Application for Technical Specification Improvement Regarding Steam Generator Tube Integrity Typed Technical Specifications Pages ii 1.1-4 3.4.13-1 3.4.13-2 3.4.19-1 3.4.19-2 5.5-7 5.5-8 5.5-9 5.5-10 5.5-11 5.5-12 5.5-13 5.5-14 5.5-15 5.5-16 5.5-17 5.5-18 5.5-19 5.5-20 5.5-21 5.6-6

TABLE OF CONTENTS - TECHNICAL SPECIFICATIONS ' '

3.4 3.4.1 3.4.2 3.4.3 3.4.4 3.4.5 3.4.6 3.4.7 3.4.8 3.4.9 3.4.10 3.4.11 3.4.12 3.4.13 3.4.14 3.4.15 3.4.16 3.4.17

.3.4.18 3.4.19 3.5 3.5.1 3.5.2 3.5.3 3.5.4 3.5.5 3.6 3.6.1 3.6.2 3.6.3 3.6.4 3.6.5 3.6.6 3.6.7 3.6.8 3.7 3.7.1 3.7.2 3.7.3 3.7.4 3.7.5 3.7.6 REACTOR COOLANT SYSTEM (RCS)

RCS Pressure, Temperature, and Flow Departure from Nucleate Boiling (DNB) Limits...............

RCS Minimum Temperature for Criticality..............

RCS Pressure and Temperature (P/T) Limits............

RCS Loops-MODES 1 and 2.............................

RCS Loops-MODE 3......................................

RCS Loops-MODE 4......................................

RCS Loops-MODE 5, Loops Filled.......................

RCS Loops-MODE 5, Loops Not Filled...................

Pressurizer..........................................

Pressurizer Safety Valves...................

Pressurizer Power Operated Relief Valves (PORVs).

Low Temperature Overpressure Protection (LTOP)*

System.............................

RCS Operational LEAKAGE...............

RCS Pressure Isolation Valve'(PIV) Leakage...........

RCS Leakage Detection Instrumentation...............

RCS Specific Activity................................

RCS Loop Isolation Valves...........................

RCS Loops-Isolated.......................

Steam Generator (SG) Tube Integrity.....

EMERGENCY CORE COOLING SYSTEMS (ECCS)

Accumulators....................................

ECCS-Operating...........................

ECCS-S hutdown...........................

Refueling Water Storage Tank CRWST)..................

Seal Injection Flow..................................

CONTAINMENT SYSTEMS Containment.........................

Containment Air Locks................

Containment Isolation Valves..................

Containment Pressure..........................

Containment Air Temperature..........................

Containment Spray and Cooling Systems................

Spray Additive System............

(Deleted)........................

PLANT SYSTEMS Main Steam Safety Valves (MSSVs)...............

Main Steam Isolation Valves (MSIVs)............

Secondary Specific Activity........................'

Steam Generator (SG) Power Operated Relief Valves (PORVs)...................................

Auxiliary Feedwater (AF) System...

Condensate Storage Tank (CST).....

3.4.1-1 3.4.2-1 3.4.3-1 3.4.4-1 3.4.5-1 3.4.6-1 3.4.7-1 3.4.8-1 3.4.971 3.4.10-1 3.4.11-1 3.4.12-1 3.4.13-1 3.4.14-1 3.4.15-1 3.4.16-1 3.4.17-1 3.4.18-1 3.4.19-1 I

3.5.1-1 3.5.2-1 3.5.3-1 3.5.4-1 3.5.5-1 3.6.1-1 3.6.2-1 3.6.3-1 3.6.4-1 3.6.5-1 3.6.6-1 3.6.7-1 3.6.8-1 3.7.1-1 3.7.2-1 3.7.3-1 3.7.4-1 3.7.5-1 3.7.6-1 BYRON - UNITS 1 & 2 ii Amendment

Definitions

1.1 1.1 Definitions LEAKAGE LEAKAGE shall be:

a. Identified LEAKAGE

1. LEAKAGE,'such as that from pump seals or valve packing (except Reactor Coolant pump (RCP) seal water injection or leakoff),

that is captured and conducted to collection systems or a sump or collecting tank;

2. LEAKAGE into the containment atmosphere from sources that are both specifically located and known either not to interfere with the operation of leakage detection systems or not to be pressure boundary LEAKAGE; or

3. Reactor Coolant through a Steam System (primary System (RCS) LEAKAGE Generator to the.Secondary to secondary LEAKAGE);

l.

b. Unidentified LEAKAGE All LEAKAGE or leakoff)

(except RCP seal water injection that is not identified LEAKAGE;

c. Pressure Boundary LEAKAGE LEAKAGE.(except primary to secondary LEAKAGE) through a nonisolable fault in an RCS component body,'pipe wall, or vessel wall.

I MASTER RELAY TEST A MASTER RELAY TEST shall consist of energizing each master relay and verifying the OPERABILITY of each relay.

The MASTER RELAY TEST shall include a continuity check of each associated slave relay.

BYRON - UNITS 1 & 2 1.1 - 4 Amendment

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; and

d. 150 gallons per day primary to secondary LEAKAGE through any one steam generator (SG).

.1 APPLICABILITY:

MODES 1, 2, 3, and 4.

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

limits for reasons other than pressure boundary LEAKAGE or Erimary to secondary EAKAGE.

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 AND not 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.

OR Primary to secondary LEAKAGE not within limit.

I BYRON -

UNITS 1 & 2 3.4.13 - 1 Amendment

RCS Operational LEAKAGE 3.4.13 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.13.1 N----NOTES-------------------

1. 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.

2. Not applicable to primary to secondary LEAKAGE.

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

l 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months SR 3.4.13.2 ------------------- 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.

Verify primary to secondary LEAKAGE is 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months

< 150 gallons per day through any one SG.

BYRON - UNITS 1 & 2 3.4.13 - 2 '

Amendment

SG Tube Integrity 3.4.19 3.4 REACTOR COOLANT SYSTEM (RCS) 3.4.19 Steam Generator (SG) Tube Integrity LCO 3.4.19 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 rogram.

APPLICABILITY:

MODES 1, 2, 3, and 4.

ACTIONS NOTE-----------------------------------------

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 7 days satisfying the tube of the affected repair criteria and tube(s) is maintained not plugged or until the next repaired in accordance refueling outage or with the Steam SG tube inspection.

Generator Program.

AND A.2 Plug or repair the Prior to affected tube(s) in entering MODE 4 accordance with the following the Steam Generator next refueling Program..

outage 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 AND not 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.

BYRON - UNITS 1 & 2 3.4.19 - 1 Amendment I

SG Tube Integrity 3.4.19 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.19.1 Verify SG tube integrity in accordance with In accordance the Steam Generator Program.

with the Steam Generator Program SR 3.4.19.2 Verify that each inspected SG tube that Prior to satisfies the tube repair criteria is entering MODE 4 plugged or-repaired in accordance with the following a SG Steam Generator Program.

tube inspection BYRON - UNITS 1 & 2 3.4.19 - 2 Amendment I

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.9 Steam Generator (SG) Program 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.

BYRON - UNITS 1 & 2 5.5 - 7 Amendment

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.9 Steam Generator (SG) ProQram (continued)

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 a total of 1 gpm for all SGs.

3.

The operational LEAKAGE performance criteria 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.

