DCL-05-018, License Amendment Request 05-01 Revision to Technical Specification 5.5.9, Steam Generator Tube Surveillance Program, and 5.6.10, Steam Generator Tube Inspection Report. to Allow Use of the W* Alternate Repair Criteria

License Amendment Request 05-01 Revision to Technical Specification 5.5.9, Steam Generator Tube Surveillance Program, and 5.6.10, Steam Generator Tube Inspection Report. to Allow Use of the W* Alternate Repair Criteria

ML050750134
Person / Time
Site:	Diablo Canyon
Issue date:	03/11/2005
From:	Oatley D Pacific Gas & Electric Co
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
+KBR1SISP20050630, DCL-05-018, OL-DPR-80, OL-DPR-82
Download: ML050750134 (96)

Text

.7 Pacific Gas and Electric Company' David H. Datley Vice President and General Manager Diablo Canyon Power Plant P. 0. Box 56 Avila Beach, CA 93424 805.545.4350 Fax: 805.545.4884 March 11, 2005 PG&E Letter DCL-05-018 U.S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, D.C. 20555-0001 Docket No. 50-275, OL-DPR-80 Docket No. 50-323, OL-DPR-82 Diablo Canyon Units 1 and 2 License Amendment Request 05-01 Revision to Technical Specification 5.5.9, "Steam Generator (SG) Tube Surveillance Program," and 5.6.10, "Steam Generator (SG) Tube Inspection Report." to Allow Use of the W* Alternate Repair Criteria for Indications in the Westinghouse Explosive Tube Expansion (WEXTEX) Region on a Permanent Basis In accordance with 10 CFR 50.90, enclosed is an application for amendment to Facility Operating License Nos. DPR-80 and DPR-82 for Units 1 and 2 of the Diablo Canyon Power Plant (DCPP), respectively. This License Amendment Request (LAR) will modify Technical Specification (TS) 5.5.9, "Steam Generator (SG) Tube Surveillance Program," and 5.6.10, "Steam Generator (SG) Tube Inspection Report,"

to allow use of the SG tube W star (W*) alternate repair criteria (ARC) on a permanent basis. In addition, the TS 5.6.10.d NRC notification requirements for the voltage-based ARC will be revised.

W* ARC allow axial primary water stress corrosion cracking indications in the Westinghouse explosive tube expansion (WEXTEX) region to remain in service if the indication is located below the bottom of the WEXTEX transition. Consistent with Westinghouse WCAP-14797-P, Revision 2, "Generic W* Tube Plugging Criteria for 51 Series Steam Generator Tubesheet Region WEXTEX Expansions," W* ARC accounts for the reinforcing effect that the tubesheet has on the external surface of the SG tube in the WEXTEX region for limiting SG tube burst and leakage. W* ARC reduces the need to plug SG tubes with indications in the WEXTEX region, and maintains structural and leakage integrity of tubes that are returned to service. contains a description of the proposed change, the supporting technical analyses, and the no significant hazards consideration determination. Enclosures 2 and 3 contain marked-up and retyped (clean) TS pages, respectively. Enclosure 4 provides the marked-up Final Safety Analysis Report Update pages for information only. Enclosure 5 provides Westinghouse proprietary technical information, which supports the changes. Enclosure 6 provides a non-proprietary version of the technical information contained in Enclosure 5.

A member of the STARS (Strategic Teaming and Resource Sharing) Alliance Callaway

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Document Control Desk PG&E Letter DCL-05-018 March 11, 2005 Page 2 The technical information contained in Enclosure 5 contains information proprietary to Westinghouse Electric Company LLC (Westinghouse). Accordingly, Enclosure 5 includes a Westinghouse authorization Letter, CAW-05-1964, an accompanying affidavit, a Proprietary Information Notice, and a Copyright Notice. The affidavit is signed by Westinghouse, the owner of the information. The affidavit sets forth the basis on which the Westinghouse proprietary information contained in Enclosure 5 may be withheld from public disclosure by the Commission, and it addresses with specificity the considerations listed in paragraph (b)(4) of 10 CFR 2.390 of the Commission's regulations. PG&E requests that the Westinghouse proprietary information be withheld from public disclosure in accordance with 10 CFR 2.390.

Correspondence with respect to the copyright or proprietary aspects of the application for withholding, related to the Westinghouse proprietary information or the Westinghouse affidavit provided in Enclosure 5, should reference Westinghouse Letter CAW-05-1964 and be addressed to J. A. Gresham, Manager, Regulatory Compliance and Plant Licensing, Westinghouse Electric Company LLC, P.O.

Box 355, Pittsburgh, Pennsylvania 15230-0355.

Other changes to TS 5.5.9 and 5.6.10 have also been proposed in Pacific Gas and Electric Company (PG&E) Letter DCL-04-086, "Response to NRC Request for Additional Information Regarding License Amendment Request 03-18, 'Revision to Technical Specifications 5.5.9, "Steam Generator (SG) Tube Surveillance Program,"

and 5.6.10, "Steam Generator (SG) Tube Inspection Report,"' for 4-volt Alternate Repair Criteria for Steam Generator Tube Repair," dated July 23, 2004. If approved prior to approval of this LAR, new TS markups will be provided.

The current TSs 5.5.9 and 5.6.10 allow implementation of W* ARC for Units 1 and 2 Cycles 10, 11, 12, and 13 only. Unit 1 Cycle 13 is projected to be complete in October 2005. Therefore, approval of this LAR is requested prior to October 2005 to allow continued implementation of this ARC during the DCPP Unit 1 thirteenth refueling outage and beyond. PG&E requests that the license amendment be effective immediately, to be implemented within 90 days of issuance of an amendment.

PG&E has determined that this LAR does not involve a significant hazard consideration as determined per 1 OCFR50.92. Pursuant to 1 OCFR51.22(b), no environmental impact statement or environmental assessment needs to be prepared in connection with the issuance of this amendment.

If you have any questions or require additional information, please contact Stan Ketelsen at 805-545-4720.

A member of the STARS (Strategic Teaming and Resource Sharing) Alliance Callaway

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• South Texas Project. Wolf Creek

Document Control Desk PG&E Letter DCL-05-018 March 11, 2005 Page 3 Sincerely, David H. Oatley Vice President and General Manager kjse/4328 Enclosures cc:

Edgar Bailey, DHS Bruce S. Mallett David L. Proulx Diablo Distribution cc/enc:

Girija S. Shukla A member of the STARS (Strategic Teaming and Resource Sharing) Alliance Callaway

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• Wolf Creek

PG&E Letter DCL-05-018 UNITED STATES OF AMERICA NUCLEAR REGULATORY COMMISSION In the Matter of

)

PACIFIC GAS AND ELECTRIC COMPANY)

• )

Diablo Canyon Power Plant

)

Units 1 and 2 Docket No. 50-275 Facility Operating License No. DPR-80 Docket No. 50-323 Facility Operating License No. DPR-82

_)

AFFIDAVIT David H. Oatley, of lawful age, first being duly sworn upon oath says that he is Vice President and General Manager of Pacific Gas and Electric Company; that he has executed license amendment request 05-01 on behalf of said company with full power and authority to do so; that he is familiar with the content thereof; and that the facts stated therein are true and correct to the best of his knowledge, information, and belief.

aid H. Oatley Vice President and General Manager Subscribed and sworn to before me this 11th day of March 2005.

44g -CA<g Kot-ary Public

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County of San Luit OispV State of California if Ndayc-Caw V m o 1397547 N o o~ y P~ t~ e - c aw i ri.!

Son Lii Obbpo Cm u ty PG&E Letter DCL-05-018 EVALUATION

1.0 DESCRIPTION

This letter is a request to amend Operating Licenses DPR-80 and DPR-82 for Units I and 2 of the Diablo Canyon Power Plant (DCPP), respectively.

The proposed changes will modify Technical Specification (TS) 5.5.9, "Steam Generator (SG) Tube Surveillance Program," and 5.6.10, uSteam Generator (SG)

Tube Inspection Report," to allow use of the SG tube W star (W*) alternate repair criteria (ARC) for DCPP Units 1 and 2 on a permanent basis. In addition, the TS 5.6.10.d NRC notification requirements for the voltage-based ARC will be revised.

The W* ARC allows axial primary water stress corrosion cracking (PWSCC) indications in the Westinghouse explosive tube expansion (WEXTEX) region to remain in service if the indication is located below the bottom of the WEXTEX transition (BWT). The current TSs 5.5.9 and 5.6.10 allow implementation of the W* ARC for DCPP Units 1 and 2 Cycles 10, 11, 12, and 13 only. DCPP Unit 1 Cycle 13 is projected to be completed in October 2005.

2.0 PROPOSED CHANGE

S This license amendment request (LAR) revises the existing TS surveillance program and reporting requirements associated with W* ARC for SG tubing.

The proposed TS changes would allow use of the W* ARC on a permanent basis as follows:

1. ForTSs 5.5.9.b.2.e, 5.5.9.d.1.f.2, 5.5.9.d.1.k, 5.6.10.d.1, 5.6.10.e, and 5.6.10.f Remove the existing note "Applicable for Units 1 and 2, Cycles 10, 11, 12, and 13 only" and associated asterisks.

2. ForTS 5.5.9.b.2.d Replace the period with a comma at the end of the requirement

3. ForTS 5.5.9.b.2.e Remove existing note "In-Situ Testing will be performed in accordance with PG&E Letters DCL 98-148 dated October 22, 1998, and DCL 01-052 dated May 4, 2001, for Cycles 10 and 11, and Letter DCL 01 -095 dated September 13, 2001, for Cycles 12 and 13" and associated asterisks. The current W* in-situ testing program will be terminated.

1 -

PG&E Letter DCL-05-018

4. ForTS 5.5.9.d.1.k.ii Revise the reference from "WCAP-14797, Revision 1" to 'WCAP-14797-P, Revision 2".

5. ForTS 5.6.10.d.1 The NRC notification requirement for voltage-based repair criteria for estimated leakage is revised from "if estimated leakage based on the projected end-of-cycle (or if not practical, using the actual measured end-of-cycle) voltage distribution (reduced by estimated leakage by all other alternate repair criteria - *) exceeds the leak limit determined form the licensing basis dose calculation for the postulated main steamline break for the next operating cycle" to "If estimated leakage based on the projected end-of-cycle (or if not practical, using the actual measured end-of-cycle) voltage distribution, increased by estimated leakage by all other sources (alternate repair criteria and non-alternate repair criteria indications), exceeds the leak limit determined from the licensing basis dose calculation for the postulated main steamline break for the next operating cycle".

It is noted that the above change revises the word "form" to the word "from."

6. ForTS 5.6.1O.d.2 The requirement "If circumferential crack-like indications are detected at the tube support plate intersections" is deleted.

7. For TS 5.6.1O.d.4 The requirement "If indications are identified at tube support plate elevations that are attributable to primary water stress corrosion cracking" is deleted.

8. For TS 5.6.10.d.3 and 5.6.10.d.5 TS 5.6.1O.d.3 is renumbered to 5.6.1O.d.2 and TS 5.6.1O.d.5 is renumbered to 5.6.1 Q.d.3.

9. For TS 5.6.1O.e Requirements 1, 2, 3, and 4 are replaced with a new expanded Requirement 1 which states: "Identification of W* tube indications and indications that do not meet W* requirements and were plugged or repaired, including the following information: the number of indications, the location of the indications (relative to the BWT and TTS), the orientation (axial, circumferential, volumetric, inclined),

the severity of each indication (estimated depth), the side of the tube in which the indication initiated (inside or outside diameter), the W* inspection distance measured with respect to the BWT or TTS (whichever is lower), the length of axial indications, the angle of inclination of clearly skewed axial cracks (if 2

PG&E Letter DCL-05-018 applicable), verification that the upper crack tip of W* indications returned to service remain below the TTS by at least the 95 percent confidence nondestructive examination (NDE) uncertainty on locating the crack tip relative to the TTS, updated 95 percent growth rate for use in operational assessment, the cumulative number of indications detected in the tubesheet region as a function of elevation within the tubesheet, and the condition monitoring and operational assessment main steamline break leak rate for each indication and each SG per the leak rate methodology described in PG&E Letter DCL-05-018, dated March 11, 2005."

The main steam line break (MSLB) accident primary to secondary leakage rate methodology is revised by replacing the DENTFLO model with a new model referred to as the constrained crack leak rate model. The constrained crack leak model will be used to estimate MSLB leakage for detected axial PWSCC located within the flexible W* length, detected degradation (axial, circumferential, and volumetric) located between the flexible W* length and the top of the tubesheet (TTS) minus 12 inches, and projected PWSCC indications located between 8 to 12 inches below the TTS. Also, a MSLB primary to secondary leakage rate methodology for detected and undetected degradation located below the TTS minus 12 inches and left in service is added, using a new model referred to as the severed tube model.

10. For TS 5.6.10.e A new Requirement 2 is added to state "Assessment of whether the results were consistent with expectations and, if not consistent, a description of the proposed corrective action." On pages 5.0-30 and 5.0-30a, the ucontinued" is moved after the TS 5.6.10 title.

The proposed TS changes are noted on the markup TS pages provided in. The proposed retyped TS are provided in Enclosure 3. The proposed updates to the Final Safety Analysis Report Update (FSARU) are contained in Enclosure 4. Proprietary and nonproprietary versions of technical information to support the W* ARC developed by Westinghouse Electric LLC are contained in Enclosures 5 and 6, respectively.

3.0 BACKGROUND

3.1 SG Tube Integrity The SG tubes constitute more than half of the total area of the reactor coolant pressure boundary (RCPB). Design of the RCPB for structural and leakage integrity is a requirement of 10 CFR 50 Appendix A.

Specific requirements or regulatory guidance governing the maintenance and inspection of SG tube integrity are in the DCPP TS, Section Xl, of the American Society of Mechanical Engineers (ASME) 3 PG&E Letter DCL-05-018 Boiler and Pressure Vessel Code, and Regulatory Guide (RG) 1.83.

These include requirements for periodic inservice inspection of the tubing, flaw acceptance criteria (i.e., repair limits for plugging), and primary-to-secondary leakage limits. These requirements, coupled with the broad scope of plant operational and maintenance programs, have formed the basis for assuring adequate SG tube integrity.

SG tube plugging limits are specified in the DCPP TS. The current DCPP TS require that a tube with an imperfection be removed from service by plugging if the imperfection depth in the tube is greater than or equal to 40 percent through-wall, unless the degradation is subject to voltage-based outside diameter stress corrosion cracking (ODSCC) ARC, W* ARC, or PWSCC within dented tube support plate ARC.

TS 5.5.9 repair limits ensure that tubes accepted for continued service will retain adequate structural and leakage integrity during normal operating, transient, and postulated accident conditions, consistent with General Design Criterion (GDC) 14, 15, 30, 31, and 32 of 10 CFR 50, Appendix A.

Structural integrity refers to maintaining adequate margins against gross failure, rupture, and collapse of the SG tubing. Leakage integrity refers to limiting primary-to-secondary leakage to within acceptable limits.

Section 5.5.2.5 of the DCPP FSARU discusses the SG tube surveillance program, including the inservice inspection requirements, primary-to-secondary leakage requirements, and SG ARC.

Sections 15.3.1 and 15.4.1 of the DCPP FSARU discuss the small break loss-of-coolant accident (LOCA) and large break LOCA, respectively. The small and large break LOCA analyses assume an average of 15 percent SG tube plugging for all four SGs, which provides the basis for the maximum allowable SG tube plugging limit as indicated in DCPP FSARU, Section 15.3.1.3.1, and FSARU Table 15.4-7A. The consequences associated with a SG tube rupture (SGTR) event are discussed in DCPP FSARU Section 15.4.3. The limit for accident-induced leakage through SG tubes is based on the FSARU, Section 15.5.18.1, MSLB radiological consequences analysis for control room and offsite exposure. The current limit on MSLB postaccident induced leakage is 10.5 gallons per minute in any one SG.

3.2 Existing SG Tube W* ARC The existing SG tube W* ARC are described in Section 5.5.2.5.3 of the DCPP Units 1 and 2 FSARU. The W* ARC incorporates the guidance provided in WCAP-1 4797, Revision 1, uGeneric W* Tube Plugging Criteria for 51 Series Steam Generator Tubesheet Region WEXTEX Expansions,"

dated February 1997 (proprietary).

4 PG&E Letter DCL-05-018 For tubes to which the W* ARC are applied, indications of degradation in excess of 40 percent through-wall can remain in service without a loss of functionality or structural and leakage integrity. Tubes to which W* ARC are applied can experience through-wall degradation up to the limits defined in WCAP-14797, Revision 1, without increasing the probability of a tube rupture or large leakage event. The guidance of RG 1.121, "Bases for Plugging Degraded PWR Steam Generator Tubes," issued for comment in August 1976, is used to assess the limits of acceptable tube degradation within the W* length. A potential exists for W* ARC tubes to result in primary-to-secondary leakage during a postulated steam line break. A leak rate model is provided in WCAP-14797, Revision 1. That model is used to calculate the expected leakage at MLSB conditions for W* tubes. Tube degradation of any extent below the W* length, including a complete circumferential separation of the tube, is acceptable and does not require repair.

For design basis events, the required structural margins of the SG tubes are maintained by the presence of the tubesheet. Tube rupture is precluded for cracks in the WEXTEX region due to the constraint provided by the tubesheet. The W* length is the undegraded length of tube necessary to ensure structural integrity. The W* length, which includes consideration for NDE uncertainties and crack growth, provides the necessary resistive force to preclude loads which could result in tube pullout under normal operating and accident conditions in the event of a complete circumferential separation of the tube below the W*

length. Therefore, RG 1.121 margins against burst are maintained for both normal and postulated accident conditions for the W* ARC.

At normal operating differential pressure, leakage from PWSCC in the W* length 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. Primary-to-secondary leakage flow due to a postulated SGTR is not affected since the tubesheet enhances the tube integrity in the region of the WEXTEX expansion by precluding tube deformation beyond its initial expanded outside diameter. The resistance to both tube rupture and collapse is strengthened by the tubesheet in that region. MSLB leakage is limited by leakage 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 crack face opening compared to free span indications. The combined leakage for all such tubes, plus the combined leakage developed by any other ARC, is maintained below the allowable MSLB leak rate limit (10.5 gpm) such that offsite doses are maintained less than the 10 CFR 100 guideline values and the control room dose is maintained less than the value in GDC 19 of 5

PG&E Letter DCL-05-018 10 CFR 50 Appendix A. TheW* criteria maintain the RG 1.121 margins against leakage for both normal and postulated accident conditions.

