DCL-10-126, Response to NRC Letter Dated September 1, 2010, Request for Additional Information(Set 22) for the Diablo Canyon License Renewal Application

Response to NRC Letter Dated September 1, 2010, Request for Additional Information(Set 22) for the Diablo Canyon License Renewal Application

ML102740183
Person / Time
Site:	Diablo Canyon
Issue date:	09/30/2010
From:	Becker J Pacific Gas & Electric Co
To:	Document Control Desk, Office of Nuclear Reactor Regulation, NRC/OCM
References
PG&E Letter DCL-10-126
Download: ML102740183 (20)

Text

Pacific Gas and Electric Company James R. Becker Diablo Canyon Power Plant Site Vice President Mail Code 104/5/601

p. O. Box 56 Avila Beach, CA 93424 805.545.3462 September 30,2010 Internal: 691.3462 Fax: 805.545.6445 PG&E Letter DCL-1 0-126 U.S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20852 Docket No. 50-275, OL-DPR-80 Docket No. 50-323, OL-DPR-82 Diablo Canyon Units 1 and 2 Response to NRC Letter dated September 1,2010, Request for Additional Information (Set 22) for the Diablo Canyon License Renewal Application

Dear Commissioners and Staff:

By letter dated November 23,2009, Pacific Gas and Electric Company (PG&E) submitted an application to the U.S. Nuclear Regulatory Commission (NRC) for the renewal of Facility Operating Licenses DPR-80 and DPR-82, for Diablo Canyon Power Plant (DCPP) Units 1 and 2, respectively. The application included the license renewal application (LRA), and Applicant's Environmental Report - Operating License Renewal Stage.

By letter dated September 1, 2010, the NRC staff requested additional information needed to continue their review of the DCPP LRA.

PG&E's response to the request for additional information is included in Enclosure 1. LRA Amendment 16, resulting from the responses, is included in Enclosure 2 showing the changed pages with line-in/line-out annotations.

PG&E makes commitments in revised LRA Table A4-1, License Renewal Commitments, shown in Enclosure 2.

If you have any questions regarding this response, please contact Mr. Terence L. Grebel, License Renewal Project Manager, at (805) 545-4160.

A member of the STARS (Strategic Teaming and Resource Shar ing ) Alliance Callaway. Comanche Peak. Diablo Canyon. Palo Verde. San Onofre. South Te x as Project. Wolf Creek

Document Control Desk PG&E Letter DCL-10-126 September 30, 2010 Page 2 I declare under penalty of perjury that the foregoing is true and correct.

Executed on September 30, 2010.

Sincerely, James R. Becker pns/50340356 Enclosure cc: Diablo Distribution cc/enc: Elmo E. Collins, NRC Region IV Regional Administrator Nathanial Ferrer, NRC Project Manager, License Renewal Kimberly J. Green, NRC Project Manager, License Renewal Michael S. Peck, NRC Senior Resident Inspector Fred Lyon, NRC Project Manager, Office of Nuclear Reactor Regulation A member of the STARS (Strategic Teaming and Resource Sharing) Alliance Callaway . Comanche Peak . Diablo Canyon . Palo Verde . San Onofre . South Te x as Project . Wolf Creek

Enclosure 1 PG&E Letter DCL-10-126 Sheet 1 of 12 PG&E Response to NRC Letter dated September 1, 2010 Request for Additional Information (Set 22) for the Diablo Canyon License Renewal Application RAI 2.1.19-2 (Follow-up)

Background:

By letter dated June 14, 2010, the staff issued request for additional information (RAI)

B2.1.19-2 requesting that the applicant either justify the use of One-Time Inspection of ASME Code Class 1 Small-Bore Piping Program, or provide a plant-specific aging management program (AMP) for managing aging during the period of extended operation.

The applicant provided its response in a letter dated July 7, 2010. The staff finds that the applicant's response did not adequately address why the One-Time Inspection program is still applicable given the fact that it has experienced multiple failures in Class 1 socket welds. Additionally, the response did not provide information regarding socket weld sample selection.