For Unit 2 only, degradation identified in the portion of the tube from the top of the hot leg tubesheet to 17 inches below the top of the tubesheet shall be plugged or repaired upon detection.

TIG welded sleeves found by inservice inspection to contain flaws with a depth equal to or exceeding 32% of the nominal wall thickness shall be plugged.

The following alternate tube repair criteria may be applied as an alternative to the 40% depth-based criteria:

1.

For Unit 2 only, degradation found in the portion of the tube below 17 inches from the top of the hot leg tubesheet does not require plugging or repair.

d.

Provisions for SG tube inspections.

Periodic SG tube inspections shall be performed.

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. For Unit 2 the portion of the tube below 17 inches from the top of the hot leg tubesheet is excluded. 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 BYRON -

UNITS 1 & 2 5.5 - 8 Amendment

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.9 Steam Generator (SG) Program (continued) determine which inspection methods need to be employed and at what locations.

1.

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

2.

Inspect 100% of the Unit 1 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.

Inspect 100% of the Unit 2 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.

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 Unit 2 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 BYRON - UNITS 1 & 2 5.5 - 9 Amendment

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.9 Steam Generator (SG) Program (continued) these Specifications, tube plugging is not a repair.

All acceptable repair methods are listed below.

1.

TIG welded sleeving as described in ABB Combustion Engineering Inc., Technical Reports:

Licensing Report CEN-621-P, Revision 00, "Commonwealth Edison Byron and Braidwood Unit 1 and 2 Steam Generators Tube Repair Using Leak Tight Sleeves, FINAL REPORT," April 1995; and Licensing Report CEN-627-P, "Operating Performance of the ABB CENO Steam Generator Tube Sleeve for Use at Commonwealth Edison Byron and Braidwood Units 1 and 2," January 1996; subject to the limitations and restrictions as noted by the NRC Staff.

5.5.10 Secondary Water Chemistry Program This program provides controls for monitoring secondary water chemistry to inhibit SG tube degradation. 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;

c.

Identification of process sampling points, which shall include monitoring the discharge of the condensate pumps for evidence of condenser inleakage;

d.

Procedures for the recording and management of data;

e.

Procedures defining corrective actions for all off control point chemistry conditions; and

f.

A procedure identifying the authority responsible for the interpretation of the data and the sequence and timing of administrative events, which is required to initiate corrective action.

BYRON - UNITS 1 & 2 5.5 - 10 Amendment

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.11 Ventilation Filter Testina Proaram (VFTP)

A program shall be established to implement the following required testing of Engineered Safety Feature CESF) filter ventilation systems at the frequencies specified in conformance with Regulatory Guide 1.52, Revision 2, and ANSI N510-1980, with any exceptions noted in Appendix A of the UFSAR.

BYRON - UNITS 1 & 2

.5.5 - 11 Amendment I

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.11 Ventilation Filter Testing Program (VFTP)

(continued)

a.

Demonstrate for each of the ESF filter systems that an inplace test of the High Efficiency Particulate Air (HEPA) filters shows a penetration specified below when tested in conformance with Regulatory Guide.1.52, Revision 2, and ANSI N510-1980, with any exceptions noted in.Appendix A of the UFSAR, at the system flow rate specified below.

Verification of the specified flow rates may be accomplished during the performance of SRs 3.7.10.4, 3.7.12.4, and 3.7.13.5,.as applicable:

ESF Ventilation System Flow Rate Penetration Control Room Ventilation (VC)

Filtration System (makeup)

Nonaccessible Area Exhaust Filter Plenum Ventilation System (after structural maintenance of the HEPA filter housings)

Nonaccessible Area Exhaust Filter Plenum Ventilation System (for reasons other than structural maintenance of the HEPA filter housings)

Fuel Handling Building Exhaust Filter Plenum (FHB)

Ventilation System 2 5400 cfm and

< 6600 cfm 2 55,669 cfm and

< 68,200 cfm per train, and 2 18,556 cfm and

< 22,733 cfm per bank 2 55,669 cfm and

< 68,200 cfm per train 2 18,900 cfm and

< 23,100 cfm

< 0.05%

< 1%

BYRON - UNITS 1 & 2 5.5 - 12 Amendment I

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.11 Ventilation Filter Testing Program (VFTP)

(continued)

b.

Demonstrate for each of the ESF filter systems that an inplace test of the charcoal adsorber shows a bypass specified below

_._-- when tested-in conformance-with Regulatory Guide 1.52, Revision 2, and ANSI N510-1980, with any exceptions noted in Appendix A of the UFSAR, at the system flow rate specified below.

Verification of the specified flow rates may be accomplished during the performance of SRs 3.7.10.4, 3.7.12.4, and 3.7.13.5, as applicable:

ESF Ventilation System VC Filtration System (makeup)

VC Filtration System

.(recirculation, charcoal bed after complete or partial replacement)

VC Filtration System (recirculation for reasons other than complete or partial charcoal bed replacement)

Nonaccessible Area Exhaust Filter Plenum Ventilation System (after structural maintenance of the charcoal adsorber housings)

Nonaccessible Area Exhaust Filter Plenum Ventilation System (for reasons other than structural maintenance of the charcoal adsorber

-housings)

FHB Ventilation System Flow Rate 2 5400 cfm and

< 6600 cfm 2 44,550 cfm and

< 54,450 cfm 2 44,550 cfm and

54,450 cfm 2 55,669 cfm and

68,200 cfm per train, and 2 18,556 cfm and

22,733 cfm per bank Bypass

< 0.05%

< 0.1%

< 2%

2 55,669 5 68,200 train cfm and cfm per

< 1%

2 18,900 cfm and

< 23,100 cfm per train BYRON - UNITS 1 & 2

.5.5 - 13 Amendment Il

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.12 Explosive Gas and Storage Tank Radioactivity Monitoring Program This program provides controls for potentially explosive gas mixtures contained in the waste gas system, the quantity of radioactivity-contained in gas decay-tanks or fed into the off gas treatment system, and the quantity of radioactivity contained in unprotected outdoor liquid storage tanks. The gaseous radioactivity uantities shall be determined following the methodology in Branch

-echnical Position (BTP) ETSB 11-5, "Postulated Radioactive Release due to Waste Gas System Leak or Failure." The liquid radwaste quantities shall be determined in accordance with the ODCM.

The program shall include:

a.

The limits for concentrations of hydrogen and-oxygen in the waste gas system and a surveillance program to ensure the limits are maintained. Such limits shall be appropriate-to the system's design criteria (i.e., whether or not the system is designed to withstand a hydrogen explosion);

b.

A surveillance program to ensure that the quantity of radioactivity contained in each gas decay tank and fed into the offgas treatment system is less than the amount that would result in a whole body exposure of 2 0.5 rem to any individual in an unrestricted area, in the event of an uncontrolled release of the tanks' contents; and

c.

A surveillance program to ensure that the quantity of radioactivity contained in all outdoor liquid radwaste tanks that are not surrounded by liners, dikes, or walls, capable of holding the tanks' contents and that do not have tank overflows and surrounding area drains connected to the liquid radwaste treatment system is less than the amount that would result in concentrations less than the limits of 10 CFR 20, Appendix B, Table 2, Column 2, at the nearest potable water supply and the nearest surface water supply in an unrestricted area, in the event of an uncontrolled release of the tanks' contents.