In February 1999, the NRC originally issued the W* ARC in license amendments 129 and 127 to Operating Licenses DPR-80 and DPR-82 for DCPP Units 1 and 2, respectively. The original W* ARC was only applicable for Cycles 10 and 11 of DCPP Units 1 and 2 to allow time for in situ pressure testing of W* indications to validate the W* leak rate model contained in WCAP-14797, Revision 1.

In April 2002, an extension of the W* ARC for Cycles 12 and 13 was approved by the NRC in license amendments 151/151 to Operating Licenses DPR-80 and DPR-82 for DCPP Units 1 and 2, respectively. The extension of the W* ARC to Cycles 12 and 13 was intended to allow PG&E additional time to validate the W* leak rate model through performance of additional in situ pressure testing of W* indications, as requested by the NRC. At the time the LAR was submitted in PG&E Letter DCL-01-095, dated September 13, 2001, to request use of the W* ARC for Cycles 12 and 13, only five W* indications at DCPP had grown deep enough to meet the screening criteria for in situ testing. This provided a total of six industry WEXTEX leak tests, which was less than the twenty data points which were committed to for leak rate model validation. None of these indications leaked during performance of the in situ tests, demonstrating the leak limiting capability of the WEXTEX expansion. PG&E's commitments for in situ testing for Cycles 10 and 11 were originally provided to the NRC in Letter DCL-98-148, dated October 22, 1998, and Letter DCL-01 -052, dated May 4, 2001. The in situ testing commitments were supplemented by commitments for Cycles 12 and 13 provided in Letter DCL-01-095, dated September 13, 2001. If there were no leaking W* indications obtained after 20 in situ tests (summed over all plants with WEXTEX expansions), it was intended that PG&E would initiate discussions with the NRC staff to determine if in situ testing should be continued. Following the April 2002 W* license extension, three additional W* indications at DCPP have grown deep enough to meet the screening criteria for in situ testing, and none leaked during in situ testing.

3.3 Results of W* ARC Inspections in First EiQht Outages of Implementation The W* ARC has been implemented in four refueling outages on each unit, for a total of eight outages. The W* ARC was first implemented in the ninth refueling outage for DCPP Units 1 and 2 (1 R9 and 2R9). The results of each inspection have been transmitted to the NRC in 90-day reports pursuant to the DCPP TS, except for the twelfth DCPP Unit 2 refueling outage (2R12) 90-day report, which is currently being prepared.

6 PG&E Letter DCL-05-018 Table 1 of Enclosure 1 provides the hot leg WEXTEX tubesheet region inspection scope and inspection extent since PWSCC was first identified in each unit. One hundred percent of tubes in the hot leg WEXTEX region have been inspected in each outage in which W* was implemented. In the first five outages of W* implementation, the specified minimum inspection extent was plus two to minus eight inches from the TTS. In the eleventh DCPP Unit 2 refueling outage (2R1 1), PG&E performed sample cold leg TTS Plus PointTM coil probe inspections (100 percent in SG 2-4 and 20 percent in SGs 2-1, 2-2, and 2-3). Cold leg inspections have not been required, and no cold leg TTS indications have ever been detected in DCPP Units 1 and 2, with an increased minimum inspection extent of minus 8.5 inches below the TTS for all hot leg and cold leg inspections to bound the larger W* lengths in the cold leg. The minimum inspection extent of minus 8.5 inches was also used in the twelfth DCPP Unit 1 refueling outage (1R12) and 2R12.

Currently, there are a total of 258 W* tubes in service in DCPP Units I and 2, as discussed below.

. In DCPP Unit 1,16 axial PWSCC indications are currently in service in 14 W* tubes, and 3 of these indications are in 3 deplugged tubes. In addition, one Unit 1 tube is in service with a volumetric indication located below the flexible W* length in SG 1-3. In the 1 R12 90-day report, PG&E noted that the volumetric signal is likely due to a dent, not tube degradation. In DCPP Unit 2, 67 axial PWSCC indications are currently in service in 61 W* tubes, and 40 of these indications are in 37 deplugged tubes.

Of these 40 deplugged tubes that are in service, 39 also have PWSCC in the plug expansion zone (PEZ) region. This degradation is discussed below.

. PWSCC in the PEZ of deplugged tubes in DCPP Units 1 and 2 was recently identified in 2004. Based on 100 percent Plus Pointm coil probe inspection of all potentially degraded deplugged tube PEZ regions in 1R12 and 2R12, 129 Unit 1 and 92 Unit 2 tubes were confirmed to have PWSCC in this region and were returned to service under the W* ARC.

The end of cycle (EOC) 13 projected MSLB W* leak rates for the worst case Unit 1 and Unit 2 SGs are 0.042 gpm and 0.604 gpm, respectively, much less than the limit of 10.5 gpm for all ARC and non-ARC leakage sources.

7 PG&E Letter DCL-05-018 3.4 Purpose for Proposed Amendments The DCPP SGs have experienced tube PWSCC degradation within the tubesheet region of the SG. SG tubes that experience excessive degradation have reduced integrity of the primary-to-secondary pressure boundary. Eddy current examination is used to measure the extent of SG tube degradation. When the reduction in tube wall thickness reaches 40 percent of nominal SG tube wall thickness, the SG tube is considered defective and is removed from service by installing plugs in the SG tube at the inlet and outlet of the SG tube unless the tube can be left in service under an ARC.

The installation of plugs in a SG tube eliminates the heat transfer surface associated with the tube. In addition, plug installation leads to the reduction in the primary coolant flow available for core cooling. The installation of plugs into SG tubes is limited to an average of 15 percent of the tubes in all four SGs.

This LAR will allow the continued use of the TS 5.5.9 W* ARC, with conservative modifications to the W* ARC leak rate methods. This will allow at least 258 SG tubes with degradation in excess of 40 percent through-wall in portions of the tubesheet region to remain in service and thus minimize the reduction in SG tube heat transfer surface area and primary coolant flow due to tube plugging.

The current TSs 5.5.9 and 5.6.10 allow implementation of W* ARC for Units 1 and 2 Cycles 10, 11, 12, and 13 only. Unit 1 Cycle 13 is projected to be complete in October 2005. Therefore, approval of this LAR is requested prior to October 2005 to allow continued implementation of the W* ARC during the DCPP Unit I thirteenth refueling outage (1 R13) and subsequent Unit 1 and Unit 2 outages. Approval of this change will reduce the number of SG tubes that need to be removed from service by plugging during 1R13 and subsequent Unit 1 and Unit 2 outages.

4.0 TECHNICAL ANALYSIS

4.1 Basis for Proposed Chanaes to W* ARC 4.1.1 Permanent W* ARC PG&E is proposing to renew the W* ARC license on a permanent basis based on a proposed new leak rate method which is demonstrated to be very conservative and requires no additional plant data for benchmarking or validation.

8 PG&E Letter DCL-05-018 To implement the W* ARC on a permanent basis, the existing note "Applicable for Units 1 and 2, Cycles 10,11, 12, and 13 only" and associated asterisks is removed from TSs 5.5.9.b.2.e, 5.5.9.d.1.f.2, 5.5.9.d.1.k, 5.6.10.d.1, 5.6.10.e, and 5.6.10.f. In addition, an editorial correction is made to TS 5.5.9.b.2.d to replace the period with a comma at the end of the requirement. This editorial correction has no adverse impact on the TS 5.5.9.b.2.d requirement.

4.1.2 MSLB Leak Rate Methodology for Degradation within 12 inches from Top of Tubesheet using Constrained Crack Leak Rate Model The existing W* ARC leak method developed and documented in WCAP-14797, Revision 1, and WCAP-14797-P, Revision 2, referred to as the DENTFLO model, assigns a leak rate~to each axial PWSCC indication located within the flexible W* length, as a function of tubesheet zone and distance from the upper crack tip (UCT) to the BWT, accounting for NDE uncertainty on locating BWT and on locating the UCT with respect to the TTS. No leakage is assigned to any type of detected degradation located below the flexible W* length. The existing method is developed from two leak rate models: leak rate through the tube to tubesheet crevice, and leak rate through a constrained crack, i.e.,

a crack restricted from opening due to the tubesheet constraint.

These two empirical models were integrated, and designated as the DENTFLO model.

To address NRC questions on the validity of the DENTFLO model (no tests were performed to benchmark the predicted DENTFLO leak rates), a more conservative leak rate model is being proposed, and only relies on data from the constrained crack testing. The constrained crack model will assign leak rates as a function of tube radial position and distance from the UCT to the TTS, including NDE uncertainty on locating the UCT to TTS, for the following types of indications: detected axial PWSCC indications in the flexible W* length, detected indications (axial PWSCC, circumferential PWSCC, and volumetric) between the W* length and TTS minus 12 inches, and projected undetected axial and circumferential PWSCC indications between 8 inches (the inspection extent) and 12 inches below the TTS. Any type of degradation located below the flexible W* length, including circumferential and volumetric indications, will continue to be left in service.

9 PG&E Letter DCL-05-018 4.1.2.1 Description of Constrained Crack Leak Model The proposed constrained crack leak model is a prediction methodology based only on the data from the constrained crack tests as presented in Table 6.3-3 of WCAP-14797-P, Revision 2.

By using only the constrained crack data, the predictions omit consideration of the resistance to the leak rate from the crevice, i.e., interference fit, between the tube and the tubesheet, and therefore, may be expected to be significantly conservative. A review of the raw test data was performed before starting the analysis because the data presented in WCAP-14797-P, Revision 2, Table 6.3-3, were rounded to provide a summary of the original results. In addition, the contact pressures reported as zero in Table 6.3-3 were for cases where there was a physical gap between the tube and the tubesheet, and a negative contact pressure had to be calculated to represent the magnitude of the actual gap. It was found that two of the leak rates for test collar A, with a tighter clearance, at a nominal pressure difference of 2650 pounds per square inch (psi) at 600 degrees Fahrenheit (0F) were lower than listed in Table 6.3-3 by factors of 0.6 and 0.3, and result because the fluid collection times were actually greater than listed in the data summary. All other data values were confirmed to be accurate. The discovered changes are not meaningful to the overall W* ARC analysis and do not affect any prior W* ARC analyses for DCPP Units 1 and 2. Moreover, the originally reported leak rate values were greater than actually obtained, i.e.,

conservative, and would result in a slight overestimating of the leakage from plant indications.

The data were analyzed to prepare two figures relating the leak rate to the contact pressure and the depth in the tubesheet during a postulated accident event. Figure 1 in Enclosure 5 presents the median leak rate, arithmetic average leak rate, and 95 percent simultaneous confidence bound on the arithmetic average leak rate from the constrained crack specimens as a function of contact pressure within the test collar. The contact pressure was varied by using two different diameter tubesheet collars and by changing the temperature and internal pressure of the tube. Slightly negative contact pressures represent small clearances between the tube and tubesheet collar. These are the positive diametral gap values in WCAP-14797-P, Revision 2, Table 6.3-3, for collar B. The median and average logarithm of the leak rate as a function of the contact pressure is given by the relation, ln(Q)=ao +a, P, + &

(1) 10 PG&E Letter DCL-05-018 where £ is a statistical error about the regression line. The value of c will be somewhat constant over the range of the data and is to be calculated at a one-sided 95 percent simultaneous confidence level. A prediction of the average logarithm of the leak rate, ln(Q,),

at a 95 percent confidence level for any indication, i, with a contact pressure Pc, can be calculated as, In (Qi ) = ao + a, Pj; + (2F2,n-2,a ) {2 5\\l C

1 (i

m )

(2) n1 SSFI where ao and a, are coefficients obtained from performing a regression analysis of the data, Pcm is the mean value of the test contact pressures and SSPc is the corrected sum of squares of the contact pressures found as, of SSPC =(P 4 PC.),

(3) i-I n is the number of data used to obtain the coefficients of the regression equation, s is the standard deviation of the regression errors, and F is the variate from the F-distribution for n and n-2 degrees of freedom with £ being the percentile in the upper tail, e.g., a 95th percentile corresponds to an £ of 5 percent. Since various lengths of the cracks were tested, the variance of the regression errors includes the effect of different lengths of through-wall indications. The 95th percentile value of Ffor 2 regression coefficients and 36 data pairs is 2.221. The use of the F-distribution is necessary because the confidence bound curve is to be applicable to all values of the contact pressure simultaneously, i.e., all indications in the detected population. The average of the logarithm of the leak rate corresponds to the median leak rate, but not the arithmetic average leak rate. To obtain the average leak rate, the exponential is taken of the logarithm of the leak rate plus 1/2 of the variance of the prediction errors, s2, of the logarithm of the leak rate. Therefore, a simultaneous one-sided 95 percent confidence on the expected or arithmetic average value of the leak rate, as shown on Figure 1 of, is given by the following, where s is 0.05, 1

1 (aP,+(4 m ). 2 25 Qi =exp ao +a, Pi+ (2F~.2,2z)

S 2 J 4

11 PG&E Letter DCL-05-018 In order to apply this prediction to estimate the total leak rate from several indications in the tubesheet, relations for the contact pressure as a function of depth and radius from the center of the tubesheet were developed from the results of the finite element analysis discussed in WCAP-14797-P, Revision 2. The tubesheet has been divided into five zones for which the contact pressure, as a function of depth, was determined for use in leak rate calculations and reported in WCAP-14797-P, Revision 2, Table 4.3-11. Table 1 in Enclosure 5 lists the intercept, bo, and slope, b1, parameters for the contact pressure as a function of depth, L, in the tubesheet for the five zones, i.e., BI through B4 and A. The relationships are all of the form, PI =bo + bL (5) where the coefficients bo and b1 vary as a function of the zone of the tubesheet for the tube with the indication. A plot of the contact pressures for each zone is provided as Figure 2 in Enclosure 5, and includes the residual contact pressure from the WEXTEX expansion process. The analysis was further refined by examining the relationship between the intercept and slope of the prediction equations as a function of tube location radius. It was found that second order polynomial expressions could be used to describe the parameters almost exactly, i.e., with negligible error, confirming that the analyses could be performed by using contact pressure relation parameters calculated for each specific tube. In summary, the finite element model results for contact pressure as a function of radius can be described by second order polynomial curve fits.

Table 2 in Enclosure 5 provides the polynomial coefficients that were then used to determine the values of bo and b1 for any given radius from the center of the tubesheet. A plot of the intercept and slope coefficients as a function of tube location radius is provided on Figure 3 in Enclosure 5. Here, the following relationships are

depicted,

b. =go + g1R+g 2R2 (Intercept) b1 = ho + hjR + h2R2 (Slope)

(6)

The results from converting the contact pressures to elevation depths for leak rate calculations using the finite element analysis results for Zone B1 are shown on Figure 4 in Enclosure 5 to illustrate the relationship. Zone B1 is characterized as having the most severe tubesheet bow effects associated with Zones B1 through B4 on Figure 8.2-1 of WCAP-14797-P, Revision 2.

12 PG&E Letter DCL-05-018 4.1.2.2 Bounding Constrained Crack Leak Rate for Undetected Indications Between 8 to 12 Inches Below the TTS Since the minimum inspection extent is 8 inches below the TTS, there is a short distance where undetected degradation could exist within 12 inches from the top of tubesheet. A method has been developed to conservatively estimate the number of undetected PWSCC indications between 8 inches and 12 inches below the TTS, and a bounding leak rate of 0.0028 gpm will be assigned to each postulated indication. The value of 0.0028 gpm is derived from the constrained crack leak model in Figures 1 and 2 in. From Figure 2, the contact pressures at a depth of 8 inches into the tubesheet at each of the 5-zone radii range from 2834 to 2557 psi. From Figure 1, which shows the 95 percent simultaneous confidence bound for the leak rate as a function of total contact pressure, the corresponding leak rates at these contact pressures are between 0.0022 to 0.0028 gpm. The constrained crack leak rate data are reported as a function of total contact pressure. Thus, applications of the data should be based on the total contact pressure during SG operation, including the 693 psi residual installation contact pressure. Figures 1, 2, and 6 in Enclosure 5 represent the total contact pressure during SG operation.

4.1.2.3 Justification for Applking Constrained Crack Leak Model to Circumferential Indications Between 8 to 12 Inches Below the TTS A comparison of the constrained axial crack and drilled hole crevice leak tests was performed in order to justify that the constrained crack leak rate model can be applied to circumferential indications located between 8 to 12 inches below the TTS. The drilled hole crevice leak rate test data is provided in Table 6.2-3 of WCAP-14797-P Revision 2. The drilled hole crevice tests are representative of a tube with a 360-degree through-wall circumferential crack where the ends have been separated, thus bounding any circumferential (or volumetric) indication that could be postulated in the tubesheet. This is because the total circumference of the drilled holes is more than twice that of a severed tube and the tube was deformed away from the tubesheet collar in the vicinity of the holes. Two subsets of each test series were considered. The differential pressure for each was on the order of 2650 psi at a temperature of 600'F. The data for tests of specimens with actual crevice lengths of approximately 0.6 and 1.3 inches were compared to the constrained axial crack test results for the designated close and tight collars, identified as B and A, respectively. The basis for the selection of the test data 13 PG&E Letter DCL-05-018 with which to make the comparison was the contact pressure. The crevice leak rate data in WCAP-14797-P, Revision 2, Table 6.2-3, does not include the residual contact pressure from the installation process and a value of 693 psi, consistent with prior analyses, was added to each contact pressure in order to make a direct comparison between specimen types. The results are illustrated on Figure 6 in Enclosure 5. The axial crack data in Figure 6 are the Figure 1 data at 2650 psi differential pressure separated into two contact pressure groups approximating 1000 psi and 2500 psi.

The axial cracks ranged from about 0.33 to 0.59 inch long. The equivalent length of the entrance to the crevice for the tubes with the drilled holes was about 2.8 inches (equivalent at least to the circumference of the expanded tube). The implication from observing similar leak rates from greater crack lengths is that the resistance to flow of the crevice is significantly greater than that of the restrained crack. This is consistent with the observation that the predicted leak rates for the DCPP Unit 1 and 2 SGs using the constrained crack model are more than twice the values obtained from the DENTFLO analyses, with the exception of SG 1-1 as discussed later.

In practice it has been found that the leak rate from freespan circumferential cracks is significantly less than that from freespan axial cracks with the same length. The difference is associated with the flexibility of the crack flanks and axial cracks would be expected to have a greater crack opening area for the same internal pressure. The restriction of the tubesheet would prevent the flanks of an axial crack from deforming radially outward and provide a meaningful compressive hoop stress so that axial and circumferential cracks with similar lengths within the tubesheet could be expected to exhibit similar leak rates under conditions of the same differential pressure and temperature. This reinforces the conclusion that the constrained crack model results would be expected to be more than two multiples of the DENTFLO model results. It also provides support for the use of the constrained crack model for the evaluation of circumferential cracks. The confidence bound for the leak rate is also shown on Figure 6 in, illustrating the significant margin between the evaluation curve and the test data.