Issue:

GALL AMP XI.M35, "One-Time Inspection of ASME Code Class 1 Small-Bore Piping,"

recommends the use of the AMP only for those plants that have not experienced cracking of ASME Code Class 1 small-bore piping resulting from stress corrosion or thermal and mechanical loading. It further states that for those plants that have experienced cracking, it recommends periodic inspection of the subject piping to be managed by a plant-specific AMP.

GALL AMP XI.M35 also specifies that, "This inspection should be performed at a sufficient number of locations to ensure an adequate sample. This number, or sample size, is based on susceptibility, inspectability, dose considerations, operating experience, and limiting locations of the total population of ASME Code Class 1 small-bore piping locations."

Request:

1) Discuss all failures in Class 1 small bore piping. Justify the use of One-Time Inspection of ASME Code Class 1 Small-Bore Piping Program, or provide a plant-specific AMP for managing aging during the period of extended operation.

2) Provide information regarding the number of socket welds selected for inspection and the sampling methodology. Provide the technical basis for why the sampling is statistically significant and adequate.

Enclosure 1 PG&E Letter DCL-10-126 Sheet 2 of 12 PG&E Response to RAI 2.1.19-2 (Follow-up)

1) On March 28, 1994, an un-isolatable pressure boundary leak was identified on a 3/4 inch diameter vent line socket weld off an accumulator injection line connected to the reactor coolant system (RCS). This ASME Class-1 socket weld leak was reported to the NRC (Reference PG&E Letter DCL-94-092). Metallurgical failure analysis (WCAP-14050) determined the cause of the leak as fatigue cracking initiating at a location of incomplete penetration and lack of fusion.

Extent of condition focused on double valve, cantilevered vent and drain valves that would result in an un-isolatable reactor coolant leak, and a unit shut down. Fifty locations on Unit 1 and forty locations on Unit 2 were evaluated as part of the extent of condition. Of these ninety-four locations evaluated for extent of condition to susceptibility to this failure mechanism, thirty-eight locations were modified by either deletion of the vent or drain line, addition of supports, or changing to a butt welded design.

Since the implementation of design changes to mitigate the effects of vibration induced fatigue cracking on Class-1 socket welds, no further occurrences of through wall leakage on Class-1 socket welds have occurred in the approximately 15 years since the first leak was identified. Given the significant amount of time since corrective actions have been implemented with no further occurrences of through wall leakage on ASME Class-1 small bore piping, a OTI program will be used to validate the effectiveness of corrective actions implemented to prevent recurrence.

LRA Section B2.1.19 identified that stress corrosion cracking occurred on the excess letdown reducer segment socket weld. After further review, this stress corrosion crack occurred on the ASME Class-2 portion of the piping.

2) DCPP will volumetrically examine 25 small bore welds per unit within the population of ASME Class-1 piping NPS 4-inches and less. The sample will contain socket welds and butt welds proportional to the number of socket welds and butt welds within the population. Based on the current weld count this would result in 8 butt welds and 17 socket welds in DCPP Unit 1 and 7 butt welds and 18 socket welds in Unit 2. The volumetric examination of these welds will occur within 10 years prior to the period of extended operation. The sample selection methodology will take into account damage mechanisms such as thermal fatigue, vibration induced fatigue, and stress corrosion cracking. DCPP will determine potential damage mechanisms for each weld by using site specific analysis, MRP-146 guidance, and plant operating experience. These documents currently show thermal fatigue as the prevalent damage mechanism. Plant operating experience (1 vibration induced fatigue crack) will also be considered for the socket weld examination sample to validate the effectiveness of past corrective actions.

Given the population of ASME Class-1 small bore piping NPS 4-inches and less found in DCPP Units 1 and 2, a sample size of 25 small bore welds per unit is considered

Enclosure 1 PG&E Letter DCL-10-126 Sheet 3 of 12 statistically significant. Sample methodologies such as that found in EPRI report TR-107514 "Age-Related Degradation Inspection Method and Demonstration: In Behalf of Calvert Cliffs Nuclear Power Plant License Renewal Application" show that a sample size of 25 is considered statistically significant even when the population approaches infinity.

LRA Section B2.1.19 has been revised to clarify plant operating experience and address the sampling methodology. Table A4-1 has been revised to reflect a commitment to inspect 25 small bore welds per unit. See revised LRA Table A4-1 and Section B2.1.1.19 in Enclosure 2.