The provisions of SR 3.0.2 and SR 3.0.3 are applicable to the Explosive Gas and Storage Tank Radioactivity Monitoring Program surveillance frequencies.

BYRON - UNITS 1 & 25 5.5 - 16 Amendment Il

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.13 Diesel Fuel Oil Testing Program A diesel fuel oil testing program to implement required testing of both new fuel oil and stored fuel oil shall be established. The program shall include sampling and--testing-requirements, and acceptance criteria, all in accordance with applicable ASTM Standards. The purpose of the program is to establish the following:

a.

Acceptability of new fuel-oil for use prior to addition to storage tanks by determining that the fuel oil has:.

1.

an API gravity or an absolute specific gravity within

limits,

2.

a flash point and-kinematic viscosity within limits, and

3.

a clear and bright appearance with proper color or a water and sediment content within limits;

b.

Other properties of new fuel oil are within limits within 30 days following sampling and addition to storage tanks; and

c.

Total particulate concentration of the fuel oil is < 10 mg/l when tested every 31 days.

The provisions of SR 3.0.2 and SR 3.0.3 are applicable to the Diesel Fuel Oil Testing Program test frequencies.

BYRON - UNITS 1 & 2

5.

5-17 Amendment I

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.14 Technical Specifications (TS) Bases Control Program This program provides a means for processing changes to the Bases of these Technical Specifications.

a.

Changes to the Bases of the TS shall be made under appropriate administrative controls and reviews.

b.

Licensees may make changes to Bases without prior NRC approval provided the changes do not require either of the following:

1.

a change in the TS incorporated in the license; or

2.

a change to the UFSAR or Bases that requires NRC approval pursuant to 10 CFR 50.59.

c.

The Bases Control Program shall contain provisions to ensure that the Bases are maintained consistent with the UFSAR.

d.

Proposed changes that meet the criteria of Specification 5.5.14.b above shall be reviewed and approved by the NRC prior to implementation. Changes to the Bases implemented without prior NRC approval shall be provided to the NRC on a frequency consistent with 10 CFR 50.71(e) as modified by approved exemptions.

BYRON -

UNITS 1 & 2 5.5 - 18 Amendment I

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.15 Safety Function Determination ProQram (SFDP)

This program ensures loss of safety function is detected and appropriate actions taken. Upon entry into LCO 3.0.6, an evaluation shall be made to determine if loss of safety function exists.

Additionally, other appropriate actions may be taken as a result of the support system inoperability and corresponding exception to entering supported system Condition and Required Actions. This program implements the requirements of LCO 3.0.6. The SFDP shall contain the following:

a.

Provisions for cross train checks to ensure a loss of the capability to-perform the safety function assumed in the accident analysis does not go undetected;

b.

Provisions for ensuring the plant is maintained in a safe condition if a loss of function condition exists;

c.

Provisions to ensure that an inoperable supported system's Completion Time is not inappropriately extended as a result of multiple support system inoperabilities; and.

d.

Other appropriate limitations and remedial or compensatory actions.

A loss of safety function exists when, assuming.no concurrent single failure, a safety function assumed.in the accident analysis cannot be performed. For the purpose of this program, a loss of safety function may exist when a support system is inoperable, and:

a.

A required system redundant to the system(s) supported by the inoperable support system is also inoperable; or

b.

A required system redundant to the system(s) in turn supported by the inoperable supported system is also inoperable; or

c.

A required system redundant to the support system(s) for the supported systems (a) and (b) above is also inoperable.

BYRON -

UNITS 1 & 2 5.5 - 19 Amendment I

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.15 Safety Function Determination Program (SFDP)

(continued)

The SFDP identifies where a loss of safety function exists. If a loss of safety function is determined to exist by this program, the appropriate Conditions and Required Actions of the LCO in which the loss of safety function exists are required to be entered.

5.5.16 Containment Leakage Rate Testing Program A program shall be established to implement the leakage rate testing of the containment as required by 10 CFR 50.54(o) and 10 CFR 50, Appendix J, Option B, as modified by approved exemptions. This program shall be in accordance.with the guidelines contained in Regulatory Guide 1.163, September 1995 and NEI 94-01, Revision 0.

The peak calculated containment internal pressure for the design basis loss of coolant accident, Pa, is 42.8 psig for Uniti1 and 38.4 psig for Unit 2 The maximum allowable containment leakage rate, La, at Pa, shall be 0.10% of containment air weight per day.

Leakage Rate acceptance criteria are:

a.

Containment leakage rate acceptance criterion is < 1.0 La.

During the first unit startup following testing in accordance with this program, the leakage rate acceptance criteria are

< 0.60 La for the Type B and C tests and < 0.75 La for Type A tests; and BYRON - UNITS 1 & 2 5.5 - 20 Amendment I

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.16 Containment Leakage Rate Testing Program (continued)

b.

Air lock testing acceptance criteria are:

1.

Overall air lock leakage rate is < 0.05 L.

when tested at 2 Pa; and

2.

For each door, seal leakage rate is:

i.

< 0.0024 La, when pressurized to 2 3 psig, and ii. < 0.01 La, when pressurized to 2 10 psig.

The provisions of SR 3.0.2 do not apply to the test frequencies specified in the Containment Leakage Rate Testing Program.

The provisions of SR 3.0.3 are applicable to the Containment Leakage Rate Testing Program.

5.5.17 Battery Monitoring and Maintenance'Program This program provides for restoration and maintenance, based on the recommendations of IEEE Standard 450, "IEEE Recommended Practice for Maintenance, Testing, and Replacement of Vented Lead - Acid Batteries For Stationary Applications," or of the battery manufacturer of the following:

A.

Actions to restore battery cells with float voltage

< 2.13 V, and B.

Actions to equalize and test battery cells that had been discovered with electrolyte level below the minimum established design limit.

BYRON - UNITS 1 & 2 5.5 21 Amendment I

Reporting Requirements 5.6 5.6 Reporting Requirements 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 in the Inservice Inspection Summary Report in accordance with 10 CFR 50.55a and ASME Section XI, 1992 Edition with the 1992 Addenda.

5.6.9 Steam Generator (SG) Tube Inspection Report I

A report shall be submitted within 180 days after the initial entry into MODE 4 following completion of an inspection performed in accordance with 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 repairs in each SG, and

i.

Repair method utilized and the number each repair method.

all plugging and tube of tubes repaired by BYRON - UNITS 1 & 2 5.6 - 6 Amendment

-A BRAIDWOOD STATION UNITS 1 AND 2 Docket Nos. STN 50-456 and STN 50-457 License Nos. NPF-72 and NPF-77 Application for Technical Specification Improvement Regarding Steam Generator Tube Integrity Typed Technical Specifications Bases Pages (Information Only) ii B 3.4.4-3 B 3.4.5-4 B 3.4.13-2 B 3.4.13-3 B 3.4.13-4 B 3.4.13-5 B 3.4.13-6 B 3.4.13-7 B 3.4.13-8 B 3.4.19-1 B 3.4.19-2 B 3.4.19-3 B 3.4.19-4 B 3.4.19-5 B 3.4.19-6 B 3.4.19-7 B 3.4.19-8

RCS Loops-MODES 1 and 2 B 3.4.4 BASES APPLICABLE SAFETY ANALYSES (continued)

The unit is designed to o perate 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 1 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 oeration providing forced flow for heat transport and an OPERABLE SG..