4.1.2.4 Methodology for Estimating the Number of Undetected Indications In Service Below the Current Tubesheet Region Inspection Distance of 8 Inches 193 new DCPP Units I and 2 hot leg tubesheet PWSCC WEXTEX indications, including indications within the WEXTEX expansion 14 PG&E Letter DCL-05-018 transition, have been reported through 1R12 and 2R12: 35 in Unit 1 (24 axial and 11 circumferential), and 158 in Unit 2 (143 axial and 15 circumferential). Table 1 of Enclosure 1 provides the number of new PWSCC indications detected each refueling outage. Table 2 of Enclosure 1 provides the distribution of PWSCC indications as a function of distance to the top of tubesheet, and also provides the distribution before W* application (3 to 5-inch inspection extent) and after W* application (8 to 8.5-inch inspection extent). The distances are binned in 1-inch increments. 166 PWSCC indications have been reported within 3 inches of the TTS. These data strongly imply that the distribution of indications, and the potential for new indications, is not uniform within the tubesheet and is skewed with the highest number near the TTS. PWSCC initiation is likely associated with a localized geometry discontinuity resultant from the tubesheet drilling process. As all tubesheet holes were drilled from the primary face, the frequency of tube hole abnormalities would expect to be increased as the secondary side face of the tubesheet is approached. The DCPP Units 1 and 2 data support this expectation. Furthermore, the circumferential extent of these abnormalities would be expected to be limited. The inspection data that shows the largest circumferential arc extent is 78 degrees. In addition, of the 26 circumferential indications reported to date, 18 were located within the expansion transition (within 1 inch of the TTS), with the deepest at about 9 inches below the TTS. No circumferential ODSCC has been reported below the top of tubesheet.

Top of tubesheet PWSCC was first reported at DCPP Unit 1 and DCPP Unit 2 in 1 R6 and 2R5, respectively. Circumferential PWSCC was first reported 2R5 and I R7. The number of new PWSCC indications has shown a declining trend overtime, as seen in Table 1 and Figure 1 of Enclosure 1. The hot leg top of tubesheet region was shot peened in 1 R5 and 2R5 to mitigate the potential for PWSCC, and may be a contributing factor for the declining trend of PWSCC initiation at the top of tubesheet.

Figures 2 and 3 in Enclosure 1 present a cumulative distribution plot of elevations of all PWSCC indications reported at DCPP Units I and 2 based on the data in Table 2. These plots clearly show that the PWSCC initiation potential is significantly greater for the top of tubesheet region than at deeper elevations. Figure 2 also plots the Table 2 distribution of PWSCC indications before and after W* application, and shows modest increased initiation potential for indications at deeper elevations below the TTS.

15 PG&E Letter DCL-05-018 Therefore, the historical indication counts can be used to estimate the number of indications between 8 and 12 inches.

Specified inspection extents are normally exceeded in the field, and no increased initiation potential for indications at deeper elevations below the TTS has been identified by this practice. For example, in 2R12, the actual average inspection extent was about 10.6 inches below the TTS, much greater than the 8.5 inch specified extent. Ninety-five percent of the tubes received an inspection extent of about 9.3 inches below the TTS, and 5 percent of the tubes received an inspection extent of about 11.6 inches below the TTS. Therefore, in support of the assessment methodology in this section, the inspection extent below the TTS can be approximated as 100 percent to about TTS minus 9.3 inches with sample inspections below 9.3 inches. In addition, about 250 tubes in DCPP Units 1 and 2 have been Plus PointTM coil probe inspected the entire length of the hot tubesheet region, due to various conservative inspection program practices.

No PWSCC has been detected below 8 inches from the TTS in this inspection sample, again confirming that there is no increased initiation potential for indications at deeper elevations below the TTS.

Of the 35 PWSCC indications in DCPP Unit 1, 9 percent were between 4 to 8 inches below the TTS, and 17 percent were between 8 to 12 inches below the TTS. The small number of total Unit 1 indications tends to skew these percentages on the high side. Of the 158 PWSCC indications in DCPP Unit 2, 4 percent were between 4 to 8 inches below the TTS, and 3 percent were located between 8 to 12 inches below the TTS.

The number of undetected PWSCC indications between 8 and 12 inches below the TTS would not be expected to be much greater than the number reported between 4 and 8 inches below the TTS. For combined DCPP Units 1 and 2 data, 10 indications have been reported between 4 to 8 inches below the TTS, and 10 indications have been reported between 8 to 12 inches below the TTS. Therefore, it is reasonable to expect that the number of undetected indications between 8 and 12 inches would be bounded by about 9 to 17 percent for Unit 1 and about 3 to 4 percent for Unit 2 of the total number of indications detected. For Unit 1, 17 percent of the total historical plus EOC projected indication count will be assumed to be undetected between 8 and 12 inches below the TTS. For Unit 2, 4 percent of the total historical plus EOC projected indication count will be assumed to be undetected between 8 and 12 inches below the TTS.

16 PG&E Letter DCL-05-018 Figures 4 and 5 in Enclosure 1 illustrate the cumulative number of PWSCC indications versus effective full power years (EFPY) in DCPP Unit 1 and DCPP Unit 2, respectively. A linear regression analysis using only data from the last four outages shows that about 5 new indications are anticipated at the thirteenth DCPP Unit 1 refueling outage (1 R13) and about 6 new indications are anticipated at the thirteenth DCPP Unit 2 refueling outage (2R1 3).

Therefore, the cumulative DCPP Unit 1 total number of indications including the 1 R13 projection is a maximum of 40 (35 plus 5), and the cumulative DCPP Unit 2 total number of indications including the 2R13 projection is a maximum of 164 (158 plus 6). For DCPP Unit 1, an additional 7 indications (17 percent of combined historical indications plus 1 R13 new indications) might be observed if the inspection distance were increased from 8 to 12 inches below the TTS. For DCPP Unit 2, an additional 7 indications (4 percent of combined historical indications plus 2R13 new indications) might be observed if the inspection distance were increased from 8 to 12 inches below the TTS. A very small number, if any, of these postulated indications between 8 and 12 inches below the TTS would be expected to represent a 100 percent through-wall condition.

Figures 6 and 7 in Enclosure 1 present a plot of the binned PWSCC elevation data for all DCPP Unit 1 and DCPP Unit 2 historical indications with and without the expansion transition indications. Excluding the expansion transition indications above 1 inch for Unit 1 and above 2 inch for Unit 2 would be expected to provide the best dataset for estimating indications at deeper depths. A best-fit regression of the data with the expansion transition excluded is included in these plots, along with an upper 90 percent probability prediction bound, which suggests that approximately 12 indications would be expected between 8 and 12 inches below the TTS for both DCPP Unit 1 and DCPP Unit 2.

For both units, 12 indications will be applied because it is slightly greater than the previously established value of 7 indications.

Note that this analysis is provided to estimate the number of indications between 8 and 12 inches below the TTS using existing data. For each future outage in which W* ARC is implemented, the data from the just completed inspections will be evaluated in the same manner to more accurately assess the postulated number of undetected indications between 8 and 12 inches below the TTS for both condition monitoring (CM) and operational assessment (OA).

17 PG&E Letter DCL-05-018 4.1.2.5 Considerations for PWSCC Indications Near or Above BWT Axial PWSCC indications that extend above BWT will be evaluated for MSLB leakage as follows. Similar to the current W* ARC methodology, if greater than or equal to 75 percent of the length of the axial indication is below BWT, the indication will be considered as constrained and 100 percent through-wall, and a CM leak rate of 0.168 gpm (95 percent confidence bound leak rate for zero contact pressure, see Figure 1 of Enclosure 5) will be assigned to the indication using the constrained crack model.

If less than 75 percent of the length of the axial indication is below BWT, the indication will be considered as nonconstrained, and will be conservatively treated as free span and evaluated for in situ pressure testing using the screening criteria in the EPRI in situ pressure testing guidelines.

In support of the existing W* criteria and DENTFLO leakage model, PG&E currently verifies that potential taper lengths below BWT are less than 0.7 inches. If the bobbin data indicates a nearly uniform taper greater than 0.7 inches, then the BWT is redefined to be within 0.7 inches of the end of the profile taper.

Only about 5 percent of the DCPP Units 1 and 2 SG tubes exhibit a small taper below BWT. Because the proposed constrained crack leak model does not account for potential taper lengths, the following method change will be made to support evaluation of PWSCC indications with crack tips near the BWT. For tubes with PWSCC indications within 12 inches from the top of tubesheet, if a taper exists below BWT, then BWT will be redefined (lowered) to coincide with the end of the taper. Then the indications will be assessed for MSLB leakage in accordance with the discussion in the previous paragraph.

4.1.3 MSLB Leak Rate Methodology for Degradation Located Below 12 inches from Top of Tubesheet (Severed Tube Model)

As described earlier, in the existing W* ARC method, no leakage is assigned to any type of degradation located below the flexible W* length. The proposed constrained crack model described above assigns leakage to degradation located below the flexible W* length down to 12 inches below the TTS. For any type of degradation located below 12 inches from the TTS, for which detected degradation is allowed to remain in service, another leak rate model was developed assuming complete 360-degree tube severance at 12 inches below the TTS. This model is referred to as the severed tube model. A bounding leak rate of 0.00009 gpm is assigned to each inservice tube to account for 18 PG&E Letter DCL-05-018 potential degradation below 12 inches from the TTS. The severed tube model was previously reviewed and approved by the NRC for Beaver Valley Unit I on October 15, 2004. A description of this model is provided below.

The total anticipated leak rate from indications located below a depth of 12 inches into the tubesheet is based on considering all of the tubes to be severed at that elevation. No leakage would be expected from indications greater than 12 inches below the TTS due to the substantial contact pressure below that depth, e.g., the expected Zone B1 contact pressure at 4200 seconds into the MSLB event is about 3000 psi. However, a conservative estimate of leakage for indications at greater than 12 inches below the TTS can be made by assigning each active tube a leak rate of 8.7-1 0-5 gpm, rounded to 0.00009 gpm, which is derived from Figure 7 of as the upper 90 percent prediction leak rate at 2650 psid for an actual contact depth of 2.28 inches, representative of the 3-inch nominal crevice data.

As mentioned earlier, the drilled hole crevice leak rate test data is provided in Table 6.2-3 of WCAP-14797-P, Revision 2. The drilled hole crevice tests are representative of a tube with a 360-degree through-wall circumferential crack where the ends have been separated, thus bounding any circumferential indication that could be postulated in the tubesheet. Figure 5 in Enclosure 5 lists the average contact pressure for the 1.25-inch, 2-inch, and 3-inch nominal crevice samples (1352 psi, 2020 psi, and 2273 psi, respectively), and shows that the average contact pressure for the 3-inch nominal crevice samples, 2273 psi, is approximately equal to the Zone B1 contact pressure at about 9 inches below the TTS.

The average actual contact length for the 3-inch nominal crevice test specimens is 2.28 inch. This means that the minimum contact pressure for the length of crevice from a depth of 9 to 11.28 inches is greater than the contact pressure of the 3-inch nominal test specimens. The average contact pressure over that length is greater than the test specimens by about 450 psi since contact pressure increases at a rate of about 400 psi per inch of depth in the tubesheet as shown on Figure 5 of Enclosure 5. Therefore, the leak rate for the 3-inch nominal crevice test specimens would be conservative with respect to the leak rate from a tube severed at 12 inches below the TTS.

If all of the approximately 3300 actives tubes in the faulted SG were

• assumed to be severed at a depth of 12 inches into the tubesheet, the calculated MSLB leakage would be on the order of 0.3 gpm.

Zones B2, B3, B4 and A contact pressures as a function of depth 19 PG&E Letter DCL-05-018 below the top of the tubesheet are higher than for Zone B1 to a depth of about 11 inches. Zone A tubes have a positive contact pressure for almost the entire crevice length which is expected to result in a substantially decreased leak rate during a postulated MSLB event.

4.1.4 Impact of Revised MSLB Leak Rate Methodology PG&E has assessed the impact of the revised leak rate methodology on DCPP Units 1 and 2. For each Unit 1 and Unit 2 SG, Table 3 of Enclosure 1 provides the SG projected EOC 13 operational assessment leak rate using the existing W*

leak method (DENTFLO) and the proposed W* leak method. In both models, the measured elevation of the UCT was increased by 0.22 inch, the 95 percent upper bound on the Plus PointTM NDE uncertainty associated with locating the UCT relative to the TTS, and the 95th percentile growth rate is applied to each indication returned to service.

The SG leak rate from each element of the proposed leak method is listed, along with the total leak rate. The constrained crack correlation at a simultaneous 95 percent confidence limit was applied to each DCPP Units 1 and 2 axial PWSCC indication in the flexible W* length, as well as detected axial PWSCC indications and one SG 1-3 volumetric indication between the flexible W* length and 12 inches. The bounding constrained crack leak rate of 0.0028 gpm was applied to projected undetected PWSCC indications between 8 and 12 inches below the TTS. The bounding 360-degree severed tube leak rate of 0.00009 was applied to every inservice tube to account for indications below 12 inches from the TTS.

For Unit 2, the total SG leak rates using the proposed method are a factor of 3 to 6 times higher than the existing method. For Unit 1, the total SG leak rates using the proposed method are a factor of about 12 to 57 times higher than the existing method, much higher than Unit 2 because of the smaller number of W* indications in Unit 1 for which the contributions below the W*

length are a larger fraction of the total leak rate. In any case, the projected EOC 13 MSLB W* leak rates for the worst case Unit 1 and Unit 2 SGs are about 0.5 gpm and 2.1 gpm, respectively, much less than the limit of 10.5 gpm for all ARC and non-ARC leakage sources.

When comparing the constrained crack leak rates to the DENTFLO leak rate for axial PWSCC indications in the flexible W* length, the 20

Enclosure I PG&E Letter DCL-05-018 constrained crack leak rates are 2 to 5 times higher than DENTFLO leak rates, with the exception of SG 1-1. The larger leak rates using the constrained crack model is expected simply because the resistance provided by the tube-to-tubesheet interference fit is neglected.

In SG 1-1, the constrained crack leak rate is less than DENTFLO leak rate and reflects the fact that the constrained crack leak rates are based on contact pressures as a function of the individual tube row and column numbers. The reason for the SG 1-1 difference is due to indication R3C2, which is the only indication in SG I-1 near the BWT and which accounts for 95 percent of the total SG leak rate using DENTFLO. The constrained crack model estimate of the indication R3C2 leak rate is negligible due to its radial position on the periphery and resulting high contact pressures.

4.1.5 In Situ Leak Testing of W* Indications In support of W* leak rate model validation, PG&E Letter DCL-01-095 dated September 13, 2001, defined a four-step sequential screening process for determining the need for in situ leak testing of axial PWSCC indications in the WEXTEX region.

The screening criteria are described below. PG&E's assessment of the axial PWSCC indications detected in each outage with respect to the screening criteria is described in 90-day reports submitted to the NRC.

• Step 1: Prior leak tested W* indications with maximum Plus Point'm coil probe voltages greater than or equal to 1.25 times the prior leak test voltage are carried to Step 2. W* indications with no prior leak test are also carried to Step 2.

Step 2: Indications with maximum the Plus Pointm coil probe voltages exceeding the critical voltage (V, t) are leak tested independent of other parameters. Vrt equals 4.0 volts for nondeplugged indications and 6.0 volts for depluged indications. Indications with maximum Plus Point coil probe voltages less than Vcdt are carried to Step 3.

• Step 3: Indications with maximum Plus PointTM coil probe voltages exceeding Vth, are carried to the Step 4 depth evaluation. A minimum of the 5 largest voltage indications are carried to the depth evaluation if less than 5 indications exceed 21 PG&E Letter DCL-05-018 the voltage threshold. Vthr equals 2.5 volts for nondeplugged indications, and 4.0 volts for deplugged indications.

Step 4 (depth evaluation): Indications with maximum depths exceeding the maximum depth leakage threshold (MDL..th) over lengths greater than the deep crack length threshold (LL-min) are leak tested. MDL.thr equals 80 percent and LL-min equals 0.1 inch.

PG&E proposes to terminate the W* in situ testing program and only in situ test indications that meet the requirements of the EPRI In Situ Guidelines. The W* in situ testing program to validate the WCAP-14797, Revision 1, and WCAP-14797-P, Revision 2, DENTFLO leakage model is no longer needed because a new leakage methodology is proposed that is more conservative than the DENTFLO model.

To date, there have been 21 in situ leak tests of W* indications in the industry: 14 at DCPP Unit 2 (DCPP 2), 1 at Sequoyah Unit 2 (SQN 2), and 6 at Beaver Valley Unit 1 (BVPS 1). The indications are listed in Table 4 of Enclosure 1.

No leakage was observed in any test. A total of 9 industry tests have been conducted on axial PWSCC indications that exceeded the W* in situ screening criteria: 8 at DCPP 2 and 1 at SQN 2.

This is less than the 20-industry in situ tests PG&E previously committed to perform. If there were no leaking W* indications obtained after 20 in situ tests (summed over all plants with WEXTEX expansions), it was intended that PG&E would initiate discussions with the NRC staff to determine if in situ testing should be continued. PG&E initiated discussions with the NRC staff in December 2004 to determine the need for continued in situ testing to support validation of the WCAP-14797 leak rate methodology.

Most of the tested indications were located near the top of tubesheet, just below the BWT, such that the tubesheet provided minimal crevice restriction. Also, several of the tested indications near the top of tubesheet were likely through-wall, and these test results support the evaluations that conclude that leakage from tube indications deeper in the tubesheet would be negligible.

Consistent with termination of the in situ testing, the existing note "In-Situ Testing will be performed in accordance with PG&E Letters DCL 98-148 dated October 22, 1998, and DCL 01-052 dated May 4, 2001, for Cycles 10 and 11 and Letter DCL 01-095 dated 22 PG&E Letter DCL-05-018 September 13, 2001, for Cycles 12 and 13." in TS 5.5.9.b.2.e will be removed.

4.1.6 NRC Reporting Requirements The LAR proposes to retain the existing NRC reporting requirement that PG&E committed to in PG&E Letter DCL-99-01 1: Notify the NRC prior to returning the SGs to service if condition monitoring determines that the upper crack tip of W* indications returned to service do not remain below the TTS by at least the 95 percent confidence NDE uncertainty on locating the crack tip relative to the TTS.

The following existing TS 5.6.10.e reporting requirements will be retained:

Identification of W* tube indications, the W* inspection distance measured with respect to the BWT or TTS (whichever is lower),

the elevation and length of axial indications, and the angle of inclination of clearly skewed axial cracks (if applicable).