Enclosure 1 PG&E Letter DCL-10-126 Sheet 4 of 12 RAI 2.1.28-1 (Follow-up)

Background:

By letter dated July 19, 2010, the applicant responded to RAI B2.1.28-1 regarding the three tier acceptance criteria which was developed for acceptance for Diablo Canyon Nuclear Power Plant containments concrete surface conditions. In the response, the applicant states that procedure NDE VT 3C-1, which originally contained a three tier acceptance criteria has been revised as to clarify exactly when a corrective action document is required to be written. In addition, the applicant states that the third-tier criterion is based on an engineering evaluation performed in PG&E Calculation No.

2305C, Revision 2, for determining threshold levels (acceptable for continued operability).

Issues:

1) Revision 3 of procedure NDE VT 3C-1 now has two tier acceptance criteria.

For all degradations that are in excess of Tier 1 criteria, the procedure recommends that the responsible engineer's review is required.

2) Calculation No. 2305C, Revision 2, has an engineering evaluation for determining threshold levels for three tiers. The evaluation in the calculation does not distinguish between operability and long term operation of the plant.

3) Section 3.0 of the calculation allows a crack width of 0.025 inch instead of the 0.015 inch listed in ACI 349.3R. The justification for increasing the crack width limit is not clearly explained in the calculation. Revision 3 of procedure NDE VT 3C-1 also uses a crack width limit of 0.025 inch for Tier 1.

Requests:

1) Explain the reason for the inconsistency between Calculation No. 2305C, Revision 2, and Revision 3 of Procedure NDE VT 3C-1 regarding the use of different tiers. This is significant because Section 3.0 of Calculation No. 2305C states that the acceptance criteria defined in the calculation will be documented in Procedure NDE VT 3C-1.

2) Explain why Calculation No. 2305C does not have separate concrete surface examination acceptance criteria for operability and long term operation of the plant.

3) Provide justification for use of crack width limit of 0.025 inch for Tier 1 criteria.

Enclosure 1 PG&E Letter DCL-10-126 Sheet 5 of 12 PG&E Response to RAI 2.1.28-1 (Follow-up)

1. Calculation No. 2305C, Revision 2 was prepared in accordance with Procedure NDE VT 3C-1 Revision 2. Calculation No. 2305C will be revised by November 1, 2010, to be consistent with the latest revision of Procedure NDE VT 3C-1. See revised LRA Table A4-1 in Enclosure 2.

2. Calculation No. 2305C acceptance criteria will be consistent with the latest revision of Procedure NDE VT 3C-1. Any long term planning and decisions on potential repair will be made on a case by case basis and based on review of trends in the inspection findings and will be implemented via the DCPP corrective action program. See revised LRA Table A4-1 in Enclosure 2.

3. Procedure NDE VT 3C-1 and Calculation No. 2305C acceptance criteria will be revised to be consistent with ACI 349.3R Chapter 5 detailed quantitative acceptance criteria with the exception that the First Tier, the allowable crack width of 0.015 (per ACI 349.3, Section 5.1) is increased to 0.025 for areas not around penetrations and embedments. See revised LRA Table A4-1 in Enclosure 2. It should be noted that ACI 349.3R96 does not address the evaluation requirements for concrete containment vessels. However, its quantitative requirements are generally used as guidelines in the absence of any other applicable code. This increase in allowable crack width for areas not around penetrations and embedments is judged to be acceptable based on the following:

a. It is applicable only to areas of the containment that are relatively less stressed and have a large margin of safety (not around penetrations/openings and embedments).

b. ACI 349, Section 7.7.1 states that the typical minimum concrete cover for concrete exposed to earth or weather (for No. 18 bar) is 2. ACI 224R-01, Table 4.1 (Guide to reasonable crack widths, reinforced concrete under service loads), discusses what reasonable crack widths may be for typically reinforced concrete structures with typical minimum concrete covers. ACI 224R-01, Table 4.1 states that a reasonable crack width for concrete exposed to humidity, moist air and soil is 0.012".