BRAIDWOOD - UNITS 1 & 2

B 3.4.4 - 3 Revi sion

RCS Loops-MODE 3 B 3.4.5 BASES LCO (continued)

An OPERABLE RCS loop consists of one OPERABLE RCP and one OPERABLE SG,. which has 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.

I 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 L[O, 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, LCO 3.4.6, LCO 3.4.7, LCO 3.4.8, LCO 3.9.5, "RCS Loops-MODES 1 and 2";

"RCS Loops-MODE 4";

"RCS Loops-MODE 5, Loops Filled";

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

"Residual Heat Removal (RHR) and Coolant Circulation-High Water Level" (MODE 6); and "Residual Heat Removal (RHR) and Coolant Circulation-Low Water Level" (MODE 6).

LCO 3.9.6, BRAIDWOOD -

UNITS 1 & 2 B 3.4.5 - 4 Revision

RCS Operational LEAKAGE B 3.4.13 BASES BACKGROUND (continued)

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 analyses 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 ermit unit shutdown before a LOCA occurs. This advantage has been shown by "leak before break" studies.

APPLICABLE SAFETY ANALYSIS Except for primary to secondary LEAKAGE, the safety analyses do not address operational LEAKAGE. However, other operational LEAKAGE is related to the safety analyses for LOCA; the amount of leakage can affect the probability of such an event. The safety analyses for the Main Steamline Break and the Locked Rotor with Failed Open PORV, base the radioactive discharge to the atmosphere on primary to secondary LEAKAGE from the faulted SG of 0.5 gallon per minute and primary to secondary LEAKAGE from the intact SGs of 0.218 gallon per minute per intact SG.

For the Locked Rotor and Rod Cluster Control Assembly Ejection, the radioactive discharge to the atmosphere is based on the total primary to secondary LEAKAGE from all SGs of 1 gallon per minute. 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.

Primary to secondary LEAKAGE is a factor in the dose releases outside containment resulting from a Locked Rotor with a Concurrent Steam Generator (SG) Power Operated Relief Valve.(PORV) Failure accident because such leakage contaminates the secondary fluid. Other accidents or transients involve secondary steam release to the atmosphere, such as a Steam Generator Tube Rupture (SGTR).

The SGTR is more limiting than the Locked Rotor with a Concurrent SG PORV Failure for site radiation releases.

The UFSAR (Ref. 3) analysis for SGTR assumes the contaminated secondary fluid is released for a limited time via the SG PORV.

After a tube rupture occurs, reactor coolant immediately begins flowing from the primary system into the secondary side of the ruptured SG causing the RCS pressure to-decrease until a reactor trip occurs on low pressurizer pressure.

The analysis assumes a Loss of Offsite Power occurs coincident with the reactor trip BRAIDWOOD - UNITS 1 & 2 B 3.4.13 - 2 Revision

RCS Operational LEAKAGE B 3.4.13 BASES APPLICABLE SAFETY ANALYSES (continued) causing the Reactor Coolant Pumps to trip and the main condenser to become unavailable when the circulating water pumps are lost.

After the reactor trips, the core power quickly decreases to decay heat levels.

The steam dump system cannot be used to dissipate the core decay heat due to the unavailable condenser. Therefore, the secondary pressure increases in the SGs until the SG PORVs open at which time the ruptured SG PORV is assumed to fail in the open position. The ruptured SG failed PORV is isolated when the block valve is manually closed twenty minutes after the PORV first opened.

The 1 gpm primary to secondary LEAKAGE safety analysis assumption is relatively inconsequential to the results of this analysis.

The dose consequences resulting from the Locked Rotor with a Concurrent SG PORV Failure accident are well within the limits defined in 10 CFR 100.

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, valve seats, and gaskets is not pressure boundary LEAKAGE.

BRAIDWOOD - UNITS 1 & 2 B 3.4.13 - 3 Revision

RCS Operational LEAKAGE B 3.4.13 BASES LCO (continued)

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 discharge flow 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.

c.

Identified LEAKAGE Upto 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.

BRAIDWOOD - UNITS 1 & 2 B 3.4.13 - 4 Revi sion

RCS Operational LEAKAGE B 3.4.13 BASES LCO (continued)

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 rimary 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.

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

measures leakage through each individual Pressure Isolation Valve (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 leak tight. If both valves leak and result in a loss of mass from the RCS, the loss must be included as identified LEAKAGE.

APPLICABILITY In MODES 1, 2, 3, and 4, the potential for RCPB LEAKAGE is greater due to RCS pressure.

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 or identified LEAKAGE 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 Required Action is necessary to prevent further deterioration of the RCPB.

I BRAIDWOOD - UNITS 1 & 2 B 3.4.13 - 5 Revi sion

RCS Operational LEAKAGE B 3.4.13 BASES ACTIONS (continued)

B.1 and B.2 If any pressure boundary LEAKAGE exists, or primary to secondary LEAKAGE is not within limit, or if unidentified or identified 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. It should be noted that LEAKAGE past seals and gaskets is not pressure boundary LEAKAGE.

The unit 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 unit 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.

BRAIDWOOD - UNITS 1 & 2 B 3.4.13 - 6 Revi sion

RCS Operational LEAKAGE B 3.4.13 BASES 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, valve seats, and gaskets is not pressure boundary LEAKAGE.

Unidentified LEAKAGE and identified LEAKAGE are determined by performance of an RCS water inventory balance.

The RCS water inventory balance must be performed with the reactor at steady state operating conditions and near operating pressure. The Surveillance is modified by two Notes.

Note 1 states that 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.

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 (Ž 2150 psig), temperature, power level, pressurizer and makeup tank levels, makeup and letdown, and CP seal injection and return flows.

An early warning of pressure boundary LEAKAGE or unidentified LEAKAGE is provided by the 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 LCO 3.4.15, "RCS Leakage Detection Instrumentation."

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.

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

BRAIDWOOD -

UNITS 1 & 2 B 3.4.13 - 7 Revi sion

RCS Operational LEAKAGE B 3.4.13 BASES SURVEILLANCE REQUIREMENTS (continued)

SR 3.4.13.2 This SR verifies that primary to secondary LEAKAGE is less than 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 3.4.19, "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. The primary to secondary LEAKAGE is determined using continuous process radiation monitors or radiochemical grab sampling in accordance with EPRI guidelines (Ref. 5).

REFERENCES

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

2. Regulatory Guide 1.45, May 1973.

3. UFSAR, Chapter 15.

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

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

BRAIDWOOD -

UNITS 1 & 2 B 3.4.13 - 8 Revi sion

SG Tube Integrity B 3.4.19 B 3.4 REACTOR COOLANT SYSTEM (RCS)

B 3.4.19 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 eakage, 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.

BRAIDWOOD - UNITS 1 & 2 B 3.4.19 - I Revision

SG Tube Integrity B 3.4.19 BASES BACKGROUND (continued)

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

APPLICABLE SAFETY ANALYSIS The steam generator tube rupture (SGTR) accident is the limiting design basis event for SG tubes and avoiding an SGTR is the basis for this Specification. The analysis of a SGTR event assumes total initial primary to secondary LEAKAGE of 1.0 gpm for the intact SGs 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 released to the atmosphere via the SG Power Operated Relief Valves (PORVs).

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.)