The following new TS 5.6.1 0.e reporting requirements have been added, but do not represent a change from current PG&E 90-day reporting practices:

Identification of indications that do not meet W* requirements and were plugged or repaired, total number of indications, the location of the indications (relative to the BWT and TTS), the orientation (axial, circumferential, volumetric, inclined), the severity of each indication (estimated depth), the side of the tube in which the indication initiated (inside or outside diameter), verification that the upper crack tip of W* indications returned to service remain below the TTS by at least the 95 percent confidence NDE uncertainty on locating the crack tip relative to the TTS, updated 95 percent growth rate for use in operational assessment.

The following new TS 5.6.10.e reporting requirements will be added to reflect changes in the leak rate methodology proposed in this LAR, which supersedes the leak rate method in WCAP-14797, Revision 1 and WCAP-14797-P, Revision 2:

The cumulative number of indications detected in the tubesheet region as a function of elevation within the tubesheet, the CM and OA MSLB leak rate for each indication and each SG in accordance with the leak rate methodology described in PG&E Letter DCL-05-018, dated March 11, 2005, and an assessment of whether the results were consistent with expectations and, if not consistent, a description of the proposed corrective action.

23

Enclosure I PG&E Letter DCL-05-018 The revised 90-day TS 5.6.1 O.e reporting requirements for W*

tubes and moving the "continued" on TS pages 5.0-30 and 5.0-30a after the TS title, have no adverse affect on the current TS reporting requirements and provide additional information to the Commission on the results of the inspection of the W* tubes and MSLB leak rate for each detected indication.

4.1.7 WCAP-14797-P Revision 2 WCAP-14797 has been revised from Revision 1 to Revision 2 to incorporate minor corrections, and the TS reference is updated to reflect the latest revision of the WCAP. The TS reference to the WCAP is provided to define the boundaries of Zone A and Zone B. The zone boundaries were not changed in the WCAP revision. WCAP-14797-P, Revision 2 (proprietary), "Generic W*

Tube Plugging Criteria for 51 Series Steam Generator Tubesheet Region WEXTEX Expansions," March 2003, and WCAP-14798-NP, Revision 2 (nonproprietary), "Generic W*

Tube Plugging Criteria for 51 Series Steam Generator Tubesheet Region WEXTEX Expansions," March 2003, was submitted to the NRC by FirstEnergy Nuclear Operating Company in a letter dated June 28, 2004, to support review and approval of a SG tubesheet inspection extent license application. Revision 2 of WCAP-14797 made the following minor corrections from Revision 1: (1) For Table 6.2-3 on pages 6-20 and 6-21, the table title was changed, loss coefficients for all specimens were added, and several corrections were made to loss coefficient, average contact pressure, and leak rates; (2) page 7-9 corrected a typo on growth rate; and (3) page A-12 Table Al shading was added. The change in the reference from WCAP-14797, Revision 1, to WCAP-14797-P, Revision 2, for the definition of the boundaries of Zone A and Zone B has no adverse impact on the current TS 5.5.9.d.1.k.ii W* Length.

WCAP-14797-P, Revision 2, is applicable to DCPP Units 1 and 2. The parameter values used in the W* normal and faulted-condition analysis are bounding for DCPP Units 1 and 2.

PG&E monitors the DCPP steam generator pressure during normal operation to ensure that tfie WCAP-14797-P, Revision 2, normal condition minimum steam pressure analysis value of 760 psia is maintained.

24

Enclosure I PG&E Letter DCL-05-018 4.2 Description of Unchanged W* ARC Requirements 4.2.1 W* Plugging (Repair) Limits All existing TS 5.5.9.d.1.k.v W* plugging (repair) limits are being retained. The repair criteria are listed below.

Resolvable, single axial PWSCC indications detected by rotating pancake coil (RPC) probe within the flexible W* length may be left in service. Such indications shall have the upper crack tip below the BWT by at least the NDE measurement uncertainty (NDEcT.Bwr), and below the TTS by at least the NDE measurement uncertainty (NDEc-ri-s) and the crack growth (CG) allowance, such that at the end of the subsequent operating cycle the entire crack remains below the tubesheet secondary face, where:

NDEcT.BwT (NDE uncertainty on locating the crack tip relative to the BWT) = 0.28 inch for the Plus Point coil probe.

NDEcT-TTs (NDE uncertainty on locating the crack tip relative to the TTS) = 0.22 inch for the Plus Point' coil probe.

CG = 95 percent cumulative probability growth rate.

Inclined axial PWSCC indications within the flexible W* length are subject to the following repair criteria. An inclined indication is defined as an indication that is visually inclined on the RPC C-scan, such that an angular measurement is required, and the measured angle exceeds the measurement uncertainty of NDECA, where NDEcA, (NDE uncertainty on the measurement of the crack angle) is equal to 6.8 degrees for 0.080 pancake.

• Tubes with two or more parallel (overlapping elevation) inclined axial cracks shall be plugged or repaired. There is no limit on the number of parallel axial cracks that are not inclined.

Inclined axial indications less than 2.0 inches long (including the crack growth allowance) having inclination angles relative to the tube axis of less than 45 degrees minus the NDE uncertainty, NDEcA, on the measurement of the crack angle can be left in service. The limit of 2.0 inches for inclined axial indications is conservatively applied to limit the circumferential involvement of the indication. There is no length limit on axial indications that are not inclined.

• Circumferential, volumetric, and axial indications with inclination angles greater than 45 degrees minus NDEcA within the flexible W* length shall be plugged or repaired.

25 PG&E Letter DCL-05-018 RPC indications within the flexible W* length shall be plugged or repaired.

Any tube degradation detected by RPC below the flexible W* length may be left in service.

4.2.2 W* Length and Flexible W* Length All existing requirements for determining the W* length and flexible W* length are retained. The W* length is the distance into the tubesheet below the BWT that precludes tube pullout in the event of a complete circumferential separation of the tube below the W*

length. For nondegraded tubing, the W* length of tubing below the BWT is defined as W* length + NDEw, where:

• W* length (Hot Leg) = 7.0 inch below BWT for W* Zone B (central zone) and 5.2 inch below BWT for W* Zone A (outer zone).

• W* length (Cold Leg) = 7.5 inch below BWT for W* Zone B (central zone) and 5.5 inch below BWT for W* Zone A (outer zone).

NDEw (NDE uncertainty on measuring W* length) = 0.12 inch for the Plus PointTM coil probe.

The flexible W* length is the W* length adjusted for any axial PWSCC cracks found within the W* region. The flexible W*

length is the total RPC inspected length as measured downward from the BWT, and includes NDE uncertainties and crack lengths within W* as adjusted for growth. That is, flexible W* length

= W* length + NDEw+ XCLI + (NCL)(NDEcL) + (NcL)(CG), where:

• XCL, is the total axial length of tubing in which axial cracking is present below BWT and down to the adjusted W* length. For axial cracks that share the same elevation over a portion of their length (e.g., parallel cracks), the contribution to CL from that band of axial cracks is the distance from the uppermost crack within the band to the lowermost crack within the band. CL may include contributions from both parallel cracks and single axial cracks.

• NCL is the number of enveloped groupings of indications (either of single cracks or parallel cracks) as described in CL above.

NDECL (NDE uncertainty associated with the measurement of the length of axial cracks) = negative 0.14 inch for the Plus PointT coil probe 26

Enclosure I PG&E Letter DCL-05-018 CG is the 95 percent crack growth rate in length for each of the NCL crack groups.

4.2.3 Inspection Requirements All existing W* inspection requirements are being retained. Existing W* inspection requirements are listed below. Use of the terminology "RPC" inspection also includes RPC equivalent inspection technology.

The entire flexible W* length (also termed as the W* inspection distance) shall be inspected by RPC every refueling outage.

Because RPC inspections are performed relative to the TTS, and the W* inspection distance is relative to BWT, the required RPC inspection extent is equal to the required flexible W* length below BWT, plus measured distance from BWT to TTS, plus NDEMwr-rrs, where NDEBW-r-TTs (NDE uncertainty on locating BWT relative to TTS) = 0.09 inch for bobbin. In future inspections, PG&E will continue to apply a minimum inspection extent of TTS minus 8 inches to all hot leg inspections, and TTS minus 8.5 inches for cold leg inspections should they be required. These inspection extents provide for allowances between 0.88 inch (for Zone B) and 2.68 to 2.88 inch (for Zone A hot leg and cold leg, respectively) for distance between the TTS and BWT. This is a very conservative specification for most tubes because, based on 100 percent hot leg BWT measurements made at DCPP Unit 2, 95 percent of hot leg BWTs were less than 0.5 inch below the TTS. Every refueling outage, the actual inspection extent is verified to meet or exceed the flexible W* length for degraded tubes. In all cases, the actual inspection extent exceeded the flexible W* length. In addition, in 2R12, the actual inspection extent of every nondegraded hot leg tube was measured and, in all cases, the actual inspection extent exceeded the W* length. The actual average inspection extent in 2R12 was about 10.6 inches below the TTS, much greater than the minimum specified extent.

Indications found by bobbin within the flexible W* length shall be inspected by RPC to characterize crack lengths and elevations.

Indications left in service within the flexible W* length shall be RPC inspected each subsequent outage.

The existing W* ARC does not mandate a specific inspection sample size. In the past, PG&E has followed the EPRI Examination Guidelines, which have required RPC inspection of 27 PG&E Letter DCL-05-018 100 percent of the hot leg top of tubesheet region every refueling outage because PWSCC is an active or potential degradation mechanism in every SG. PG&E will continue to follow the EPRI Examination Guidelines and perform RPC inspection of 100 percent of the hot leg top of tubesheet region every refueling outage.

If a C-3 condition is identified in the hot leg TTS inspection, or if cold leg TTS crack-like RPC indications are detected, PG&E will perform augmented cold leg TTS RPC inspections in accordance with the latest revision of the EPRI Examination Guidelines. For the purposes of classifying the inspection results, tubes with RPC indications that do not meet the W* criteria and are plugged will be counted as defective tubes, and tubes with RPC indications within the flexible W* length that meet the W* criteria will be counted as degraded tubes.

4.2.4 Growth Rate Methodology The existing W* growth rate methods are being retained, and are described below.

The W* ARC growth rate distribution consists of only DCPP Units I and 2 data with back-to-back Plus Pointm coil probe inspections. Following 2R12 inspections in November 2004, the updated W* growth rate distribution consists of 256 Plus PointTM coil probe data points from DCPP Units 1 and 2, with a 95 percent cumulative probability of 0.118 inch per EFPY at 6040F. This DCPP growth distribution is updated every outage with new DCPP data for W* ARC application. If the new growth data and deletion of the oldest cycle of growth data results in a minimum of 200 data points, the oldest cycle of growth data is deleted. This is currently applicable to DCPP Unit 2, which has over 200 growth rate data points. 75 percent of the total length of the axial crack is required to be below BWT in order for the crack growth rate to be included in the leak rate distribution.

The 95 percent growth rate value is used during the inspections to calculate the flexible W* length and to project the location of the upper crack tip at the end of the next cycle to determine the need for repair and to determine the OA MSLB leak rate. As a matter of practicality to support the preliminary OA for startup, the 95 percent growth rate may be the value developed from prior cycle data. If the inspection schedule permits, an updated 95 percent growth rate value incorporating the latest cycle of data may be applied. In any case, the 90-day report will provide the 28 PG&E Letter DCL-05-018 95 percent growth rate developed from the prior cycle data, the updated 95 percent growth rate after incorporating the latest cycle of data, and the final OA using the updated 95 percent growth rate.

4.2.5 Performance Criteria The existing NRC reporting and W* performance criteria are being retained, as follows:

Notify the NRC prior to returning the SGs to service if condition monitoring determines that the upper crack tip of W* indications returned to service do not remain below the TTS by at least the 95 percent confidence NDE uncertainty on locating the crack tip relative to the TTS.

No axial PWSCC indications have been left in service that, in subsequent inspections, failed the W* ARC or had the UCT extend above the TTS (allowing for NDE uncertainty), thereby meeting the performance criteria and validating the slow growth rate of axial PWSCC.

4.3 Non-W* ARC Changes 4.3.1 TS 5.6.10.d.1 Change In TS 5.6.10.d.1, the word "reduced" is replaced with the word "increased." This corrects a typographical error that was introduced by PG&E Letter DCL-99-011, dated January 29, 1999, which supported amendments 151/151 to Operating Licenses DPR-80 and DPR-82 for DCPP Units 1 and 2, respectively. This change is made because the estimated leakage for the voltage-based repair should be increased by the leakage due to other sources to ensure that the total estimated leakage from all sources is compared to the allowable leakage limit from the MSLB dose calculation.

In addition, the words "alternate repair criteria" are changed to usources (alternate repair criteria and non-alternate repair criteria indications) " so that the estimated leakage due to non-alternate repair criteria indications is considered in the total estimated leakage. Since the non-alternate repair criteria indications are a source of leakage, the leakage due to non-alternate repair criteria indications needs to be included in the total estimated leakage.

These changes will ensure that NRC notification will occur if the total estimated leakage due to ARC and non-alternate repair criteria exceeds the allowable leakage limit determined from the licensing basis MSLB dose calculation. It is noted that these changes are 29 PG&E Letter DCL-05-018 consistent with the leakage reporting requirements for PWSCC ARC in TS 5.6.10.g.2 that considers the leakage from all sources (ARC and non-altemate repair criteria indications) for comparison to the leakage limit determined from the licensing basis MSLB dose calculation. PG&E's procedures have correctly interpreted the intent of the TS 5.6.10.d.1 and, therefore, these changes have no adverse effect on the current PG&E reporting procedures for voltage-based repair criteria estimated leakage.

An editorial change is made to TS 5.6.10.d.1 to replace the parentheses before the word "reduced" with a comma and to add a comma before the word uexceeds. " Also, an editorial correction change is made to TS 5.6.10.d.1 to change the word uform" to "from." These editorial changes have no adverse affect on TS 5.6.10.d.l.

4.3.2 TS 5.6.10.d.2 Chanae In TS 5.6.10.d.2, the requirement to notify the NRC prior to returning SGs to service "If circumferential crack-like indications are detected at the tube support plate intersections" is deleted. This notification was originally required pursuant to NRC GL 95-05 for ODSCC ARC implementation, but is no longer necessary because it is redundant to detailed PWSCC ARC criteria for tube support plate circumferential indications that were developed by PG&E and approved by the NRC in the NRC letter to PG&E dated May 1, 2002. PWSCC ARC provides specific criteria for performing: circumferential crack CM and OA, trending analysis of circumferential crack depths, and mixed mode evaluations (see TS 5.6.10.h.7).

4.3.3 TS 5.6.10.d.4 Change In TS 5.6.10.d.4, the requirement to notify the NRC prior to returning SGs to service "If indications are identified at the tube support plate elevations that are attributable to primary water stress corrosion cracking" is deleted. This notification is no longer necessary because it is redundant to detailed PWSCC ARC reporting criteria already contained in TS 5.6.10.h.7. With the deletion of current TS 5.6.1O.d.2 and 5.6.10.d.4, current TS 5.6.10.d.3 is renumbered to TS 5.6.10.d.2 and current TS 5.6.10.d.5 is renumbered to TS 5.6.10.d.3. These editorial changes have no adverse affect on TS 5.6.10.d.

30 PG&E Letter DCL-05-018 4.4 Summary/Conclusion The proposed permanent W* ARC includes a revised MSLB leak rate methodology that results in a more conservative leak rate than the existing W* ARC leak model. For indications above 12 inches from the top of tubesheet, the revised method conservatively ignores the contribution of the crevice restriction for reducing leakage, and assigns 95 percent simultaneous confidence bound leak rate values to indications applying the constrained crack model. A method is also defined to estimate the number of undetected indications between the 8 inch inspection distance and 12 inches below the top of tubesheet, and constrained crack model 95 percent simultaneous confidence bound leak rate values are assigned to these indications. To account for indications below 12 inches from the top of tubesheet, the revised method provides a conservative leak rate assuming every inservice tube is severed at 12 inches from the TTS.

NRC reporting requirements are enhanced to support the new leak rate method. The W* in situ testing program will be terminated since validation of the new leakage methods is not required. Based on the above, structural and leakage integrity of the SG tubes will continue to be maintained in accordance with regulatory requirements with permanent use of the W* ARC.

5.0 REGULATORY ANALYSIS

5.1 No Significant Hazards Consideration PG&E has evaluated whether or not a significant hazards consideration is involved with the proposed amendment by focusing on the three standards set forth in 10 CFR 50.92, "Issuance of amendment," as discussed below:

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

Response: No.

Of the various accidents previously evaluated, the permanent use of the steam generator (SG) tube W star (W*) alternate repair criteria (ARC) only affects the steam generator tube rupture (SGTR) accident evaluation and the postulated main steam line break (MSLB) accident evaluation.

Loss-of-coolant accident (LOCA) conditions cause a compressive axial load to act on the tube. Therefore, since the LOCA tends to force the tube into the tubesheet rather than pull it out, it is not a factor in this evaluation.

For the SGTR accident, the required structural margins of the SG tubes will be maintained by the presence of the tubesheet. Tube rupture is 31 PG&E Letter DCL-05-018 precluded for cracks in the Westinghouse explosive tube expansion (WEXTEX) region due to the constraint provided by the tubesheet.

Therefore, Regulatory Guide (RG) 1.121, "Bases for Plugging Degraded PWR Steam Generator Tubes," margins against burst are maintained for both normal and postulated accident conditions.

WCAP-14797-P, Revision 2, defines a length, W*, of degradation-free expanded tubing that provides the necessary resistance to tube pullout due to the pressure-induced forces (with applicable safety factors applied).

The W* length supplies the necessary resistive force to preclude pullout loads under both normal operating and accident conditions. The contact pressure results from the WEXTEX expansion process, thermal expansion mismatch between the tube and tubesheet and from the differential pressure between the primary and secondary side as offset at higher tubesheet elevations by bow of the tubesheet. The proposed changes do not affect other systems, structures, components, or operational features.

Therefore, the proposed change results in no significant increase in the probability of the occurrence of an SGTR or MSLB accident.

The consequences of an SGTR accident are affected by the primary-to-secondary leakage flow during the accident. Primary-to-secondary leakage flow through a postulated broken tube is not affected by the proposed changes since the tubesheet enhances the tube integrity in the region of the WEXTEX expansion by precluding tube deformation beyond its initial expanded outside diameter. The resistance to both tube rupture and collapse is strengthened by the tubesheet in that region. At normal operating pressures, leakage from primary water stress corrosion cracking in the W* length is limited by both the tube-to-tubesheet crevice and the limited crack opening permitted by the tubesheet constraint. No leakage has been observed in any in situ test of W* indications to date.

Consequently, negligible normal operating leakage is expected from cracks within the tubesheet region.