Based on review of ACI 224R-01, Table 4.1 and Section 4.4 (Tolerable crack widths versus exposure conditions in reinforced concrete) and ACI 349, Section 7.7.1, it is reasonable to conclude that an acceptable crack width of 0.012" corresponds to a typical minimum concrete cover of 2" and is considered more than adequate to prevent water from reaching the embedded reinforcement. By extrapolating the ratio of crack width size to

Enclosure 1 PG&E Letter DCL-10-126 Sheet 6 of 12 minimum concrete cover, the expected acceptable crack width corresponding to a minimum concrete cover of 5 would be about 0.030.

c. At DCPP, the nominal concrete cover for reinforcement in the containment cylinder wall and dome is slightly greater than 5" (per PG&E design drawings). Therefore, the use of a crack width limit of 0.025 (< 0.030) is justified.

It should also be noted that other inspection attributes per Procedure NDE VT 3C-1 will ensure that any indications of anomalies beyond the First Tier limits related to any degradation other than the size of the crack width are identified and recorded for further review by the responsible engineer.

Enclosure 1 PG&E Letter DCL-10-126 Sheet 7 of 12 RAI 2.1.32-1 (Follow-up)

By letter dated July 19, 2010, the applicant responded to RAI B2.1.32-1 regarding the Structures Monitoring Program acceptance criteria categories. In the response, the applicant provides a description of structural concrete condition classifications.

However, the descriptions are qualitative and make no mention of quantitative criteria.

The category descriptions leave much of the deficiency rating to the judgment of the responsible engineer.

A lack of quantitative criteria for condition classification and acceptance can lead to differences in classification by different responsible engineers. The GALL Report states that acceptance criteria should be commensurate with industry standards and offers ACI 349.3R as an acceptable basis for developing acceptance criteria. ACI 349.3R, Chapter 5 provides detailed quantitative acceptance criteria. In addition, the GALL Report states that the plant-specific Structures Monitoring Program is to contain sufficient detail on acceptance criteria to conclude that this program attribute is satisfied.

Explain how quantitative guidelines are incorporated into the Structures Monitoring Program acceptance criteria. Discuss any relevant references or guidance documents which contain the acceptance criteria.

PG&E Response to RAI 2.1.32-1 (Follow-up)

Prior to the period of extended operation, the acceptance criteria for concrete structural elements provided in the implementing procedures for the Structures Monitoring Program for safety-related structures will be revised to incorporate the quantitative evaluation criteria provided in ACI 349.3R, Evaluation of Existing Nuclear Safety Related Concrete Structures, Chapter 5, Evaluation Criteria. See revised LRA Table A-4 in Enclosure 2.

RAI 2.1.32-2 (Follow-up)

Enclosure 1 PG&E Letter DCL-10-126 Sheet 8 of 12 By letter dated July 19, 2010, the applicant responded to RAI B2.1.32-2 regarding the Structures Monitoring Program inspection interval. In the response, the applicant stated that inspections are scheduled such that the accessible areas of both units are inspected over a maximum ten year interval, except water control structures, for which all accessible areas of both units are inspected at a frequency of no more than five years. The applicant states that the established frequencies provide assurance that any age-related degradation is detected at an early stage and that appropriate corrective actions can be taken.

The applicant did not include structures exposed to a natural environment or structures inside primary containment within the five year inspection interval as recommended in ACI 349.3R, Table 6.1. Due to environmental factors, such as winds, temperature fluctuations, humidity, radiation, chloride exposure, etc., the staff disagrees that a ten year inspection interval is appropriate for structures exposed to a natural environment or inside primary containment.

Explain how the Structures Monitoring Program inspection interval is aligned with the guidance in ACI 349.3R, or provide a detailed technical justification for a longer inspection interval for structures inside primary containment or exposed to a natural environment. An adequate explanation needs to address all environmental factors to which a structure may be exposed, as well as relevant operating experience supporting the adequacy of a longer inspection interval (e.g., humidity, high winds, temperature fluctuations, radiation, etc.).