For the Main Steamline Break and the Locked Rotor with Failed Open PORV, the radioactive discharge to the atmosphere is based on primary to secondary LEAKAGE from the faulted SG of 0.5 gallon per minute and primary to secondary LEAKAGE from the intact SGs of 0.218 gallon per minute per intact SG.

For the Locked Rotor and Rod Cluster Control Assembly Ejection, the radioactive discharge to the atmosphere is based on the total primary to secondary LEAKAGE from all SGs of 1 gallon per minute.

For accidents that do not involve fuel damage, the primary coolant activity level of DOSE EQUIVALENT I-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).

1 & 2 B 3.4.19 - 2 Revision BRAIDWOOD -

UNITS

SG Tube Integrity B 3.4.19 BASES 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. For Unit 2 the portion of the tube below 17 inches from the top of the hot leg tubesheet is excluded.

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.

There are three SG performance criteria: structural integrity, accident induced leakage, and operational LEAKAGE (i.e., primary to secondary 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 have a significant effect on burst or collapse. In that context, the term "significant" is defined as "An accident loading condition other than differential pressure is considered BRAIDWOOD - UNITS 1 & 2 B 3.4.19 - 3 Revi sion

SG Tube Integrity B 3.4.19 BASES LCO (continued) 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."

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 II, 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 induced leakage requirement of 1 gpm for all SGs, except for specific types of degradation at specific locations where the NRC has approved greater accident induced leakage, bounds the accident analysis assumptions for primary to secondary 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.

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.

BRAIDWOOD - UNITS 1 & 2 B 3.4.19 - 4 Revision

SG Tube Integrity B 3.4.19 BASES 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 3.4.19.2. 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 refueling outage or SG tube inspection, whichever occurs first. 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.

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.

BRAIDWOOD - UNITS 1 & 2 B 3.4.19 - 5 Revision

SG Tube Integrity B 3.4.19 BASES ACTIONS (continued)

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, whichever occurs first, 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, whichever occurs first. 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 3.4.19.1 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 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.

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 BRAIDWOOD - UNITS 1 & 2 B 3.4.19 - 6 Revision

SG Tube Integrity B 3.4.19 BASES SURVEI LLANCE REQUI REMENTS (continued)

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 3.4.19.1. 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 3.4.19.2 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 provides 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.

BRAIDWOOD - UNITS 1 & 2 B 3.4.19 - 7 Revision

SG Tube Integrity B 3.4.19 BASES 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, "Pressurized Water Reactor Steam Generator Examination Guidelines."

1 & 2 B 3.4.19 - 8 Revision BRAIDWOOD - UNITS

-B BYRON STATION UNITS 1 AND 2 Docket Nos. STN 50-454 and STN 50-455 License Nos. NPF-37 and NPF-66 Application for Technical Specification Improvement Regarding Steam Generator Tube Integrity Typed Technical Specifications Bases Pages (Information Only) ii B 3.4.4-3 B 3.4.5-4 B 3.4.13-2 B 3.4.13-3 B 3.4.13-4 B 3.4.13-5 B 3.4.13-6 B 3.4.13-7 B 3.4.13-8 B 3.4.19-1 B 3.4.19-2 B 3.4.19-3 B 3.4.19-4 B 3.4.19-5 B 3.4.19-6 B 3.4.19-7 B 3.4.19-8

TABLE OF CONTENTS - TECHNICAL SPECIFICATIONS BASES B 3.4 B 3.4.1 B

B B

B 3.4.2 3.4.3 3.4.4 3.4.5 3.4.6 3.4.7 3.4.8 3.4.9 3.4.10 3.4.11 3.4.12 3.4.13 3.4.14 3.4.15 3.4.16 3.4.17 3.4.18 3.4.19 B 3.5 B 3.5.1 B 3.5.2 B 3.5.3 B 3.5.4 B 3.5.5 B 3.6 B 3.6.1 B 3.6.2 B 3.6.3 B 3.6.4 B 3.6.5 B 3.6.6 B 3.6.7 B 3.6.8 REACTOR COOLANT SYSTEM (RCS)

RCS Pressure, Temperature, and Flow Departure from Nucleate Boiling (DNB) Limits................ B RCS Minimum Temperature for Criticality.............. B RCS Pressure and Temperature (P/T) Limits............ B RCS Loops-MODES 1 and 2............................. B RCS Loops-MODE 3...................................... B RCS Loops-MODE 4....................................... B RCS Loops-MODE 5, Loops Filled........................ B RCS Loops-MODE 5, Loops Not Filled.................

B...B Pressurizer........................................

B Pressurizer Safety Valves............................. B Pressurizer Power Operated Relief Valves (PORVs)..... B Low Temperature Overpressure Protection (LTOP)

System............

B RCS Operational LEAKAGE.B RCS Pressure Isolation Valve (PIV) Leakage........... B RCS Leakage Detection Instrumentation............... B RCS Specific Activity...................-

B RCS Loop Isolation Valves..................

B RCS Loop-Isolated..............

B Steam Generator (SG) Tube Integrity.B EMERGENCY CORE COOLING SYSTEMS (ECCS)

Accumulators.

B ECCS-Operating.

B ECCS-Sh utdown.

B Refueling Water Storage Tank (RWST).

B Seal Injection Flow.

B CONTAINMENT SYSTEMS Containment.

B Containment Air-Locks.B Containment Isolation Valves.

B Containment Pressure.

B Containment Air Temperature............................

B Containment Spray and Cooling Systems.

B Spray Additive System

.B Hydrogen Recombiners.

B PLANT SYSTEMS Main Steam Safety Valves (MSSVs).

B Main Steam Isolation Valves (MSIVs).

B Secondary Specific Activity.

B Steam Generator (SG) Power Operated Relief Valves (PORVs).

B Auxiliary Feedwater (AF) System.

B Condensate Storage Tank (CST)

B 3.4.1-1 3.4.2-1 3.4.3-1 3.4.4-1 3.4.5-1 3.4.6-1 3.4.7-1 3.4.8-1 3.4.9-1 3.4.10-1 3.4.11-1 3.4.12-1 3.4.13-1 3.4.14-1 3.4.15-1 3.4.16-1 3.4.17-1 3.4.18-1 3.4.19-1l 3.5.1-1 3.5.2-1 3.5.3-1 3.5.4-1 3.5.5-1 3.6.1-1 3.6.2-1 3.6.3-1 3.6.4-1 3.6.5-1 3.6.6-1 3.6.7-1 3.6.8-1

.iIiI i

B B

B 3.7 3.7.1 3.7.2 3.7.3 3.7.4 3.7.1-1 3.7.2-1 3.7.3-1 3.7.4-1 3.7.5-1 3.7.6-1 B 3.7.5 B 3.7.6 BYRON - UNITS 1 & 2 lRelvi sion

RCS Loops-MODES 1 and 2 B 3.4.4 BASES APPLICABLE SAFETY ANALYSES (continued).

The unit 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 1 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 operation providing forced flow for heat transport and an OPERABLE SG...

BYRON - UNITS 1 & 2 B 3.4.4 - 3 Revision

RCS.Loops-MODE 3 B 3.4.5 BASES LCO (continued)

An OPERABLE RCS loop consists of one OPERABLE RCP and one OPERABLE SG, which has 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 LCO LCO LCO LCO 3.4.4, 3.4.6, 3.4.7, 3.4.8, 3.9.5, "RCS Loops-MODES land 2";

"RCS Loops-MODE 4";

"RCS Loops-MODE 5, Loops Filled";

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

"Residual Heat Removal (RHR) and Coolant Circulation-High Water Level" (MODE 6); and "Residual Heat Removal (RHR) and Coolant Circulation-Low Water Level" (MODE 6).