MSLB leakage is limited by leakage flow restrictions resulting from the crack and tubesheet that provide a restricted leakage path and also limit the degree of crack face opening compared to free span indications. The total leakage, that is, the combined leakage for all such tubes, plus the combined leakage developed by any other ARC and non-ARC degradation, is limited to less than the maximum allowable MSLB accident dose analysis leak rate limit, such that offsite dose is maintained less than the guideline value in Title 10 to the Code of Federal Regulations (10 CFR) Part 100 and control room dose is maintained less than the value in General Design Criterion (GDC) 19 of Appendix A to 10 CFR Part 50. In addition, the editorial changes made to Technical Specifications 5.5.9 and 5.6.10 have no impact on the MSLB leakage.

32 PG&E Letter DCL-05-018 Therefore, the proposed change does not involve a significant increase in the probability or consequences of an accident previously evaluated.

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

Response: No.

The proposed changes do not introduce any changes or mechanisms that create the possibility of a new or different kind of accident. Tube bundle integrity is expected to be maintained for all plant conditions upon continued implementation of the W* ARC.

Axial indications left in service shall have the upper crack tip below the top of the tubesheet (TTS) by at least the value of the nondestructive examination (NDE) uncertainty and crack growth allowance, such that at the end of the subsequent operating cycle the entire crack remains below the tubesheet secondary face, thereby minimizing the potential for free span cracking and demonstrating that an acceptable level of risk is maintained for tubes returned to service under W* ARC. This repair criterion is in addition to ensuring that the upper crack tip is located below the bottom of the WEXTEX transition by at least the NDE measurement uncertainty. Condition monitoring will verify that all tube cracks returned to service under W* ARC remain below the TTS, including an allowance for NDE uncertainty.

These changes do not introduce any new equipment or any change to existing equipment. No new effects on existing equipment are created nor are any new malfunctions introduced.

Therefore, the proposed change does not create the possibility of a new or different 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. RG 1.121 is used as the basis in the development of the W* ARC for determining that SG tube integrity considerations are maintained within acceptable limits. RG 1.121 describes a method acceptable to the NRC staff for meeting General Design Criteria 14,15, 31, and 32 by reducing the probability and consequences of an SGTR. RG 1.121 concludes that by determining the limiting safe conditions of tube wall degradation beyond which tubes with 33 PG&E Letter DCL-05-018 unacceptable cracking, as established by inservice inspection, should be removed from service or repaired, 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 ASME Code.

For primarily axially oriented cracking located within the tubesheet, tube-burst is precluded due to the presence of the tubesheet. WCAP-14797-P, Revision 2, defines a length, W*, 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 W* ARC will preclude unacceptable primary-to-secondary leakage during all plant conditions. The methodology for determining MSLB leakage due to indications within the tubesheet region provides for large margins between calculated and actual leakage values. In addition, the total leakage, including leakage due to use of other ARC, is maintained below the maximum allowable MSLB accident dose analysis leak rate limit, such that offsite dose is maintained less than the guideline value in 10 CFR Part 100 and control room dose is maintained less than the value in GDC 19. In addition, the editorial changes made to Technical Specifications 5.5.9 and 5.6.10 have no impact on the determination of MSLB leakage.

Plugging of the SG tubes reduces the reactor coolant flow margin for core cooling. Continued implementation of W* ARC will result in maintaining the margin of flow that may have otherwise been reduced by tube plugging.

Therefore, the proposed change does not involve a significant reduction in a margin of safety.

Based on the above evaluation, PG&E concludes that the proposed change presents no significant hazards consideration under the standards set forth in 10 CFR 50.92(c), and accordingly, a finding of "no significant hazards consideration" is justified.

5.2 Applicable Regulatory Requirements/Criteria GDC 14 of Appendix A to 10 CFR 50, uReactor Coolant Pressure Boundary," contains requirements applicable to SG tubes since they are part of the reactor coolant pressure boundary. GDC 14 requires that the reactor coolant pressure boundary be designed, fabricated, erected, and tested in order to have an extremely low probability of abnormal leakage, of rapidly propagating failure, and of gross failure.

RG 1.121 provides guidance for determining the minimum wall thickness at which a SG tube should be plugged. The RG 1.121 performance 34 PG&E Letter DCL-05-018 criteria recommend that the margin of safety against SGTR under normal operating conditions should not be less than 3 at any tube location where defects have been detected. The margin of safety against tube failures under postulated accident conditions should be consistent with the margin of safety determined by the stress limits specified in Section III of the ASME Boiler and Pressure Vessel Code. Analyses have been performed as described in WCAP-14797, Revision 2, to ensure the RG 1.121 requirements continue to be met for the W* ARC.

10 CFR Part 100 provides the basis for the limits for tube leakage integrity for offsite radiological consequences and GDC 19 provides the bases for the limits for tube leakage integrity for control room radiological consequences. The tubes left in service under the W* ARC will continue to meet the leakage integrity limits required to meet the 10 CFR 100 and GDC 10 requirements. The postaccident leakage will be calculated for all indications left in service under all ARC, including the W* ARC, and limited to ensure the 10 CFR 100 and GDC 19 limits are met.

RG 1.83 provides requirements for periodic inservice inspection of the SG tubing. Continued implementation of the W* ARC does not adversely impact the inservice inspection of the SG tubes as required by RG 1.83.

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

6.0 ENVIRONMENTAL CONSIDERATION

PG&E has evaluated the proposed amendment and has determined that 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 10 CFR 51.22(c)(9). Therefore, pursuant to 10 CFR 51.22(b), no environmental impact statement or environmental assessment need be prepared in connection with the proposed amendment.

35 PG&E Letter DCL-05-018

7.0 REFERENCES

7.1 References

1.

NRC letter to PG&E, "Issuance of Amendments for Diablo Canyon Nuclear Power Plant, Unit No. 1 (TAC No. M98283) and Unit No. 2 (TAC No. M98284)," dated February 19,1999.

2.

NRC letter to PG&E, "Correction to Amendment No. 129 to Facility Operating License No. DPR-80 (TAC No. M98283) and Amendment No. 127 to Facility Operating License No. DPR-82 (TAC No. M98284)," dated June 4, 1999.

3.

PG&E letter to NRC, DCL-97-038, "License Amendment Request 97-04, Steam Generator Tube Alternate Repair Criteria for Indications in the Westinghouse Explosive Tube Expansion (WEXTEX) Region," dated March 10, 1997.

4.

PG&E letter to NRC, DCL-97-095, "Transmittal of Errata Sheets for WCAP-14797 and WCAP-14798," dated May 20,1997.

5.

NRC letter to PG&E, "Request for Additional Information -

Proposed W* Steam Generator Tube Repair Criteria (TAC Nos.

M98283 and M98284)," dated January 6, 1998.

6.

PG&E letter to NRC, DCL-98-039, 'Response to Request for Additional Information, License Amendment Request 97-04," dated March 13, 1998.

7.

NRC letter to PG&E, "Request for Additional Information -

Proposed W* Steam Generator Tube Repair Criteria (TAC Nos.

M98283 and M98284)," dated June 23, 1998.

8.

PG&E letter to NRC, DCL-98-119, "Response to NRC Request for Additional Information, Dated June 23, 1998, Regarding Proposed W* Steam Generator.Tube Repair Criteria," dated August 28, 1998.

9.

NRC letter to PG&E, "Request for Additional Information Regarding Proposed W* Steam Generator Tube Alternate Repair Criteria for Diablo Canyon Power Plant, Units 1 and 2 (TAC Nos. M98283 and M98284)," dated August 6, 1998.

10. PG&E letter to NRC, DCL-98-148, "Response to NRC Request for Additional Information, Dated August 6, 1998, Regarding Proposed W* Steam Generator Tube Repair Criteria," dated October 22, 1998.

11. NRC letter to PG&E, "Request for Additional Information -

Proposed W* Steam Generator Tube Repair Criteria (TAC Nos.

M98283 and M98284)," dated January 29, 1999.

12. PG&E letter to NRC, DCL-99-011, "Response to NRC Request for Additional Information, Dated January 29, 1999, Regarding Proposed W* Steam Generator Tube Repair Criteria," dated January 29, 1999.

36 PG&E Letter DCL-05-018

13. PG&E letter to NRC, DCL-99-015, "Submittal of Supplementary Technical Specification Page Regarding Proposed W* Steam Generator Tube Repair Criteria," dated February 2, 1999.

14. PG&E letter to NRC, DCL-01-052, "2R10 Threshold Screening Values for W* In situ Leak Testing," dated May 4, 2001.

15. NRC letter to PG&E, 'Diablo Canyon Nuclear Power Plant, unit Nos. 1 and 2 - Issuance of Amendment RE: Renewal of Steam Generator Tube W* Alternate Repair Criteria (TAC Nos. MB2983 and MB2985)," dated April 29, 2002.

16. PG&E letter to NRC, DCL-01-095, "License Amendment Request 01-03, Extension of Steam Generator Tube W* Alternate Repair Criteria for Indications in the Westinghouse Explosive Tube Expansion (WEXTEX) Region," dated September 13, 2001.

17. PG&E letter to NRC, DCL-02-027, 'Response to NRC Request for Additional Information Regarding License Amendment Request 01-03, 'Extension of Steam Generator Tube W* Alternate Repair Criteria for Indications in the Westinghouse Explosive Tube Expansion (WEXTEX) Region'", dated March 14,2002.

18. WCAP-14797, Revision 1 (proprietary), uGeneric W* Tube Plugging Criteria for 51 Series Steam Generator Tubesheet Region WEXTEX Expansions," February 1997.

19. WCAP-1 4798, Revision 1 (nonproprietary), "Generic W* Tube Plugging Criteria for 51 Series Steam Generator Tubesheet Region WEXTEX Expansions," February 1997.

20. WCAP-14797-P, Revision 2 (proprietary), "Generic W* Tube Plugging Criteria for 51 Series Steam Generator Tubesheet Region WEXTEX Expansions," March 2003.

21. WCAP-14798-NP, Revision 2 (nonproprietary), "Generic W* Tube Plugging Criteria for 51 Series Steam Generator Tubesheet Region WEXTEX Expansions," March 2003.

22. PG&E letter to NRC, DCL-01-016, 'Supplement 2 to License Amendment Request 00-06, "Alternate Repair Criteria for Axial PWSCC at Dented Intersections in Steam Generator Tubing,"

dated February 20, 2001.

23. PG&E letter to NRC, DCL-99-076, "Special Report 99 90 Day Report, Results of Steam Generator Alternate Repair Criteria for Diablo Canyon Power Plant Unit 1 Ninth Refueling Outage," dated June 8,1999.

24. PG&E letter to NRC, DCL-00-008, "Special Report 00 90 Day Report, Results of Steam Generator Alternate Repair Criteria for Diablo Canyon Power Plant Unit 2 Ninth Refueling Outage," dated January 20, 2000.

25. PG&E letter to NRC, DCL-01-010, "Special Report 00 Results of Steam Generator Alternate Repair Criteria for Diablo Canyon Power Plant Unit 1 Tenth Refueling Outage," dated February 5, 2001.

37 PG&E Letter DCL-05-018

26. PG&E letter to NRC, DCL-01-086, "Special Report 01 90-Day Report, Results of Steam Generator Alternate Repair Criteria for Diablo Canyon Power Plant Unit 2 Tenth Refueling Outage," dated August 21, 2001.

27. PG&E letter to NRC, DCL-02-098, 'Special Report 02 Results of Steam Generator Inspections for Diablo Canyon Power Plant Unit 1 Eleventh Refueling Outage," dated August 22, 2002.

28. PG&E letter to NRC, DCL-03-076, "Special Report 03 Results of Steam Generator Inspections for Diablo Canyon Power Plant Unit 2 Eleventh Refueling Outage," dated June 23, 2003.

29. PG&E letter to NRC, DCL-04-112, "Special Report 04 Results of Steam Generator Inspections for Diablo Canyon Power Plant Unit 1 Twelfth Refueling Outage," dated September 7, 2004.

30. Regulatory Guide 1.83, ulnservice Inspection of Pressurized Water Reactor Steam Generator Tubes," Revision 1.

31. Regulatory Guide 1.121, "Bases for Plugging Degraded PWR Steam Generator Tubes".

32. FirstEnergy Nuclear Operating Company letter to NRC, L-04-089, "Beaver Valley Power Station, Unit No. 1, Docket No. 50-334, License No. DPR-66, License Amendment Request No. 328, Revised Steam Generator Inspection Scope for One Cycle of Operation,"

dated June 28, 2004

33. NRC letter to FirstEnergy Nuclear Operating Company, "Beaver Valley Power Station, Unit No. 1 (BVPS-1) - Issuance of Amendment RE: Revised Steam Generator Inspection Scope for One Cycle of Operation (TAC No. MC3671)," dated October 15, 2004.

34. TVA letter to NRC, 1VA-SQN-TS-02-06, 'Sequoyah Nuclear Plant (SQN) - Unit 2 - Technical Specifications (TS) Change 03 --Change Inspection Scope for Steam Generator (SG) Tubes," dated December 2, 2004.

7.2 Precedent DCPP Units 1 and 2 currently have W* ARC that are applicable for Cycles 10, 11, 12, and 13. The NRC issued the W* ARC for Cycles 12 and 13 in license amendment No. 151 to DCPP Unit 1 Operating License DPR-80 and license amendment No. 151 to DCPP Unit 2 Operating License DPR-82 to PG&E by a letter dated April 29, 2002.

DCPP Units 1 and 2 originally had a W* ARC in TS 5.5.9 which was applicable for Cycles 10 and 11. The NRC issued the original W* ARC in license amendment No. 129 to DCPP Unit 1 Operating License DPR-80 and license amendment No. 127 to DCPP Unit 2 Operating License DPR-82 to PG&E by letters dated February 19, 1999, and June 4,1999. LAR 97-04 for the W* ARC was contained in 38

Enclosure I PG&E Letter DCL-05-018 PG&E Letter DCL-97-038 dated March 10,1997. PG&E Letter DCL-97-038 also transmitted Westinghouse WCAP-14797, Revision 1 (proprietary), and WCAP-14798, Revision 1 (nonproprietary), which provide the technical basis for the W* ARC. An error correction to page A-12 of WCAP-14797, Revision 1, and WCAP-14798, Revision 1 was provided in PG&E Letter DCL-97-038, dated March 10,1997.

Responses to NRC requests for additional information on LAR 97-04 dated January 6, 1998, June 23, 1998, August 6, 1998, and January 29, 1999, were provided in PG&E Letters DCL-98-039, dated March 13, 1998, DCL-98-119, dated August 28, 1998, DCL-98-148, dated October 22, 1998, and DCL-99-011, dated January 29, 1999, respectively. Supplementary TS pages for LAR 97-04 were provided in PG&E Letter DCL-99-015, dated February 2,1999. Revised in situ testing screening values for 2R10 were provided in PG&E Letter DCL-01-052 dated May 4, 2001.

FirstEnergy Nuclear Operating Company's Beaver Valley Unit 1 obtained NRC approval to limit the tubesheet inspection extent in a license amendment (No. 262 for DPR-66) by the NRC letter dated October 15, 2004, based on the FirstEnergy Nuclear Operating Company LAR contained in a letter dated June 28,:2004 and a response to an NRC request for additional information contained in a "DCL-04-110, Response to August 30. 2004, NRC Request for Additional Information Regarding License Amendment Request 03-18, Revision to Technical Specifications 5.5.9, Steam Generator (SG) Tube Surveillance Program, and 5.6.10. [[system" contains a listed "[" character as part of the property label and has therefore been classified as invalid. (SG) Tu|letter dated September 3, 2004]]. The FirstEnergy Nuclear Operating Company letter dated June 28, 2004, submitted WCAP-14797-P, Revision 2 (proprietary), "Generic W* Tube Plugging Criteria for 51 Series Steam Generator Tubesheet Region WEXTEX Expansions,"

March 2003, and WCAP-14798-NP, Revision 2 (nonproprietary),

'Generic W* Tube Plugging Criteria for 51 Series Steam Generator Tubesheet Region WEXTEX Expansions," March 2003, to the NRC to support review and approval of their license application. The license amendment approved the use of a bounding leak rate model (severed tube model) assuming all tubes are severed at 12 inches below the top of tubesheet.