PG&E Response to RAI 2.1.32-2 (Follow-up)

The Structures Monitoring Program inspection interval will be revised to be aligned with the guidance in ACI 349.3R, Evaluation of Existing Nuclear Safety Related Concrete Structures, Chapter 6, Evaluation Frequency, except for the exterior of non-safety related structures, for which all accessible areas of both units will be inspected at an interval of no more than ten years. See revised LRA Table A4-1 in Enclosure 2.

RAI 2.1.32-4 (Follow-up)

Enclosure 1 PG&E Letter DCL-10-126 Sheet 9 of 12 By letter dated July 19, 2010, the applicant responded to RAI B2.1.32-4 regarding Units 1 and 2 spent fuel pool leakage.

In its response, the applicant stated that Unit 1 experiences occasional minor leakage within the leak chases during refueling outages, and Unit 2 experiences a slight increase of leakage within the leak chases during outages.

Explain why there is spent fuel pool leakage at Unit 1 only during outages, and why the leakage increases during outages at Unit 2.

PG&E Response to RAI 2.1.32-4 (Follow-up)

As indicated in PG&E letter DCL-10-077 dated July 19, 2010, RAI B2.1.32-4 response, there is presently no liner leaks on Unit 1.

As indicated in PG&E letter DCL-10-077, Unit 2 has had minor leakage that varies from 50 to 975 ml per week and it appears that very slight increases of leak rate occurs during outages. The very slight increase in leakage in Unit 2 during the outages is not due to flooding of the transfer tube since sampling of the leak chases has shown the leak chase to be dry when the tube is flooded. The very slight increase in the Unit 2 leakage during outages is attributed to outage activities such as fuel handling, cask movements and increases in the spent fuel pool water level. These activities can result in minor stresses to the spent fuel pool liner.

During a telephone call on August 12, 2010 between the NRC staff and PG&E, NRC staff requested clarification regarding if the frequency for analyses of the water collected from the leak chases and the criteria for evaluation or acceptance would be continued in the period of extended operation. In addition, the NRC staff requested if any future video inspections of the leak chase channels would be conducted. PG&E Letter No.

DCL-86-067 dated March 11, 1986 indicated the following: Leakage past the liner would be detected by opening these leak detection shutoff valves and observing any water accumulation or flow on a weekly basis. These valves are normally closed. This weekly leak chase surveillance will be continued during the period of extended operation. As discussed in PG&E Letter DCL-10-077 RAI Response B2.1.32-4, video inspections of the Units 1 and 2 leak chases were conducted in January 2008 and a follow-up video inspection of the Unit 2 leak chases were performed in March 2010.

These inspections determined the leak chases were not blocked. A one-time video inspection of the Unit 2 leak chase will be performed during the period of extended operation. See revised LRA Table A4-1 in Enclosure 2.

Enclosure 1 PG&E Letter DCL-10-126 Sheet 10 of 12 RAI 2.1.33-1 (Follow-up)

By letter dated July 19, 2010, the applicant responded to RAls B2.1.33-1, B2.1.33-2, and B2.1.33-3 regarding water control structures. The responses discussed past inspections of the intake structure, discharge structure, and discharge conduits.

It is unclear from the response that the structures have been inspected on a five year interval, as recommended by the GALL AMP XI,S7, "Water-Control Structures." It is also unclear if different inspection frequencies will be used for different structures, or portions of structures.

Identify the inspection frequency that will be used for the Water-Control Structures Program during the period of extended operation. If different frequencies will be used for different structures, or portions of structures, clearly identify each 'structure -inspection frequency' combination. Explain whether the inspection frequency during the period of extended operation requires an 'enhancement' to the existing program.

PG&E Response to RAI 2.1.33-1 (Follow-up)

As discussed in LRA Section B2.1.33, the RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants program, is implemented as part of the Structures Monitoring Program. Inspections of water-control structures are currently scheduled such that the accessible areas of both units are inspected at an interval of no more than ten years. The existing Structures Monitoring Program procedure will be revised prior to the period of extended operation to specify a five year maximum interval for inspection of water control structures. See revised LRA Table A4-1 in Enclosure 2.