.LCO 3.9.6, BYRON - UNITS 1 & 2 8 3.4.5 - 4 Revision

RCS Operational LEAKAGE B 3.4.13 BASES BACKGROUND (continued)

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 analyses 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 unit shutdown before a LOCA occurs. This advantage has been shown by "leak before break" studies.

APPLICABLE SAFETY ANALYSIS Except for primary to secondary LEAKAGE, the safety analyses do not address operational LEAKAGE. However, other operational LEAKAGE is related to the safety analyses for LOCA; the amount of leakage can affect the probability of such an event. The safety analyses for the Main Steamline Break and the Locked Rotor with Failed Open PORV, base the radioactive discharge to the atmosphere on primary to secondary LEAKAGE from the faulted SG of 0.5 gallon per minute and primary to secondary LEAKAGE from the intact SGs of 0.218 gallon per minute per intact SG.

For the Locked Rotor and Rod Cluster Control Assembly Ejection, the radioactive discharge to the atmosphere is based on the total primary to secondary LEAKAGE from all SGs of 1 gallon per minute. 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.

Primary to secondary LEAKAGE is a factor in the dose releases outside containment resulting from a Locked Rotor with a Concurrent Steam Generator (SG) Power Operated Relief Valve.(PORV) Failure accident because such lea age contaminates the secondary fluid. Other accidents or transients involve secondary steam release to the atmosphere, such as a Steam Generator Tube Rupture (SGTR).

The SGTR is more limiting than the Locked Rotor with a Concurrent SG PORV Failure for site radiation releases.

The UFSAR (Ref. 3) analysis for SGTR assumes the contaminated secondary fluid is released for a limited time via the SG PORV. After a tube rupture occurs, reactor coolant immediately begins flowing from the primary system into the secondary side of the ruptured SG causing the RCS pressure to decrease until a reactor trip occurs on low pressurizer pressure. The analysis assumes a Loss of Offsite Power occurs coincident with the reactor trip BYRON - UNITS 1 & 2 B 3.4.13 - 2 Revision

RCS Operational LEAKAGE B 3.4.13 BASES APPLICABLE SAFETY ANALYSES (continued) causing the Reactor Coolant Pumps to trip and the main condenser to become unavailable when the circulating water pumps are lost.

After the reactor trips, the core power quickly decreases to decay heat levels. -The steam dump system cannot be used to dissipate the core decay heat due to the unavailable condenser. Therefore, the secondary pressure increases in the SGs until the SG PORVs open at which time the ruptured SG PORV is assumed to fail in the open position.

The ruptured SG failed PORV is isolated when the block valve is manually closed twenty minutes after the PORV first opened.

The 1 gpm primary to secondary LEAKAGE safety analysis assumption is relatively inconsequential to the results of this analysis.

The dose consequences resulting from the Locked Rotor with a Concurrent SG PORV Failure accident are well within the limits defined in 10 CFR 100.

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, valve seats, and gaskets is not pressure boundary LEAKAGE.

BYRON - UNITS 1 & 2 B 3.4.13 - 3 Revision

RCS Operational LEAKAGE B 3.4.13 BASES LCO (continued)

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 sums discharge flow 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.

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.

BYRON -

UNITS 1 & 2 B 3.4.13 - 4 Revision

RCS Operational LEAKAGE B 3.4.13 BASES LCO (continued)

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 rimary 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.

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

measures leakage through each individual Pressure Isolation Valve (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 leak tight. If both valves leak and result in a loss of mass from the RCS, the loss must be included as identified LEAKAGE.

I APPLICABILITY In MODES 1, 2, 3, and 4, the potential for RCPB LEAKAGE is greater due to RCS pressure.

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 or identified LEAKAGE 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 Required Action is necessary to prevent further deterioration of the RCPB.

I BYRON - UNITS 1 & 2 B 3.4.13 - 5 Revi sion

RCS Operational LEAKAGE B 3.4.13 BASES ACTIONS (continued)

B.1 and B.2 If any pressure boundary LEAKAGE exists, or primary to secondary LEAKAGE is not within limit, or if unidentified or identified 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.

It should be noted that LEAKAGE past seals and gaskets is not pressure boundary LEAKAGE.

The unit 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 unit 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.

BYRON -

UNITS 1 & 2 B 3.4.13 - 6 Revision

RCS Operational LEAKAGE B 3.4.13 BASES 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, valve seats, and gaskets is not pressure boundary LEAKAGE.

Unidentified LEAKAGE and identified LEAKAGE are determined by performance of an RCS water inventory balance.

The RCS water inventory balance must be performed with the reactor at steady state operating conditions and near operating pressure. The Surveillance is modified by two Notes.

Note 1 states that 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.

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 (C 2150 psig), 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 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 LCO 3.4.15, "RCS Leakage Detection Instrumentation."

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.

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

BYRON -

UNITS 1 & 2 B 3.4.13 - 7 Revi sion

RCS Operational LEAKAGE B 3.4.13 BASES SURVEILLANCE REQUIREMENTS (continued)

SR 3.4.13.2 This SR verifies that primary to secondary LEAKAGE is less than 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 3.4.19, "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. The primary to secondary LEAKAGE is determined using continuous process radiation monitors or radiochemical grab sampling in accordance with EPRI guidelines (Ref. 5).

REFERENCES

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

2. Regulatory Guide 1.45, May 1973.

3. UFSAR, Chapter 15.

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

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

BYRON - UNITS 1 & 2 B 3.4.13 - 8 Revi sion

SG Tube Integrity B 3.4.19 B 3.4 REACTOR COOLANT SYSTEM (RCS)

B 3.4.19 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 eakage, 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.

IRevi sion BYRON - UNITS 1 & 2 B 3.4.19 - 1

SG Tube Integrity B 3.4.19 BASES BACKGROUND (continued)

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

APPLICABLE SAFETY ANALYSIS The steam generator tube rupture (SGTR) accident is the limiting design basis event for SG tubes and avoiding an SGTR is the basis for this Specification. The analysis of a SGTR event assumes total initial primary to secondary LEAKAGE of 1.0 gpm for the intact SGs 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 released to the atmosphere via the SG Power Operated Relief Valves (PORVs).

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.)

For the Main Steamline Break and the Locked Rotor with Failed Open PORV, the radioactive discharge to the atmosphere is based on primary to secondary LEAKAGE from the faulted SG of 0.5 gallon per minute and primary to secondary LEAKAGE from the intact SGs of 0.218 gallon per minute per intact SG.

For the Locked Rotor and Rod Cluster Control Assembly Ejection, the radioactive discharge to the atmosphere is based on the total primary to secondary LEAKAGE from all SGs of 1 gallon per minute.

For accidents that do not involve fuel damage, the primary coolant activity level of DOSE EQUIVALENT I-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 10 CFR 50.36(c)(2)(ii).

Criterion 2 of Revision BYRON - UNITS 1 & 2 B 3.4.19 - 2

SG Tube Integrity B 3.4.19 BASES 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.