39 PG&E Letter DCL-05-018 Table 1 - Hot Leg Tubesheet Inspection Scope and New PWSCC Indications per Outage DCPP Unit 1 Number Indications Outage EFPY Inspection extent Inspection sample Probe

_(inch)

(percent) 2 1R6 7.1

-5 22 RPC 3

1R7 8.5

-5 30 Plus Pointfm 6

1R8 9.8

-3 45 Plus PointTm 11 1R9 11.4

-8 100 Plus PointTm 4

1R10 12.9

-8 100 Plus PointTm 6

1R11 14.3

-8 100 Plus Pointm 3

1R12 15.9

-8.5 100 Plus PointTm DCPP Unit 2 Number Indications Outage EFPY Inspection extent Inspection sample Probe (inch)

(percent) 28 2R5 5.7

-5 41 RPC 13 2R6 7.1

-5 30 RPC 43 2R7 8.4

-3 56 Plus PointTm 30 2R8 10.0

-3.5 100 Plus PointTm 28 2R9 11.5

-8 100 Plus PointTm 4

2R10 12.9

-8 100 Plus PointTm 9

2R11 14.6

-8.5 100 Plus Pointm 3

2R12 16.1

-8.5 100 Plus PointTM Table 2 - Distribution of PWSCC Indications Distance (inch)

DCPP Unit 1 DCPP Unit 2 relative to TTS Total pre-W*

post-W*

Total pre-W*

post-W*

1 0

0 0

2 2

0 0

13 6

7 68 55 13

-1 5

3 2

53 41 12

-2 6

1 5

19 12 7

-3 2

1 1

5 2

3

-4 0

0 0

4 1

3

-5 1

0 1

0 0

0

-6 2

0 2

2 0

2

-7 0

0 0

1 0

1

-8 4

0 4

0 0

0

-9 2

0 2

0 0

0

-10 0

0 0

2 0

2

-11 0

0 0

2 1

1 Total 35 11 24

158, 114 44 40 PG&E Letter DCL-05-018 Table 3 EOC 13 Projected Operational Assessment Leak Rates (gpm at Room Temperature) - Comparison of Existing W* Leak Model and Proposed W*

Leak Model Constrained Severed Existing Crack Leak Constrained Tube W* Leak Constrained Model for Crack Leak Model Method for Crack Leak Detected Axial, Model for Assuming Total Detected Model for Circumferential, Non-360 Constrained SG Axial Detected Volumetric detected 6 reeCrack and PWSCC Axial Indications Indications Tube Severed Indications Indications between Between 8 Severance TMuobdels in Flexible in Flexible Flexible W*

and 12 at 12 Mdl W* Length W* Length Length and inches inches TTS - 12 Below TTS Below TTS inches 11 0.028 0.006 0.004 0.034 0.288 0.331 12 0.042 0.196 0.002 0.034 0.280 0.512 13 0.030 0.059 0.002 0.034 0.298 0.393 14 0.006 0.016 0.004 0.034 0.290 0.343 21 0.289 1.519 0.001 0.034 0.294 1.848 22 0.140 0.586 NA 0.034 0.283 0.902 23 0.604 1.779 NA, 0.034 0.294 2.106 24 0.484 1.402 0.002 0.034 0.275 1.713 41 PG&E Letter DCL-05-018 Table 4 Industry In situ Test Results for Axial PWSCC in WEXTEX Region through 2004 Crack Approx Y

Distance Crack Max Length Exceeded In situ S

Crack Deplug Year Below Peak Length,

Depth,

> 80 W

Test Leak Tube Plant G R C number Tube In situ BWT or Volt (inch)

(percent) percent, Threshold Pressure Rate Plugged Tested TTS, (inch)

(3)

(2)

(inch)

Values (gpm)

_(1)

(3)

DCPP 2 1 3 59 1

Yes 1999 0.23 5.58 0.49 100%

0.23 Yes NOP 0

No DCPP 2 1 3 59 1

Yes 2004 0.03 7.13 0.86 100%

0.71 Yes 3dpNO 0

Yes DCPP 2 1 7 62 1

Yes 1999 0.31 4.17 0.49 80%

None Yes NOP 0

No DCPP 2 2 31 25 1

Yes 1999 0.70 3.99 0.47 70%

None Yes NOP 0

No DCPP 2 3 7 52 1

Yes 2001 0.28 3.9 0.55 94%

0.37 Yes NOP 0

No DCPP 2 4 3 5 1

Yes 2001 0.27 1.51 0.72 100%

0.63 No NOP 0

No DCPP 2 4 2 29 1

Yes 2001 2.88 4.45 0.95 100%

0.84 Yes NOP 0

No DCPP 2 4 2 29 2

Yes 2001 1.20 0.94 0.26 100%

0.10 No NOP 0

No DCPP 2 4 2 29 1

Yes 2003 3.04 5.25 0.97 100%

0.97 No dpSLB 0

Yes DCPP 2 4 2 29 2

Yes 2003 1.21 1.22 0.64 97%

0.12 No dpSLB 0

Yes DCPP 2 4 16 10 1

No 2004 1.19 2.76 0.54 77%

None No NOP 0

No DCPP 2 4 24 26 1

No 2004 0.89 2.66 0.54 100%

0.21 Yes NOP 0

No DCPP 2 4 24 26 2

No 2004 0.66 0.73 0.16 58%

None No NOP 0

No DCPP 2 4 13 40 1

Yes 2004 0.86 2.57 0.52 90%

0.25 Yes NOP 0

No SQN 2 4 7 17 1

No 1997 0.15 3.6 0.32 100%

0.02 Yes 3dpNO 0

Yes BVPS 1 A 19 51 1

No 1997 0.24 0.7 0.3 77%

None No 3dpNO 0

Yes BVPS 1 A 27 28 1

No 1997 3.20 1.2 0.22 35%

None No 3dpNO 0

Yes BVPS 1 B 5 83 1

No 1997 0.35

• 1.5 0.21 30%

None No 3dpNO 0

Yes BVPS 1 C 27 31 1

No 1997 0.60 0.9 0.18 44%

None No 3dpNO (4)

Yes BVPS 1 A 7 59 1

No 2001 1.86 1.98 NA 33%

None No dpSLB 0

Yes BVPS 1 B 35 22 1

No 2001 1.51 1.3 NA 50%

None No dpSLB 0

Yes Notes

1)

For DCPP data, distances are upper crack tip to BWT, including NDE uncertainty. For other plants, distances are crack to TTS.

2)

For DCPP data, maximum depths are adjusted per PWSCC ARC methods.

3)

For DCPP data, cracks lengths are adjusted per PWSCC ARC methods.

4)

In situ pressure testing tooling system leakage. No leakage judged to be due to flaw.

42

DCPP Units 1 and 2 Tu 50 -

45 -

40 -

135 -

cm o 30 C 25-10 20 --

5 10 _

5-0 PG&E Letter DCL-05-018 Figure 1 besheet PWSCC Trending by Outage l *U2 Data 3 U1 Data 8

9 10 11 12 Refueling Outage 43 CoI 5

6 7

PG&E Letter DCL-05-018 Figure 2 DCPP Units 1 and 2 PWSCC Circ and Axial Indications in WEXTEX Region, including Pre-W* and Post-W* Comparison Data through 1R12 and 2R12 I -AIl Data Pre We (minus 3 to 5 inch)

Post W* (minus 8 to 8.5 inch)

I 100%

anoAl A_2:

.0a.

e E

80%-

/

70% -

/'

60%

50%

/

17 40%-

/

/

30%

/

/

20%

10%

n%

,M v {9

-12

-11

-10

-9

-8

-7

-6

-5

-4

-3

-2

-1 0

1 Indication distance below TTS (inch) 44 PG&E Letter DCL-05-018 Figure 3 DCPP Units I and 2 PWSCC Circ and Axial Indications in WEXTEX Region Data through 1R12 and 2R12 All Unit 2 Data All Unit 1 Data 100%

90%

r 80% -

70% -

X 60% -

L 50%

E 40%

30%

20% -

10%

/

0% *

-12

-11

-10

-9

-8

-7

-6

-5

-4

-3

-2

-1 0

Indication distance below TTS (inch) 45 PG&E Letter DCL-05-018 Figure 4 DCPP I Cumulative Tubesheet Region PWSCC Trending by EFPY All Data 0

Post-W* Outages - - - 1R13 -Linear (Post-W* Outages) 45 40 35 CDaIv 3.001x-12.049 xl

r. 30

-0 t2 15 100

-20f = <

15 0

2 4

6 8

10 12 14 16 18 20 EFPY Cost I

46 PG&E Letter DCL-05-018 Figure 5 DCPP 2 Cumulative Tubesheet Region PWSCC Trending by EFPY All Data a

Post-W Outages -

2R13 -

Linear (Post-W* Outages) 180-160 Y= 3.Max + 99.64 140

,,120 0

10 2

46

_1_1 1

1 1_2 100

~80 75 E

60 1-40*

20 0

2 4

6 8

10 12 14 16 18 20 EFPY 47 PG&E Letter DCL-05-018 Figure 6 DCPP Unit 1 Tubesheet PWSCC Elevation vs. Number of Indications 30 25 20 ci 00 r.

c~ 15 z

10 5

0 60 50 40 X r.0

-C)-

20 U 10 0

0 1

2 3

4 5

6 7

8 9

10 11 12 Distance below TTS (inch) 48 COG PG&E Letter DCL-05-018 Figure 7 DCPP Unit 2 Tubesheet PWSCC Elevation vs Number of Indications 60 50 40 a)

CZ Z430 c)

S 20 10 0

90 80 70 60 o r.0a 50 '

0 40 -

E 30 0 20 10 0

Go?

0 1

2 3

4 5

6 7

8 9

10 11 12 Distance below TTS (inch) 49 PG&E Letter DCL-05-018 Proposed Technical Specification Changes (mark-up)

Programs and Manuals 5.5 5.5 Programs and Manuals (continued) 5.5.9 Steam Generator (SG) Tube Surveillance Program SG tube integrity shall be demonstrated by performance of the following augmented inservice inspection program.

The provisions of SR 3.0.2 are applicable to the SG Tube Surveillance Program test frequencies.

a.

SG Sample Selection and Inspection - SG tube integrity shall be determined during shutdown by selecting and inspecting at least the minimum number of SGs specified in Table 5.5.9-1.

b.

SG Tube Sample Selection and Inspection - The SG tube minimum sample size, inspection result classification, and the corresponding action required shall be as specified in Table 5.5.9-2. The inservice inspection of SG tubes shall be performed at the frequencies specified in Specification 5.5.9.c and the inspected tubes shall be verified acceptable per the acceptance criteria of Specification 5.5.9.d. The tubes selected for each inservice inspection shall include at least 3%

of the total number of tubes in all SGs; the tubes selected for these inspections shall be selected on a random basis except:

1.

Where experience in similar plants with similar water chemistry indicates critical areas to be inspected, then at least 50% of the tubes inspected shall be from these critical areas;

2.

The first sample of tubes selected for each inservice inspection (subsequent to the preservice inspection) of each SG shall include:

a)

All nonplugged tubes that previously had detectable wall penetrations (greater than 20%),

b)

Tubes in those areas where experience has indicated potential

problems, c)

A tube inspection (pursuant to Specification 5.5.9.d.' 1.h) shall be performed on each selected tube. If any selected tube does not permit the passage of the eddy current probe for a tube inspection, this shall be recorded and an adjacent tube shall be selected and subjected to a tube inspection, d)

Indications left in service as a result of application of the tube support plate voltage-based repair criteria shall be inspected by bobbin coil probe during all future refueling outages l

e)

Tubes identified as W* tubes having a previously identified Li indication within the W* length shall be inspected using a rotating pancake coil (RPC) probe for the full len th of the W* region during all future refueling ou tagese

--- _(continued)

• Applicable for Units I and 2, Cycles 10, 11, 12, and 13 only

• • In-Situ Testing will be performed in accordance with PG&E letters DCL 98-148 dated October 22, 1998, and DCL 01-052 dated May 4, 2001, for Cycles 10 and 11 and letter DCL 01-095 dated VSeptember 13, 2001, for Cycles 12 and 13.

DIABLO CANYON - UNITS 1 & 2 5.0-10 Unit 1 - Amendment No. 435, 454, TAB5.doc - R12 1

Unit 2 - Amendment No. 435,454,

Programs and Manuals Note: There are no Changes on this Page. Page included for Information Only 5.5 Programs and Manuals 5.5.9 Steam Generator (SG) Tube Surveillance Program (continued)

3.

The tubes selected as the second and third samples (if required by Table 5.5.9-2) during each inservice inspection may be subjected to a partial tube inspection provided:

a)

The tubes selected for these samples include the tubes from those areas of the tube sheet array where tubes with imperfections were previously found, and b)

The inspections include those portions of the tubes where imperfections were previously found.

4.

Implementation of the steam generator tube/tube support plate repair criteria requires a 100% bobbin coil inspection for hot-leg and cold-leg support plate intersections down to the lowest cold-leg tube support plate with known outside diameter stress corrosion cracking (ODSCC) indications. The determination of the lowest cold-leg tube support plate intersection having ODSCC indications shall be based on the performance of at least a 20% random sampling of tubes inspected over their full length.

5.

Inspection of dented tube support plate intersections will be performed in accordance with WCAP-15573, Revision 1, to implement axial primary water stress corrosion cracking (PWSCC) depth-based repair criteria. The extent of required inspection is:

a) 100 percent bobbin coil inspection of all tube support plate (TSP) intersections.

b)

Plus Point coil inspection of all bobbin coil indications at dented TSP intersections.

c)

Plus Point coil inspection of all prior PWSCC indications left in service.

d)

If bobbin coil is relied upon for detection of axial PWSCC in less than or equal to 2 volt dents, then on a SG basis perform Plus Point coil inspection of all TSP intersections having greater than 2 volt dents up to the highest TSP for which PWSCC has been detected in the prior two inspections or current inspection and 20%

of greater than 2 volt dents at the next higher TSP. If a circumferential indication is detected in a dent of ax" volts in the prior two inspections or current inspection, Plus Point inspections will be conducted on 100% of dents greater than "x - 0.3" volts up to the affected TSP elevation in the affected SG, plus 20% of dents greater than ax - 0.3" volts at the next higher TSP. ax" is defined as the lowest dent voltage where a circumferential crack was detected.

(continued)

DIABLO CANYON - UNITS I & 2 5.0-11 Unit 1 - Amendment No. 435, 152 TAB5.doc - R12 2

Unit 2 - Amendment No. 435, 152

Programs and Manuals 5.5 Note: There are no Changes on this Page. Page included for Information Only 5.5 Programs and Manuals 5.5.9 Steam Generator (SG) Tube Surveillance Program (continued) e)

If bobbin coil is not relied upon for detection of axial PWSCC in less than or equal to 2 volt dents, then on a SG basis perform Plus Point coil inspection of all dented TSP intersections (no lower dent voltage threshold) up to the highest TSP for which PWSCC has been detected in the prior two inspections or current inspection and 20% of all dents at the next higher TSP.

f)

For any 20% dent sample, a minimum of 50 dents at the TSP elevation shall be inspected. If the population of dents is less than 50 at the TSP elevation, then 100% of the dents at the TSP elevation shall be inspected.

The results of each sample inspection shall be classified into one of the following three categories:

Category Inspection Results C-1 Less than 5% of the total tubes inspected are degraded tubes and none of the inspected tubes are defective.

C-2 One or more tubes, but not more than 1 % of the total tubes inspected are defective, or between 5% and 10% of the total tubes inspected are degraded tubes.

C-3 More than 10% of the total tubes inspected are degraded tubes or more than 1% of the inspected tubes are defective.

Note: In all inspections, previously degraded tubes must exhibit significant (greater than 10%) further wall penetrations to be included in the above percentage calculations.

c.

Inspection Frequencies - The above required inservice inspections of SG tubes shall be performed at the following frequencies:

1.

The first inservice inspection shall be performed after 6 Effective Full Power Months but within 24 calendar months of initial criticality.

Subsequent inservice inspections shall be performed at intervals of not less than 12 nor more than 24 calendar months after the previous inspection. If two consecutive inspections not including the preservice inspection, result in all inspection results falling into the C-1 category or if two consecutive inspections demonstrate that previously observed degradation has not continued and no additional degradation has occurred, the inspection interval may be extended to a maximum of once per 40 months; (continued)

DIABLO CANYON - UNITS 1 & 2 5.0-11a Unit 1 - Amendment No. 435,152 TAB5.doc - R12 3

Unit 2 - Amendment No. 435,152

Programs and Manuals Note: There are no Changes on this Page. Page included for Information Only 5.5 Programs and Manuals 5.5.9 Steam Generator (SG) Tube Surveillance Program (continued)

2.

If the results of the inservice inspection of a SG conducted in accordance with Table 5.5.9-2 at 40 month intervals fall in Category C-3, the inspection frequency shall be increased to at least once per 20 months. The increase in inspection frequency shall apply until the subsequent inspections satisfy the criteria of Specification 5.5.9.c.1. The interval may then be extended to a maximum of once per 40 months; and

3.

Additional, unscheduled inservice inspections shall be performed on each SG in accordance with the first sample inspection specified in Table 5.5.9-2 during the shutdown subsequent to any of the following conditions:

a)

Reactor-to-secondary tube leaks (not including leaks originating from tube-to-tube sheet welds) in excess of the limits of Specification 3.4.13; or b)

A seismic occurrence greater than the Double Design Earthquake, or c)

A loss-of-coolant accident requiring actuation of the Engineered Safety Features, or d)

A main steam line or feedwater line break.

d.

Acceptance Criteria

1.

As used in this Specification:

a)

Imperfection means an exception to the dimensions, finish or contour of a tube from that required by fabrication drawings or specifications. Eddy-current testing indications below 20% of the nominal tube wall thickness, if detectable, may be considered as imperfections; b)

Degradation means a service-induced cracking, wastage, wear or general corrosion occurring on either inside or outside of a tube; c)

Degraded Tube means a tube containing imperfections greater than or equal to 20% of the nominal wall thickness caused by degradation; d)

% Degradation means the percentage of the tube wall thickness affected or removed by degradation.

e)

Defect means an imperfection of such severity that it exceeds the plugging limit. A tube containing a defect is defective; f)

Plugging Limit means the imperfection depth at or beyond which the tube shall be removed from service and is equal to 40% of the nominal tube wall thickness.

1) This definition does not apply to tube support plate intersections for which the voltage-based repair criteria are being applied.

Refer to 5.5.9.d.1.j for the repair limit applicable to these intersections.

(continued)

DIABLO CANYON - UNITS 1 & 2 5.0-12 Unit 1 - Amendment No. 4-5 142 TAB5.doc - R12 4

Unit 2 - Amendment No. 435 142

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

2) This definition does not apply to the portion of the tube within the tubesheet below the W* length. Acceptable tube wall degradation within the W* length shall be defined as in 5.5.9.d.1.k.

3) This definition does not apply to axial PWSCC indications, or portions thereof, which are located within the thickness of dented tube support plates which exhibit a maximum depth greater than or equal to 40 percent of the initial tube wall thickness. WCAP-15573, Revision 1, provides repair limits applicable to these intersections.

4) A tube which contains a tube support plate intersection with both an axial ODSCC indication and an axial PWSCC indication will be removed from service.

g)

Unserviceable describes the condition of a tube if it leaks or contains a defect large enough to affect its structural integrity in the event of a Double Design Earthquake, a loss-of-coolant accident, or a steam line or feedwater line break as specified in 5.5.9.c.3, above; h)

Tube Inspection means an inspection of the SG tube from the tube end (hot leg side) completely around the U-bend to the top support of the cold leg; i)

Preservice Inspection means an inspection of the full length of each tube in each SG performed by eddy current techniques prior to service to establish a baseline condition of the tubing. This inspection shall be performed after the field hydrostatic test and prior to initial Power Operation using the equipment and techniques expected to be used during subsequent inservice inspections; j)

Tube Suggort Plate Plugging Limit is used for the disposition of an alloy 600 steam generator tube for continued service that is experiencing predominantly axially oriented outside diameter stress corrosion cracking confined within the thickness of the tube support plates. At tube support plate intersections, the plugging limit is based on maintaining steam generator tube serviceability as described below:

(i) Steam generator tubes, whose degradation is attributed to outside diameter stress corrosion cracking within the bounds of the tube support plate with bobbin voltages less than or equal to the lower voltage repair limit (NOTE 1), will be allowed to remain in service.

(ii) Steam generator tubes, whose degradation is attributed to outside diameter stress corrosion cracking within the bounds of the tube support plate with a bobbin voltage greater than the lower voltage repair limit (NOTE 1), will be repaired or plugged, except as noted in 5.5.9.d.l j (iii) below.

9

<(continued)

Ad*

Aplicale for Units I and 2, Cycles 10, 11, 12, and 13 only.

DIABLO CANYON - UNITS 1 & 2 5.0-13 Unit 1 -.Amendment No. 135,151,452, TAB5.doc - R12 5

Unit 2 - Amendment No. 135,151,,

Programs and Manuals Note: There are no Changes on this Page. Page included for Information Only 5.5 Programs and Manuals 5.5.9 Steam Generator (SG) Tube Surveillance Program (continued)

(iii) Steam generator tubes, with indication of potential degradation attributed to outside diameter stress corrosion cracking within the bounds of the tube support plate with a bobbin voltage greater than the lower voltage repair limit (NOTE 1) but less than or equal to the upper voltage repair limit (NOTE 2), may remain in service if a rotating pancake coil inspection does not detect degradation. Steam generator tubes, with indications of outside diameter stress corrosion cracking degradation with a bobbin voltage greater than the upper voltage repair limit (NOTE 2) will be plugged or repaired.