Enclosure 1 PG&E Letter DCL-10-126 Sheet 11 of 12 RAI 2.1.33-3 (Follow-up)

By letter dated July 19, 2010, the applicant responded to RAI B2.1.33-3 regarding the circulating water discharge conduits. The response explained that portions of the discharge conduits are inaccessible for inspection due to marine growth. The response also discussed inspections in 2001 (Unit 2) and 2002 (Unit 1), with the next inspection scheduled for 2011 (Unit 2) and 2012 (Unit 1). The response stated that these inspections will require removal of marine growth.

It is unclear from the response which portions of the discharge structures are inaccessible for inspection due to marine growth. It is also unclear how frequently the marine growth is removed, and when it is removed, what portion of the inaccessible area is made accessible.

Quantify the portion of discharge conduit that is inaccessible due to marine growth.

Explain how the inaccessible portions will be inspected during the period of extended operation. Include frequencies for removing the marine growth, and if the marine growth is removed on a sampling basis explain how the sample size and location will be determined.

PG&E Response to RAI 2.1.33-3 (Follow-up)

Discharge Conduits PG&E letter dated July 19, 2010, provided specific information as to the extent of prior inspections performed on the conduits. Described in the letter was a summary of which portions of the conduits were scraped of marine growth, any degradation findings, and the overall condition of the concrete once the marine growth had been removed.

The interior surfaces of the discharge conduits are currently inaccessible due to marine growth. The marine growth will be removed in all accessible areas during refueling outage 2R16 (2011) and 1R17 (2012). The requirements for future inspections, including those to be performed during the period of extended operation, will be developed based on the findings from the 2R16/1R17 inspections. These requirements will address the following:

inspection interval (not to exceed five years) extent and frequency of marine growth removal inspection extent (100% vs. sampling)

Discharge Structure PG&E letter dated July 19, 2010, provided specific information as to how the concrete inside the discharge structure is examined, the history and details of the repairs performed, and PG&Es plans to repair and remove the delaminations in the structure.

Enclosure 1 PG&E Letter DCL-10-126 Sheet 12 of 12 Since the discharge structure is located primarily below grade, approximately 90% of the exterior walls and 70% of the exterior roof surfaces are not accessible for inspection. All accessible portions of the exterior of the discharge structure will be inspected in accordance with the Structures Monitoring Program on a five year maximum interval. Even though degradation from chloride attack on below grade concrete structures have not been prevalent at DCPP, the Structures Monitoring Program includes opportunistic inspections of any below-grade portion of the discharge structure that is exposed during maintenance and/or construction activities (Reference revised LRA Table A4-1, item #34, submitted in PG&E letter dated July 19, 2010) .

Due to the continual discharge of circulating water during plant operation, access to the interior of the discharge structure for inspections is only feasible during a refueling outage. During refueling outages, visual inspections of the interior portion of the discharge structure are performed from a localized vantage point from inside the structure. The interior surface of the roof slab and approximately 50% of the interior surface of the walls can be visually inspected from this location. However, due to the cross flow of circulating water through an opening in the wall separating the unit-specific portions of the discharge structure, as long as one unit is operating, the top surface of the floor slab and the lower portions of the walls are continuously submerged and not visible or accessible for inspection. Inspections are not planned for the inaccessible portions of the interior of the discharge structure unless indications from the inspection of the accessible portions warrant further investigation. A full inspection of the interior of the discharge structure will require a dual unit outage.

Enclosure 2 PG&E Letter DCL-10-126 Sheet 1 of 6 LRA Amendment 16 LRA Section RAI Section B2.1.19 2.1.19-2 2.1.19-2, 2.1.28-1, 2.1.32-1, Table A4-1 2.1.32-2, 2.1.32-4, 2.1.33-1 Appendix B PG&E Letter DCL-10-126 AGING MANAGEMENT PROGRAMS Sheet 2 of 6 B2.1.19 One-Time Inspection of ASME Code Class 1 Small-Bore Piping Program Description The One-Time Inspection of ASME Code Class 1 Small-Bore Piping program manages cracking of ASME Code Class 1 piping less than or equal to four inches nominal pipe size (NPS 4). This program is implemented as part of the fourth interval of the DCPP Inservice Inspection (ISI) program.