For Unit 2 the portion of the tube below 17 inches from the top of the hot leg tubesheet is excluded.

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.

There are three SG performance criteria: structural integrity, accident induced leakage, and operational LEAKAGE (i.e., primary to secondary 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 have a significant effect on burst or collapse. In that context, the term "significant" is defined as "An accident loading condition other than differential pressure is considered BYRON - UNITS 1 & 2 B 3.4.19 - 3 Revision

SG Tube Integrity B 3.4.19 BASES LCO (continued) 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."

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 II, 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 induced leakage requirement of 1 gpm for all SGs, except for specific types of degradation at specific locations where the NRC has approved greater accident induced leakage, bounds the accident analysis assumptions for primary to secondary 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.

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.

BYRON - UNITS 1 & 2 B 3.4.19 - 4 Revision

SG Tube Integrity B 3.4.19 BASES 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 3.4.19.2. 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 refueling outage or SG tube inspection, whichever occurs first. 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.

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.

BYRON -

UNITS 1 & 2 B 3.4. 19 - 5 Revision

SG Tube Integrity B 3.4.19 BASES ACTIONS (continued)

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, whichever occurs first.

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 3.4.19.1 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 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.

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 BYRON - UNITS 1 & 2 B 3.4.19 - 6 Revision

SG Tube Integrity B 3.4.19 BASES SURVEILLANCE REQUIREMENTS (continued)

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 3.4.19.1. 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 3.4.19.2 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 provides 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.

BYRON -

UNITS 1 & 2 B 3.4.19 - 7 Revision

SG Tube Integrity B 3.4.19 BASES 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, "Pressurized Water Reactor Steam Generator Examination Guidelines."

2 B 3.4.19 - 8 Revision BYRON - UNITS 1 &

BRAIDWOOD STATION UNITS 1 AND 2 Docket Nos. STN 50-456 and STN 50-457 License Nos. NPF-72 and NPF-77 and BYRON STATION UNITS 1 AND 2 Docket Nos. STN 50-454 and STN 50-455 License Nos. NPF-37 and NPF-66 Application for Technical Specification Improvement Regarding Steam Generator Tube Integrity Application for Withholding and Affidavit

Westinghouse Westinghouse Electric Company Nuclear Services P.O. Box 355 Pittsburgh. Pennsylvania 1 5230.0355 USA U.S. Nuclear Regulatory Commission Document Control Desk Washington, DC 20555-0001 Direct tel:

Direct fax:

e-mail:

(412) 374-4419 (412) 374-4011 maurerbfewestinghouse.com Our ref. CAW-05-2047 September 2, 2005 APPLICATION FOR WITHHOLDING PROPRIETARY INFORMATION FROM PUBLIC DISCLOSURE

Subject:

LTR-CDME-05-32-P, Rev. 2, "Limited Inspection ofthe Steam GeneratorTube Portion Within the Tubesheet at Byron 2 and Braidwood 2," dated August 2005 (Proprietary)

The proprietary information for which withholding is being requested in the above-referenced report is further identified in Affidavit CAW-05-2047 signed by the owner of the proprietary information, Westinghouse Electric Company LLC. The affidavit, which accompanies this letter, sets forth the basis on which the information may be withheld from public disclosure by the Commission and addresses with specificity the considerations listed in paragraph (bX4) of 10 CFR Section 2.390 of the Commission's regulations.

Accordingly, this letter authorizes the utilization of the accompanying affidavit by Exelon Generation Company, LLC.

Correspondence with respect to the proprietary aspects of the application for withholding or the Westinghouse affidavit should reference this letter, CAW-05-2047, and should be addressed to B. F. Maurer, Acting Manager, Regulatory Compliance and Plant Licensing, Westinghouse Electric Company LLC, P.O. Box 355, Pittsburgh, Pennsylvania 15230-0355.

Very truly yours, B. F. Maurer, Acting Manager Regulatory Compliance and Plant Licensing Enclosures cc: B. Benney, NRC L. Feizollahi, NRC A BNFL Group company

CAW-05-2047 bcc: B. F. Maurer (ECE 4-7) I1 R. Bastien, IL (Nivelles, Belgium)

C. Brinkman, IL (Westinghouse Electric Co., 12300 Twinbrook Parkway, Suite 330, Rockville, MD 20852)

RCPL Administrative Aide (ECE 4-7A) IL, 1 A (letter and affidavit only)

G. W. Whiteman, Waltz Mill R. F. Keating, Waltz Mill H. 0. Lagally Waltz Mill J. M. Bunecicky, ECE 560E D. W. Alexander, ECE 561B A BNFL Group company

CAW-05-2047 AFFIDAVIT COMMONWEALTH OF PENNSYLVANIA:

ss COUNTY OF ALLEGHENY:

Before me, the undersigned authority, personally appeared B. F. Maurer, who, being by me duly sworn according to law, deposes and says that he is authorized to execute this Affidavit on behalf of Westinghouse Electric Company LLC (Westinghouse), and that the averments of fact set forth in this Affidavit are true and correct to the best of his knowledge, information, and belief:

B. F. Maurer, Acting Manager Regulatory Compliance and Plant Licensing Sworn to and subscribed before this day o

f/,

2005 Notary Public MOM Seai Shon= L Rod, Notay Ply TImms~w EqwsJazRy 29,007 Meni.

Pumbs AmsoK Of Ncbfes

2 CAW-05-2047 (1)

I am Acting Manager, Regulatory Compliance and Plant Licensing, Nuclear Services, Westinghouse Electric Company LLC (Westinghouse), and as such, I have been specifically delegated the function of reviewing the proprietary information sought to be withheld from public disclosure in connection with nuclear power plant licensing and rule making proceedings, and am authorized to apply for its withholding on behalf of Westinghouse.

(2) 1 am making this Affidavit in conformance with the provisions of 10 CFR Section 2.390 of the Commission's regulations and in conjunction with the Westinghouse "Application for Withholding" accompanying this Affidavit.

(3)

I have personal knowledge of the criteria and procedures utilized by Westinghouse in designating information as a trade secret, privileged or as confidential commercial or financial information.

(4)

Pursuant to the provisions of paragraph (bX4) of Section 2.390 of the Commission's regulations, the following is furnished for consideration by the Commission in determining whether the information sought to be withheld from public disclosure should be withheld.

(i)

The information sought to be withheld from public disclosure is owned and has been held in confidence by Westinghouse.

(ii)

The information is of a type customarily held in confidence by Westinghouse and not customarily disclosed to the public. Westinghouse has a rational basis for determining the types of information customarily held in confidence by it and, in that connection, utilizes a system to determine when and whether to hold certain types of information in confidence. The application of that system and the substance of that system constitutes Westinghouse policy and provides the rational basis required.

Under that system, information is held in confidence if it falls in one or more of several types, the release of which might result in the loss of an existing or potential competitive advantage, as follows:

(a)

The information reveals the distinguishing aspects of a process (or component, structure, tool, method, etc.) where prevention of its use by any of Westinghouse's competitors without license from Westinghouse constitutes a competitive economic advantage over other companies.

3 CAW-05-2047 (b)

It consists of supporting data, including test data, relative to a process (or component, structure, tool, method, etc.), the application of which data secures a competitive economic advantage, e.g., by optimization or improved marketability.

(c)

Its use by a competitor would reduce his expenditure of resources or improve his competitive position in the design, manufacture, shipment, installation, assurance of quality, or licensing a similar product.