(continued)

DIABLO CANYON - UNITS 1 & 2 TAB5.doc-R12 6

5.0-1 3a Unit 1 - Amendment No. 435,151,152 Unit 2 - Amendment No. 435,151,152

Programs and Manuals

5.5 lNote

There are no Changes on this Page. Page included for Information Only 5.5 Programs and Manuals 5.5.9 SteamGenerator(SG)TubeSurveillanceProgram (continued)

(iv) Certain intersections as identified in PG&E Letter DCL-03-174, dated December 19, 2003, will be excluded from application of the voltage-based repair criteria as it is determined that these intersections may collapse or deform following a postulated LOCA + SSE event.

(v) If an unscheduled mid-cycle inspection is performed, the following mid-cycle repair limits apply instead of the limits identified in 5.5.9.d.1.j (i), 5.5.9.d.1lj (ii), and 5.5.9.d.1lj (iii). The mid-cycle repair limits are determined from the following equations:

VSL VMURL =

1.0 + NDE + Gr (CL

)

VMLRL = VMURL - (VURL -

VLRL)

CL

)

where:

VURL

= upper voltage repair limit VLRL

= lower voltage repair limit VMURL = mid-cycle upper voltage repair limit based on time into cycle VMLRL = mid-cycle lower voltage repair limit based on VMURL and time into cycle At

= length of time since last scheduled inspection during which VURL and VLRL were implemented CL

= cycle length (the time between two scheduled steam generator inspections)

VSL

= structural limit voltage Gr

= average growth rate per cycle length NDE

= 95% cumulative probability allowance for nondestructive examination uncertainty (i.e., a value of 20% has been approved by the NRC)

Implementation of these mid-cycle repair limits should follow the same approach as in TS 5.5.9.d.lj (i), 5.5.9.d.lj (ii), and 5.5.9.d.1lj (iii).

(continued)

DIABLO CANYON - UNITS 1 & 2 TAB5.doc - R12 7

5.0-14 Unit 1 - Amendment No. 435, 176 Unit 2 - Amendment No. 435, 178

g Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.9 Steam Generator (SG) Tube Surveillance Program (continued)

NOTE 1: The lower voltage repair limit is 2.0 volts for 7/8 inch diameter tubing at DCPP Units I and 2.

NOTE 2: The upper voltage repair limit is calculated according to the methodology in Generic Letter 95-05 as supplemented.

k Plugging Limit is used for disposition of an alloy 600 steam generator tube for continued service that is experiencing predominately axially oriented inside diameter stress corrosion cracking confined within the tubesheet, below the bottom of the WEXTEX transition (BWT). As used in this specification:

(i) Bottom of WEXTEX Transition (BWT) is the highest point of contact between the tube and tubesheet at, or below the top-of-tubesheet as determined by eddy current testing.

(ii) W* Length is the distance to the tubesheet below the BWT that precludes tube pull out in the event of the complete circumferential separation of the tube below the W* length. The W* length is conservatively set at: 1) an undegraded hot leg tube length of 5.2 P

inches for Zone A tubes and 7.0 inches for Zone B tubes, and 2) an 2

undegraded cold leg tube length of 5.5 inches for Zone A tubes and

7.

es for Zone B tubes. Information provided in WCAP-14797 Revision 4, defines the boundaries of Zone A and Zone B.

(iii) Flexible W* Length is the W* length adjusted for any cracks found within the W* region. The Flexible W* Length is the total RPC-inspected length as measured downward from the BWT, and includes NDE uncertainties and crack lengths within W* as adjusted for growth.

(iv) W* Tube is a tube with equal to or greater than 40% degradation within or below the W* length that is left in service, and degraded within the limits specified in Specification 5.5.9d.l.k)(v).

(v) Within the tubesheet, the plugging (repair) limit is based on maintaining steam generator serviceability as described below:

1) For tubes to which the W* criteria are applied, the length of non-degraded tube below BWT shall be greater than or equal to the W* length plus NDE uncertainties and crack growth for the operating cycle.

(continued)

DIABLO CANYON - UNITS 1 & 2 5.0-15 Unit 1 - Amendment No. 435, TAB5.doc - R12 8

Unit 2 - Amendment No. 435,

Programs and Manuals 5.5 Note: There are no Changes on this Page. Page included for Information Only 5.5 Programs and Manuals 5.5.9 Steam Generator (SG) Tube Surveillance Program (continued)

2) Axial cracks in tubes returned to service using W* shall have the upper crack tip below the BWT by at least the NDE measurement uncertainty, and below the top of tube sheet (TTS) by at least the NDE measurement uncertainty and crack growth allowance, such that at the end of the subsequent operating cycle the entire crack remains below the tubesheet secondary face.

3) Resolvable, single axial indications (multiple indications must return to the null point between individual cracks) within the flexible W* length can be left in service. Alternate RPC coils or an ultrasonic test (UT) inspection can be used to demonstrate return to null point between multiple axial indications or the absence of circumferential involvement between axial indications.

4) Tubes with inclined axial indications less than 2.0 inches long (including the crack growth allowance) having inclination angles relative to the tube axis of < 45 degrees minus the NDE uncertainty, ANDECA, on the measurement of the crack angle can be left in service. Tubes with two or more parallel (overlapping elevation), inclined axial cracks shall be plugged or repaired. For application of the 2.0 inch limit, an inclined indication is an axial crack that is visually inclined on the RCP C-scan, such that an angular measurement is required, and the measured angle exceeds the measurement uncertainty of ANDEcA.

5) Circumferential, volumetric, and axial indications with inclination angles greater than (45 degrees - ANDEcA) within the flexible W*

length shall be plugged or repaired.

6) Any type of combination of the tube degradation below the W*

length is acceptable.

2.

The SG tube integrity shall be determined after completing the corresponding actions (plug all tubes exceeding the plugging limit) required by Table 5.5.9-2.

e.

Reports The contents and frequency of reports concerning the SG tube surveillance program shall be in accordance with Specification 5.6.10.

(continued)

DIABLO CANYON - UNITS 1 & 2 5.0-16 Unit 1 - Amendment No. 436 142 TAB5.doc - R12 9

Unit 2 - Amendment No. 435 142

Programs and Manuals 5.5

• Applicable for Units 1 and 2, Cycles 10, 11, 12, and 13 only.

I

\\, THIS PAGE NOT USED I

DIABLO CANYON - UNITS 1 & 2 TAB5.doc - R12 10 5.0-17 Unit 1 - Amendment No. 435, 454 Unit 2 - Amendment No. 435, 45,

Reporting Requirements 5.6 5.6 Reporting Requirements (continued) 5.6.10 Steam Generator (SG) Tube Inspection Report

a.

Within 15 days following the completion of each inservice inspection of SG tubes, the number of tubes plugged in each SG shall be reported to the Commission.

b.

The complete results of the SG tube inservice inspection shall be submitted to the Commission in a report within 12 months following completion of the inspection. This Special Report shall include:

1 )

Number and extent of tubes inspected,

2)

Location and percent of wall-thickness penetration for each indication of an imperfection, and

3)

Identification of tubes plugged.

c.

Results of SG tube inspections, which fall into Category C-3, shall be reported in a Special Report to the Commission within 30 days and prior to resumption of plant operation. This report shall provide a description of investigations sources (

conducted to determine cause of the tube degradation and corrective measures taken to prevent recurrence.

d.

For ementation of the voltage-based repair criteria to tube support plate intersect notify the NRC prior to returning the steam aenerators to service should any of lowing arise: and non-alternate repair criteria indications),

1. If estimated leaka ased on the projected end-of-cycle (9r if not practical, using the actual measu end-of-cycle) voltage utribn ec by estimated leakage by all oth alternate repair cri exceeds tleak limit determi the licensing basis dose calculati for the postul ed eamline break for the next operating cycle.

,ineased from If circumferential crack-like indications are detected at the tube supportplate l

intersections.

If indications are identified that extend beyond the confines of the tube support plate.

C 4.

If indications are identified at the tube support plate elevations that are attributable to primary water stress corrosion cracking.

If the calculated conditional burst probability based on the projected end-of-cycle (or if not practical, using the actual measured end-of-cycle) voltage distribution exceeds 1 x 10-2, notify the NRC and provide an assessment of the safety significance of the occurrence.

I (continued)

DIABLO CANYON - UNITS I & 2 TAB5.doc-R12 11 5.0-29 Unit 1 - Amendment No. 435, Unit 2 - Amendment No. 435,

Reporting Requirements 5.6 5.6 Reporting Requirement 5.6.10 Steam Generator (SG) Tube Inspection Repo

_e results of the inspection of W* tubes shall be reported to the Commission pursuant to 10 CFR 50.4 within 90 days following return to service of the steam generators. This report shall include:

5 Replace w

\\2)

W* inspection distance measured with respect to the BWT or the tp o tith

'the tubesheet, whichever is lower.\\

s A3)

Elevation and length of axial indications within the flexible W* distance and the angle of inclination of clearly skewed axial cracks (if applicable).

4)

The total steam line break leakage for the limiting steam generator per X

~WCAP-1 4797. _

fI*The aggregate calculated steam line break leakage from application of all alternate repair criteria shall be reported to the Commission pursuant to 10 CFR 50.4 within 90 days following return to service of the steam generators.

9.

For implementation of the repair criteria for axial PWSCC at dented TSPs, the NRC shall be notified prior to startup, pursuant to 10CFR50.72, of the following conditions that indicate a failure of performance criteria:

1)

The calculated SG probability of burst for condition monitoring exceeds 1 x 10-2.

2)

The calculated SG leakage for condition monitoring from all sources (all alternate repair criteria and non-alternate repair criteria indications) exceeds the leakage limit determined from the licensing basis steam line break dose calculation.

h.

For implementation of the repair criteria for axial PWSCC at dented TSPs, the results of the condition monitoring and operational assessments will be reported to the NRC within 120 days following completion of the inspection. The report will include:

1)

Tabulations of indications found in the inspection, tubes repaired, and tubes left in service under the ARC.

2)

Growth rate distributions for indications found in the inspection and growth rate distributions used to establish the tube repair limits.

3)

Plus Point confirmation rates for bobbin detected indications when bobbin is relied upon for detection of axial PWSCC in less than or equal to 2 volt dents.

4)

For condition monitoring, an evaluation of any indications that satisfy burst margin requirements based on the Westinghouse burst pressure model, but do not satisfy burst margin requirements based on the combined ANL ligament tearing and throughwall burst pressure model.

(continued) 5* Apliabl fo Unts and2, ycls 1, 1, 1, ad 13 only. )

DIABLO CANYON - UNITS 1 & 2 5.0-30 Unit 1 - Amendment No. 435,A54,452, TAB5.doc-R12 12 Unit 2 - Amendment No. 4135,151,152,

M---.4;--

Dart;r -

-- g-t Note: The requirements on Page 5.0-30a are rolled onto new Page 5.0-30b due to Insert A on Page 5.030.

5.6 Reporting Requirement

)

5.6.10 Steam Generator (SG) Tube Inspection Repoi'

5)

Performance evaluation of the operational assessment methodology for predicting flaw distributions as a function of flaw size.

6)

Evaluation results of number and size of previously reported versus new PWSCC indications found in the inspection, and the potential need to account for new indications in the operational assessment burst evaluation.

7)

Identification of mixed mode (axial PWSCC and circumferential) indications found in the inspection and an evaluation of the mixed mode indications for potential impact on the axial indication burst pressures or leakage.

8)

Any corrective actions found necessary in the event that condition monitoring requirements are not met.

i.

For implementation of the probability of prior cycle detection (POPCD) method, for the voltage-based repair criteria at tube support plate intersections, if the end-of-cycle conditional main steamline break burst probability, the projected main steamline break leak rate, or the number of indications are underpredicted by the previous cycle operational assessment, the following shall be reported to the Commission pursuant to 10 CFR 50.4 within 90 days following return to service of the steam generators:

1)

The assessment of the probable causes for the underpredications, proposed corrective actions, and any recommended changes to probability of detection or growth methodology indicated by potential methods assessments.

2)

An assessment of the potential need to revise the alternate repair criteria analysis methods if: the burst probability is underpredicted by more than 0.001 (i.e., 10% of the reporting threshold) or an order of magnitude; or the leak rate is underpredicted by more than 0.5 gpm or an order of magnitude.

3)

An assessment of the potential need to increase the number of predicted low voltage indications at the beginning of cycle if the total number of as-found indications in any SG are underestimated by greater than 15%

or by greater than 150 indications.

DIABLO CANYON - UNITS 1 & 2 5.0-30a Unit 1 - Amendment No. 135,151,452,4-77, TAB5.doc-R12 13 Unit 2 - Amendment No. 135A-51-,4-52,-70,

Technical Specification Inserts TS Insert A for TS Page 5.0-30

1)

Identification of W* tube indications and indications that do not meet W* requirements and were plugged or repaired, including the following information: the number of indications, the location of the indications (relative to the BWT and TTS), the orientation (axial, circumferential, volumetric, inclined), the severity of each indication (estimated depth), the side of the tube in which the indication initiated (inside or outside diameter), the W*

inspection distance measured with respect to the BWT or TTS (whichever is lower), the length of axial indications, the angle of inclination of clearly skewed axial cracks (if applicable), verification that the upper crack tip of W* indications returned to service remain below the TTS by at least the 95% confidence NDE uncertainty on locating the crack tip relative to the TTS, updated 95% growth rate for use in operational assessment, the cumulative number of indications detected in the tubesheet region as a function of elevation within the tubesheet, and the condition monitoring and operational assessment main steamline break leak rate for each indication and each SG in accordance with the leak rate methodology described in PG&E Letter DCL-05-018, dated March 11, 2005.

2)

Assessment of whether the results were consistent with expectations and, if not consistent, a description of the proposed corrective action.

PG&E Letter DCL-05-018 Proposed Technical Specification Changes (retyped)

Remove Page Insert PaQe 5.0-10 5.0-13 5.0-15 5.0-17 5.0-29 5.0-30 5.0-30a 5.0-10 5.0-13 5.0-15 5.0-17 5.0-29 5.0-30 5.0-30a 5.0-30b

Programs and Manuals 5.5 5.5 Programs and Manuals (continued) 5.5.9 Steam Generator (SG) Tube Surveillance Program SG tube integrity shall be demonstrated by performance of the following augmented inservice inspection program.

The provisions of SR 3.0.2 are applicable to the SG Tube Surveillance Program test frequencies.

a.

SG Sample Selection and Inspection - SG tube integrity shall be determined during shutdown by selecting and inspecting at least the minimum number of SGs specified in Table 5.5.9-1.

b.

SG Tube Sample Selection and Inspection - The SG tube minimum sample size, inspection result classification, and the corresponding action required shall be as specified in Table 5.5.9-2. The inservice inspection of SG tubes shall be performed at the frequencies specified in Specification 5.5.9.c and the inspected tubes shall be verified acceptable per the acceptance criteria of Specification 5.5.9.d. The tubes selected for each inservice inspection shall include at least 3% of the total number of tubes in all SGs; the tubes selected for these inspections shall be selected on a random basis except:

1.

Where experience in similar plants with similar water chemistry indicates critical areas to be inspected, then at least 50% of the tubes inspected shall be from these critical areas;

2.

The first sample of tubes selected for each inservice inspection (subsequent to the preservice inspection) of each SG shall include:

a)

All nonplugged tubes that previously had detectable wall penetrations (greater than 20%),

b)

Tubes in those areas where experience has indicated potential

problems, c)

A tube inspection (pursuant to Specification 5.5.9.d.1.h) shall be performed on each selected tube. If any selected tube does not permit the passage of the eddy current probe for a tube inspection, this shall be recorded and an adjacent tube shall be selected and subjected to a tube inspection, d)

Indications left in service as a result of application of the tube support plate voltage-based repair criteria shall be inspected by bobbin coil probe during all future refueling outages, e)

Tubes identified as W* tubes having a previously identified indication within the W* length shall be inspected using a rotating pancake coil (RPC) probe for the full length of the W* region during all future refueling outages.

(continued)

DIABLO CANYON - UNITS 1 & 2 5.0-10 Unit 1 - Amendment No. 435, 454, TAB 5.DOC - RXX 10 Unit 2 -Amendment No. 435, 454,

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

2) This definition does not apply to the portion of the tube within the tubesheet below the W* length. Acceptable tube wall degradation within the W* length shall be defined as in 5.5.9.d.1.k.

3) This definition does not apply to axial PWSCC indications, or portions thereof, which are located within the thickness of dented tube support plates which exhibit a maximum depth greater than or equal to 40 percent of the initial tube wall thickness. WCAP-1 5573, Revision 1, provides repair limits applicable to these intersections.

4) A tube which contains a tube support plate intersection with both an axial ODSCC indication and an axial PWSCC indication will be removed from service.

g)

Unserviceable describes the condition of a tube if it leaks or contains a defect large enough to affect its structural integrity in the event of a Double Design Earthquake, a loss-of-coolant accident, or a steam line or feedwater line break as specified in 5.5.9.c.3, above; h)

Tube Inspection means an inspection of the SG tube from the tube end (hot leg side) completely around the U-bend to the top support of the cold leg; i)

Preservice Inspection means an inspection of the full length of each tube in each SG performed by eddy current techniques prior to service to establish a baseline condition of the tubing. This inspection shall be performed after the field hydrostatic test and prior to initial Power Operation using the equipment and techniques expected to be used during subsequent inservice inspections; j)

Tube Support Plate Plugging Limit is used for the disposition of an alloy 600 steam generator tube for continued service that is experiencing predominantly axially oriented outside diameter stress corrosion cracking confined within the thickness of the tube support plates. At tube support plate intersections, the plugging limit is based on maintaining steam generator tube serviceability as described below:

(i) Steam generator tubes, whose degradation is attributed to outside diameter stress corrosion cracking within the bounds of the tube support plate with bobbin voltages less than or equal to the lower voltage repair limit (NOTE 1), will be allowed to remain in service.

(ii) Steam generator tubes, whose degradation is attributed to outside diameter stress corrosion cracking within the bounds of the tube support plate with a bobbin voltage greater than the lower voltage repair limit (NOTE 1), will be repaired or plugged, except as noted in 5.5.9.d.1.j (iii) below.