For ASME Code Class 1 small-bore piping, the ISI program requires volumetric examinations on selected butt weld locations to detect cracking. Weld locations are selected based on the guidelines provided in EPRI TR-112657, Revised Risk-Informed Inservice Inspection Evaluation Procedure. Volumetric examinations are conducted in accordance with ASME Section XI with acceptance criteria from Paragraph IWB-3000 and IWB-2430. The fourth interval of the ISI program at DCPP, beginning in 2015 for Unit 1 and 2016 for Unit 2, will provide the results for the one-time inspection of ASME Code Class 1 small-bore piping. DCPP will volumetrically examine 25 small bore welds per unit within the population of ASME Class-1 piping NPS 4-inches and less. The sample will contain socket welds and butt welds proportional to the number of socket welds and butt welds within the population. For volumetric examinations of socket welds, DCPP will use a site developed and qualified procedure. DCPP will evaluate the need to enhance this procedure with the latest industry techniques at the time of the volumetric examination. DCPP has not experienced cracking of ASME Code Class 1 small bore pipe butt In conformance with 10 CFR 50.55a(g)(4)(ii), the DCPP ISI Program is updated each successive 120 month inspection interval to comply with the requirements of the latest edition of the ASME Code specified twelve months before the start of the inspection interval.

DCPP inspects ASME Code Class 1 piping less than or equal to NPS 4 through the RI-ISI Program. To determine the selection of elements for examination, degradation mechanisms were assessed and a consequence evaluation was completed in order to perform a risk ranking of the piping segments within the scope of the RI-ISI program. A risk matrix was created with categories for high, medium and low risk. Elements for examination were selected such that 25 percent of the elements in the high risk category were selected, 10 percent of the elements in the medium risk region were selected, and no elements from the low risk region were selected.

The RI-ISI Program for pipe welds employs the EPRI methodology as described in EPRI Topical Report TR 112657, Revision. B. The selection for examination of specific elements within a segment is based on the degradation mechanism, as well as inspection cost, radiation exposure and accessibility. Other considerations that go into the element selection process are inspectability, distribution of inspections among systems and segments, plant specific inspection results, and repairs or remedial measures which have been implemented.

Appendix B PG&E Letter DCL-10-126 AGING MANAGEMENT PROGRAMS Sheet 3 of 6 NUREG-1801 Consistency The One-Time Inspection of ASME Code Class 1 Small-Bore Piping program is an existing program that is consistent with exception to NUREG-1801,Section XI.M35, One-Time Inspection of ASME Code Class 1 Small-Bore Piping.

Exceptions to NUREG-1801 Program Elements Affected Scope of Program - Element 1 NUREG-1801 recommends the use of EPRI Report 1000701, Interim Thermal Fatigue Management Guideline (MRP-24), January 2001, for identifying piping susceptible to potential effects of thermal stratification or turbulent penetration. The DCPP risk-informed process examination requirements are performed consistent with EPRI TR-112657, Revised Risk-Informed Inservice Inspection Evaluation Procedure, Revision B, instead of EPRI Report 1000701. Guidelines for identifying piping susceptible to potential effects of thermal stratification or turbulent penetration that are provided in EPRI Report 1000701 are also provided in EPRI TR-112657. The recommended inspection volumes for welds in EPRI Report 1000701 are identical to those for inspection of thermal fatigue in RI-ISI programs; thus, the DCPP risk-informed process examination requirements meet the recommendations of NUREG-1801. The NRC accepted DCPPs use of EPRI TR-112657 in a letter to PG&E dated November 8, 2001.

Enhancements None Operating Experience Operating experience at DCPP is evaluated and implemented to ensure ASME Code Class 1 small-bore pipes are maintained within acceptable limits. This is accomplished by promptly identifying and documenting (using the corrective action program) any conditions that indicate degradation. In addition, industry operating experience, self assessments and independent audits provide additional input to ensure that program effectiveness is maintained.

A review of plant-specific operating experience identified one example of cracking in ASME Code Class 1 small-bore pipe welds less than or equal to NPS 4. The following example identifies weld cracking at DCPP:

1) A cracked weld coupling on a pressurizer level instrument capillary fill line evaluation concluded that the crack was due to a lack of fusion to the tubing and previous metal removal resulting in fatigue cracking. New tubing was installed.