(d)

It reveals cost or price information, production capacities, budget levels, or commercial strategies of Westinghouse, its customers or suppliers.

(e)

It reveals aspects of past, present, or future Westinghouse or customer funded development plans and programs of potential commercial value to Westinghouse.

(f)

It contains patentable ideas, for which patent protection may be desirable.

There are sound policy reasons behind the Westinghouse system which include the following:

(a)

The use of such information by Westinghouse gives Westinghouse a competitive advantage over its competitors. It is, therefore, withheld from disclosure to protect the Westinghouse competitive position.

(b)

It is information that is marketable in many ways. The extent to which such information is available to competitors diminishes the Westinghouse ability to sell products and services involving the use of the information.

(c)

Use by our competitor would put Westinghouse at a competitive disadvantage by reducing his expenditure of resources at our expense.

(d)

Each component of proprietary information pertinent to a particular competitive advantage is potentially as valuable as the total competitive advantage. If competitors acquire components of proprietary information, any one component may be the key to the entire puzzle, thereby depriving Westinghouse of a competitive advantage.

a%

4 CAW-05-2047 (e)

Unrestricted disclosure would jeopardize the position of prominence of Westinghouse in the world market, and thereby give a market advantage to the competition of those countries.

(f)

The Westinghouse capacity to invest corporate assets in research and development depends upon the success in obtaining and maintaining a competitive advantage.

(iii)

The information is being transmitted to the Commission in confidence and, under the provisions of 10 CFR Section 2.390, it is to be received in confidence by the Commission.

(iv)

The information sought to be protected is not available in public sources or available information has not been previously employed in the same original manner or method to the best of our knowledge and belief.

(v) The proprietary information sought to be withheld in this submittal is that which is appropriately marked in LTR-CDME-05-32-P, Rev. 2, "Limited Inspection of the Steam Generator Tube Portion Within the Tubesheet at Byron 2 and Braidwood 2," dated August 2005 (Proprietary). The information is provided in support of a submittal to the Commission, being transmitted by Exelon Generation Company, LLC and Application for Withholding Proprietary Information from Public Disclosure, to the Document Control Desk. The proprietary information as submitted for use by Westinghouse for Byron 2 and Braidwood 2 is expected to be applicable to other licensee submittals in support of implementing a limited inspection of the tube joint with a rotating probe within the tubesheet region of the steam generators.

This information is part of that which will enable Westinghouse to:

(a) Provide documentation of the analyses, methods, and testing for the implementation of the limited inspection length of the steam generator tube joint.

(b) Provide a primary-to-secondary side leakage evaluation for Byron 2 and Braidwood 2 during all plant conditions.

5 CAW-05-2047 (c) Assist the customer to respond to NRC requests for information.

Further this information has substantial commercial value as follows:

(a)

Westinghouse plans to sell the use of similar information to its customers for purposes of meeting NRC requirements for licensing documentation.

(b)

Westinghouse can sell support and defense of this information to its customers in the licensing process.

(c)

The information requested to be withheld reveals the distinguishing aspects of a methodology which was developed by Westinghouse.

Public disclosure of this proprietary information is likely to cause substantial harm to the competitive position of Westinghouse because it would enhance the ability of competitors to provide similar licensing support documentation and licensing defense services for commercial power reactors without commensurate expenses. Also, public disclosure of the information would enable others to use the information to meet NRC requirements for licensing documentation without purchasing the right to use the information.

The development of the technology described in part by the informnation is the result of applying the results of many years of experience in an intensive Westinghouse effort and the expenditure of a considerable sum of money.

In order for competitors of Westinghouse to duplicate this information, similar technical programs would have to be performed and a significant manpower effort, having the requisite talent and experience, would have to be expended.

Further the deponent sayeth not.

PROPRIETARY INFORMATION NOTICE Transmitted herewith are proprietary and/or non-proprietary versions of documents furnished to the NRC in connection with requests for generic and/or plant-specific review and approval.

In order to conform to the requirements of 10 CFR 2.390 of the Commission's regulations concerning the protection of proprietary information so submitted to the NRC, the information which is proprietary in the proprietary versions is contained within brackets, and where the proprietary information has been deleted in the non-proprietary versions, only the brackets remain (the information that was contained within the brackets in the proprietary versions having been deleted). Thejustification for claiming the information so designated as proprietary is indicated in both versions by means of lower case letters (a) through (f) located as a superscript immediately following the brackets enclosing each item of information being identified as proprietary or in the margin opposite such information. These lower case letters refer to the types of information Westinghouse customarily holds in confidence identified in Sections (4Xii)(a) through (4)(iiXf) of the affidavit accompanying this transmittal pursuant to 10 CFR 2.390(b)( 1).

COPYRIGHT NOTICE The reports transmitted herewith each bear a Westinghouse copyright notice. The NRC is permitted to make the number of copies of the information contained in these reports which are necessary for its internal use in connection with generic and plant-specific reviews and approvals as well as the issuance, denial, amendment, transfer, renewal, modification, suspension, revocation, or violation of a license, permit, order, or regulation subject to the requirements of 10 CFR 2.390 regarding restrictions on public disclosure to the extent such information has been identified as proprietary by Westinghouse, copyright protection notwithstanding. With respect to the non-proprietary versions of these reports, the NRC is permitted to make the number of copies beyond those necessary for its internal use which are necessary in order to have one copy available for public viewing in the appropriate docket files in the public document room in Washington, DC and in local public document rooms as may be required by NRC regulations if the number of copies submitted is insufficient for this purpose. Copies made by the NRC must include the copyright notice in all instances and the proprietary notice if the original was identified as proprietary.

BRAIDWOOD STATION UNITS 1 AND 2 Docket Nos. STN 50-456 and STN 50-457 License Nos. NPF-72 and NPF-77 and BYRON STATION UNITS 1 AND 2 Docket Nos. STN 50-454 and STN 50-455 License Nos. NPF-37 and NPF-66 Application for Technical Specification Improvement Regarding Steam Generator Tube Integrity Non-proprietary Version of Westinghouse LTR-CDME-05-32, "Limited Inspection of the Steam Generator Tube Portion Within the Tubesheet at Byron 2 and Braidwood 2," Revision 2, dated August 2005

v t e Letter Sequence Request
TAC:MC8966, Steam Generator Tube Integrity (Open)
Initiation Request Acceptance... Supplement Administration Withholding Request Acceptance, Withholding Request Acceptance Questions 4 August 2006 13 December 2006 28 March 2007 Answers 15 February 2007 Results Approval... Other: ML062780287, ML062780503, ML062990266, ML070810337, ML071000245, ML071210555
MONTHYEAR2007-02-15 [Table View]

ML053320303

Text

Subject:

References:

1.0 DESCRIPTION

2.0 PROPOSED CHANGE

3.0 BACKGROUND

4.0 TECHNICAL ANALYSIS

5.0 REGULATORY ANALYSIS

6.0 ENVIRONMENTAL CONSIDERATION

8.0 REFERENCES

1.0 DESCRIPTION

2.0 PROPOSED CHANGE

3.0 BACKGROUND

4.0 TECHNICAL ANALYSIS

5.0 REGULATORY ANALYSIS

6.0 ENVIRONMENTAL CONSIDERATION

8.0 REFERENCES

Subject:

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