(continued)

DIABLO CANYON - UNITS 1 & 2 5.0-13 Unit 1 -Amendment No. 435,151,452, TAB 5.DOC - RXX 14 Unit 2 - Amendment No. 135,151,452,

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

NOTE 1: The lower voltage repair limit is 2.0 volts for 7/8 inch diameter tubing at DCPP Units 1 and 2.

NOTE 2: The upper voltage repair limit is calculated according to the methodology in Generic Letter 95-05 as supplemented.

k)

W* Plugginq Limit is used for disposition of an alloy 600 steam generator tube for continued service that is experiencing predominately axially oriented inside diameter stress corrosion cracking confined within the tubesheet, below the bottom of the WEXTEX transition (BWT). As used in this specification:

(i) Bottom of WEXTEX Transition (BWT) is the highest point of contact between the tube and tubesheet at, or below the top-of-tubesheet as determined by eddy current testing.

(ii) W* Length is the distance to the tubesheet below the BWT that precludes tube pull out in the event of the complete circumferential separation of the tube below the W* length. The W* length is conservatively set at: 1) an undegraded hot leg tube length of 5.2 inches for Zone A tubes and 7.0 inches for Zone B tubes, and 2) an undegraded cold leg tube length of 5.5 inches for Zone A tubes and 7.5 inches for Zone B tubes. Information provided in WCAP-14797-P, Revision 2, defines the boundaries of Zone A and Zone B.

(iii) Flexible W* Length is the W* length adjusted for any cracks found within the W* region. The Flexible W* Length is the total RPC-inspected length as measured downward from the BWT, and includes NDE uncertainties and crack lengths within W* as adjusted for growth.

(iv) W* Tube is a tube with equal to or greater than 40% degradation within or below the W* length that is left in service, and degraded within the limits specified in Specification 5.5.9d.I.k)(v).

(v) Within the tubesheet, the plugging (repair) limit is based on maintaining steam generator serviceability as described below:

1) For tubes to which the W* criteria are applied, the length of non-degraded tube below BWT shall be greater than or equal to the W* length plus NDE uncertainties and crack growth for the operating cycle.

(continued)

DIABLO CANYON - UNITS 1 & 2 5.0-15 Unit I -Amendment No. 435, TAB 5.DOC - RXX 17 Unit 2 - Amendment No. 435,

Programs and Manuals 5.5

-Hi THIS PAGE NOT USED I

DIABLO CANYON - UNITS 1 & 2 TAB 5.DOC - RXX 19 5.0-17 Unit 1 - Amendment No. 4*5, 451, Unit 2-Amendment No. 435, 451,

Reporting Requirements 5.6 5.6 Reporting Requirements (continued) 5.6.10 Steam Generator (SG) Tube Inspection Report

a.

Within 15 days following the completion of each inservice inspection of SG tubes, the number of tubes plugged in each SG shall be reported to the Commission.

b.

The complete results of the SG tube inservice inspection shall be submitted to the Commission in a report within 12 months following completion of the inspection. This Special Report shall include:

1)

Number and extent of tubes inspected,

2)

Location and percent of wall-thickness penetration for each indication of an imperfection, and

3)

Identification of tubes plugged.

c.

Results of SG tube inspections, which fall into Category C-3, shall be reported in a Special Report to the Commission within 30 days and prior to resumption of plant operation. This report shall provide a description of investigations conducted to determine cause of the tube degradation and corrective measures taken to prevent recurrence.

id.

For implementation of the voltage-based repair criteria to tube support plate intersections, notify the NRC prior to returning the steam generators to service should any of the following arise:

1.

If estimated leakage based on the projected end-of-cycle (or if not practical, using the actual measured end-of-cycle) voltage distribution, increased by estimated leakage by all other sources (alternate repair criteria and non-alternate repair criteria indications), exceeds the leak limit determined from the licensing basis dose calculation for the postulated main steamline break for the next operating cycle.

2.

If indications are identified that extend beyond the confines of the tube support plate.

3.

If the calculated conditional burst probability based on the projected end-of-cycle (or if not practical, using the actual measured end-of-cycle) voltage distribution exceeds I x 10.2, notify the NRC and provide an assessment of the safety significance of the occurrence.

(continued)

DIABLO CANYON - UNITS 1 & 2 5.0-29 Unit 1 - Amendment No. 435, TAB 5.DOC - RXX 33 Unit 2 - Amendment No. 435,

Reporting Requirements 5.6 5.6 Reporting Requirements 5.6.10 Steam Generator (SG) Tube Inspection ReDort (continued)

e.

The results of the inspection of W* tubes shall be reported to the Commission pursuant to 10 CFR 50.4 within 90 days following return to service of the steam generators. This report shall include:

1)

Identification of W* tube indications and indications that do not meet We requirements and were plugged or repaired, including the following information: the number of indications, the locations of the indications (relative to the BWT and TTS), the orientation (axial, circumferential, volumetric, inclined), the severity of each indication (estimated depth), the side of the tube in which the indication initiated (inside or outside diameter), the W* inspection distance measured with respect to the BWT or TTS (whichever is lower), the length of axial indications, the angle of inclination of clearly skewed axial cracks (if applicable), verification that the upper crack tip of W* indications returned to service remain below the TTS by at least the 95% confidence NDE uncertainty on locating the crack tip relative to the TTS, updated 95% growth rate for use in operational assessment, the cumulative number of indications detected in the tubesheet region as a function of elevation within the tubesheet, and the condition monitoring and operational assessment main steamline break leak rate for each indication and each SG in accordance with the leak rate methodology described in PG&E Letter DCL-05-018, dated March 11, 2005.

2)

Assessment of whether the results were consistent with expectations and, if not consistent, a description of the proposed corrective action.

f.

The aggregate calculated steam line break leakage from application of all alternate repair criteria shall be reported to the Commission pursuant to 10 CFR 50.4 within 90 days following return to service of the steam generators.

g.

For implementation of the repair criteria for axial PWSCC at dented TSPs, the NRC shall be notified prior to startup, pursuant to 1 OCFR50.72, of the following conditions that indicate a failure of performance criteria:

1)

The calculated SG probability of burst for condition monitoring exceeds I x 10.2.

2)

The calculated SG leakage for condition monitoring from all sources (all alternate repair criteria and non-alternate repair criteria indications) exceeds the leakage limit determined from the licensing basis steam line break dose calculation.

(continued)

DIABLO CANYON - UNITS 1 & 2 5.0-30 Unit 1 - Amendment No. 435,451,452, TAB 5.DOC - RXX 34 Unit 2 - Amendment No. 435,454,452,

Reporting Requirements 5.6 5.6 Reporting Requirements 5.6.10 Steam Generator (SG) Tube Inspection Report (continued)

h.

For implementation of the repair criteria for axial PWSCC at dented TSPs, the results of the condition monitoring and operational assessments will be reported to the NRC within 120 days following completion of the inspection. The report will include:

1)

Tabulations of indications found in the inspection, tubes repaired, and tubes left in service under the ARC.

2)

Growth rate distributions for indications found in the inspection and growth rate distributions used to establish the tube repair limits.

3)

Plus Point confirmation rates for bobbin detected indications when bobbin is relied upon for detection of axial PWSCC in less than or equal to 2 volt dents.

4)

For condition monitoring, an evaluation of any indications that satisfy burst margin requirements based on the Westinghouse burst pressure model, but do not satisfy burst margin requirements based on the combined ANL ligament tearing and throughwall burst pressure model.

(continued)

DIABLO CANYON - UNITS 1 & 2 TAB 5.DOC - RXX 35 5.0-30a Unit 1 - Amendment No. 435454,452, Unit 2 - Amendment No. 435,454,452,

Reporting Requirements 5.6 5.6 Reporting Requirements 5.6.10 Steam Generator (SG) Tube Inspection Report (continued)

5)

Performance evaluation of the operational assessment methodology for predicting flaw distributions as a function of flaw size.

6)

Evaluation results of number and size of previously reported versus new PWSCC indications found in the inspection, and the potential need to account for new indications in the operational assessment burst evaluation.

7)

Identification of mixed mode (axial PWSCC and circumferential) indications found in the inspection and an evaluation of the mixed mode indications for potential impact on the axial indication burst pressures or leakage.

8)

Any corrective actions found necessary in the event that condition monitoring requirements are not met.

i.

For implementation of the probability of prior cycle detection (POPCD) method, for the voltage-based repair criteria at tube support plate intersections, if the end-of-cycle conditional main steamline break burst probability, the projected main steamline break leak rate, or the number of indications are underpredicted by the previous cycle operational assessment, the following shall be reported to the Commission pursuant to 10 CFR 50.4 within 90 days following return to service of the steam generators:

1)

The assessment of the probable causes for the underpredications, proposed corrective actions, and any recommended changes to probability of detection or growth methodology indicated by potential methods assessments.

2)

An assessment of the potential need to revise the alternate repair criteria analysis methods if: the burst probability is underpredicted by more than 0.001 (i.e., 10% of the reporting threshold) or an order of magnitude; or the leak rate is underpredicted by more than 0.5 gpm or an order of magnitude.

3)

An assessment of the potential need to increase the number of predicted low voltage indications at the beginning of cycle if the total number of as-found indications in any SG are underestimated by greater than 15%

or by greater than 150 indications.

DIABLO CANYON - UNITS 1 & 2 5.0-30b Unit 1 - Amendment No. 445,454,452,47q, TAB 5.DOC - RXX 36 Unit 2 - Amendment No. 435,454,452,1-9, PG&E Letter DCL-05-018 Changes to Final Safety Analysis Report Update (For information only)

DCPP UNITS 1 & 2 FSAR UPDATE limit defined in the Technical Specifications. Degradation may be left in service if qualified non-destructive examination sizing techniques verify that the imperfection is less than the plugging limit (reference PG&E response to NRC Generic Letter 97-05).

Degradation may also be left in service under alternate repair criteria.

Whenever the results of any SG tubing inservice inspection fall into Technical Specification Category C-3, these results will be reported to the Commission as a Special Report pursuant to the Technical Specifications within 30 days and prior to resumption of plant operation. Such cases will be considered by the Commission on a case-by-case basis and may result in a requirement for analysis, laboratory examinations, tests, additional eddy-current inspection, and revision of the Technical Specifications, if necessary.

5.5.2.5.2 Primary-to-Secondary Leakage The plant is expected to be operated in a manner such that the secondary coolant will be maintained within those chemistry limits found to result in negligible corrosion of the SG tubes. If the secondary coolant chemistry is not maintained within these limits, localized corrosion may likely result in stress corrosion cracking. The extent of cracking during plant operation is limited by the limitation on SG tube leakage between the Reactor Coolant System and the Secondary Coolant System (primary-to-secondary leakage = 150 gallons per day per SG). Cracks having a primary-to-secondary leakage less than this limit during operation will have an adequate margin of safety to withstand the loads imposed during normal operation and by postulated accidents. DCPP has demonstrated that primary-to-secondary leakage of 150 gallons per day per SG can readily be detected during power operation. Leakage in excess of this limit will require plant shutdown and an unscheduled inspection, during which the leaking tubes will be located and plugged.

The combined calculated accident-induced primary-to-secondary leak rate from all alternate repair criteria must be less than the maximum allowable SLB leak rate limit in any one SG in order to maintain off-site doses to within 10 CFR 100 guideline values during a postulated steam line break event. FSAR Section 15.5.18.1 provides the radiological assessment for accident-induced leakage to support alternate repair criteria and defines 10.5 gpm at room temperature conditions as the maximum allowable SLB primary-to-secondary leak rate limit in any one SG.

5.5.2.5.3 W* Alternate Repair Criteria The W* criteria incorporate the guidance. in part, provided in Revision 24-of WCAP-14797-P, "Generic W* Tube Plugging Criteria for 51 Series Steam Generator Tubesheet Region WEXTEX Expansions." W* length is the distance into the tubesheet below the bottom of the WEXTEX transition (BWT) that precludes tube pullout in the event of a complete circumferential separation of the tube below the W* length. Operating experience of tubes with through-wall cracking in the transition region of European plants and in situ pressure testing of a domestic plant with primary water stress 5.5-16 Revision 16 June 2005

DCPP UNITS 1 & 2 FSAR UPDATE corrosion cracking in the roll transitions suggests that leakage at operating conditions from W* tubes would not be expected.

For tubes to which the W* criteria are applied, indications of degradation in excess of 40% through-wall can remain in service without a loss of functionality or structural and leakage integrity. Tubes to which W* is applied can experience through-wall degradation up to the limits defined in Revision 24 of WCAP-14797-P without increasing the probability of a tube rupture or large leakage event. The guidance of Regulatory Guide 1.121, issued for comment in August 1976, is used to assess the limits of acceptable tube degradation within W*. A potential exists for W* tubes to allow primary-to-secondary leakage during an postulated steam line break. Information is provided in PG&E Letter DCL-05-018, dated March 11, 2005, Rcyision 1 of

.C/P 14797 that is used to calculate the expected leakage at steam line break conditions for W* tubes. Tube degradation of any extent below the W* length, including a complete circumferential separation of the tube, is acceptable and does not require repair.

Axial cracks in tubes returned to service using the W* criteria must remain below the secondary tubesheet face at the end of the subsequent operating cycle. This performance criteria is demonstrated by operational assessment and condition monitoring.

5.5.2.5.4 Voltage-Based Alternate Repair Criteria The voltage-based repair limits in the Technical Specifications implement the guidance in GL 95-05 and are applicable only to Westinghouse-designed SGs with outside diameter stress corrosion cracking (ODSCC) located at the tube-to-tube support plate intersections. The voltage-based repair limits are not applicable to other forms of SG tube degradation nor are they applicable to ODSCC that occurs at other locations within the SG. Additionally, the repair criteria apply only to indications where the degradation mechanism is dominantly axial ODSCC with no significant cracks extending outside the thickness of the support plate. Refer to GL 95-05 for additional description of the degradation morphology.

The lower voltage repair limit for 7/8 inch diameter SG tubing is 2.0 volts in accordance with GL 95-05. Calculation of the upper voltage repair limit requires a derivation of the voltage structural limit from the burst versus voltage empirical correlation and then the subsequent derivation of the upper voltage repair limit from the structural limit.

The voltage structural limit is the voltage from the burst pressure/bobbin voltage correlation, at the 95 percent prediction interval curve reduced to account for the lower 95/95 percent tolerance bound for tubing material properties at 650'F (i.e., the 95-percent LTL curve). The voltage structural limit must be adjusted downward to account for potential flaw growth during an operating interval and to account for NDE uncertainty. The upper voltage repair limit, VURL is determined from the structural voltage limit by applying the following equation:

5.5-1 7 Revision 16 June 2005

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: (412) 3744643 Direct fax: (412) 3744011 e-mail: greshaja~westinghouse.com Our ref: CAW-05-1964 March 9,2005 APPLICATION FOR WITHHOLDING PROPRIETARY INFORMATION FROM PUBLIC DISCLOSURE

Subject:

Diablo Canyon Bounding Leak Rate Evaluation Based on WCAP-14797, Revision 2 Figures and Tables (Proprietary)

The proprietary information for which withholding is being requested in the above-referenced report is further identified in Affidavit CAW-05-1964 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 (b)(4) of 10 CFR Section 2.390 of the Commission's regulations.

Accordingly, this letter authorizes the utilization of the accompanying affidavit by Pacific Gas and Electric Company.

Correspondence with respect to the proprietary aspects of the application for withholding or the Westinghouse affidavit should reference this letter, CAW-05-1964, and should be addressed to J. A. Gresham, Manager, Regulatory Compliance and Plant Licensing, Westinghouse Electric Company LLC, P.O. Box 355, Pittsburgh, Pennsylvania 15230-0355.

Very truly yours, R. M. Span, ting Manager Regulatory Compliance and Plant Licensing Enclosures cc: B. Benney L. Feizollahi A BNFL Group company

CAW-05-1964 AFFIDAVIT COMMONWEALTH OF PENNSYLVANIA:

ss COUNTY OF ALLEGHENY:

Before me, the undersigned authority, personally appeared J. McInerney, 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:

J. McInemey, Director Systems & Safety Analysis Sworn to and subscribed before me this 9 day of

,2005 Notary Public Notarial Sea]

Sharon L Rodi, Notary Pubrc Monroevile Boro, Allegheny Couny My Commission Expires January 29,2007 Member, Pennsylvania Associaton of Notaries

2 CAW-05-1 964 (I)

I am Director, Systems & Safety Analysis, in 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)

I 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 (b)(4) 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-05-1 964 (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.

4 CAW-05-1 964 (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-05-49 P-Attachment, "Diablo Canyon Bounding Leak Rate Evaluation Based on WCAP-14797, Revision 2 Figures and Tables," dated March 2005 (Proprietary). The information is provided in support of a submittal to the Commission, being transmitted by Pacific Gas and Electric Company letter and Application for Withholding Proprietary Information from Public Disclosure, to the Document Control Desk. The proprietary information as submitted for use by Westinghouse for Diablo Canyon Units I and 2 is expected to be applicable for other licensee submittals in support of implementing the W* inspection methodology addressing service induced degradation in the tube joint region of 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 W* tube inspection methodology.

(b) Provide contact pressure as a function of depth by zone for W* leak rate determination for Diablo Canyon Units I and 2.

5 CAW-05-1964 (c) Provide a bounding W* potential steam line break leakage evaluation from within and below the W* depth for Diablo Canyon Units I and 2.

(d) 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 information 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). The justification 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 (4)(ii)(a) through (4)(ii)(f) 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.

PG&E Letter DCL-05-018 Westinghouse Electric LLC Information to Support W* Alternate Repair Criteria at Diablo Canyon Units 1 and 2 (nonproprietary)

PG&E Letter DCL-05-018 aelations na,c.e Table 1: Contact Pressure as a Function of Depth R (Pressure in psi and Depth in Inches)

Table 2: Contact Pressure Polynomial Function Coefficients for Linear Relation Coefficients I

PG&E Letter DCL-05-018

-a

.P Figure 1: SLB Leak Rate from Constrained Crack Specimens.

2 PG&E Letter DCL-05-018

-a.c~e Figure 2: Total Contact Pressure for Various W* Leak Rate Zones 3

s s

PG&E Letter DCL-05-018

,ac.e Figure 3: Contact Pressure for Coefficients 4

PG&E Letter DCL-05-018

,ac,e Figure 4: SLB Leak Rate from Constrained Crack Secimens, Zone BI Example.

5 PG&E Letter DCL-05-018 a,c,e Figure 5: SLB Leak Analysis Contact Pressures 6

PG&E Letter DCL-05-018

_ ace Figure 6: SLB Leak Rate for Axial & Circumferential Cracks for Differential Pressure of 2650 psi at 600 degrees F 7

PG&E Letter DCL-05-018

_a,ce Figure 7: SLB Leak Rate for 3600 Circumferential Cracks from the Crevice Tests 8