Appendix B PG&E Letter DCL-10-126 AGING MANAGEMENT PROGRAMS Sheet 4 of 6 Follow-up inspections at these locations have not identified any further evidence of weld cracking. This demonstrates the effectiveness of the DCPP Corrective Action program.

Inservice Inspection Reports for the Second Interval were reviewed for Unit 1 Refueling Outages 10, 11, 12 and 13 and Unit 2 Refueling Outages 10, 11, 12 and 13. There were no reportable indications for small-bore piping observed.

The DCPP operating experience findings for this program identified no unique plant specific operating experience; therefore DCPP operating experience is consistent with NUREG-1801. Should evidence of significant aging be revealed by the one-time inspection, periodic inspections will be implemented.

Based on a review of operating experience, cracking of ASME Code Class 1 small-bore pipe butt welds less than or equal to NPS 4 has not been observed. This provides confidence that the One-Time Inspection of ASME Code Class 1 Small-Bore Piping program is adequate to assure that aging of ASME Code Class 1 piping is not occurring and component intended functions will be maintained during the period of extended operation.

Conclusion The continued implementation of the One-Time Inspection of ASME Code Class 1 Small-Bore Piping program provides reasonable assurance that aging effects will be managed such that the systems and components within the scope of this program will continue to perform their intended functions consistent with the current licensing basis for the period of extended operation.

TABLE A4-1 PG&E Letter DCL-10-126 LICENSE RENEWAL COMMITMENTS Page 5 of 6 Table A4-1 License Renewal Commitments Item # Commitment LRA Implementation Section Schedule 39 DCPP will volumetrically examine 25 small bore welds per unit within the B2.1.19 Prior to the period population of ASME Class-1 piping NPS 4-inches and less. The sample will of extended operation contain socket welds and butt welds proportional to the number of socket welds and butt welds within the population. Based on the current weld count this would result in 8 butt welds and 17 socket welds in DCPP Unit-1 and 7 butt welds and 18 socket welds in Unit-2. The volumetric examination of these welds will occur within 10 years prior to the period of extended operation.

40 Calculation No. 2305C will be revised by November 1, 2010 to be consistent B2.1.28 Prior to the period with the latest revision of Procedure NDE VT 3C-1. of extended operation 41 Calculation No. 2305C acceptance criteria will be consistent with the latest B2.1.28 Prior to the period revision of Procedure NDE VT 3C-1. Any long term planning and decisions on of extended operation potential repair will be made on a case by case basis and based on review of trends in the inspection findings and will be implemented via DCPP corrective action program.

42 Procedure NDE VT 3C-1 and Calculation No. 2305C acceptance criteria will be B2.1.28 Prior to the period revised to be consistent with ACI 349.3R Chapter 5 detailed quantitative of extended operation acceptance criteria with the exception that the First Tier, the allowable crack width of 0.015 (per ACI 349.3, Section 5.1) is increased to 0.025 for areas not around penetrations and embedments.

43 Prior to the period of extended operation, the acceptance criteria for concrete B2.1.32 Prior to the period structural elements provided in the implementing procedures for the Structures of extended operation Monitoring Program for safety-related structures will be revised to incorporate the quantitative evaluation criteria provided in ACI 349.3R, Evaluation of Existing Nuclear Safety Related Concrete Structures, Chapter 5, Evaluation Criteria.

TABLE A4-1 PG&E Letter DCL-10-126 LICENSE RENEWAL COMMITMENTS Page 6 of 6 44 The Structures Monitoring Program inspection interval will be revised to be B2.1.32 Prior to the period aligned with the guidance in ACI 349.3R, Evaluation of Existing Nuclear Safety of extended operation Related Concrete Structures, Chapter 6, Evaluation Frequency, except for the exterior of non-safety related structures, for which all accessible areas of both units will be inspected at an interval of no more than ten years.

45 A one-time video inspection of the Unit 2 leak chase will be performed during B2.1.32 Prior to the period the period of extended operation of extended operation 46 The existing Structures Monitoring Program procedure will be revised prior to B2.1.33 Prior to the period the period of extended operation to specify a five year maximum interval for of extended operation inspection of water control structures.