DCL-16-023, Response to NRC Letter Dated February 2, 2016, Requests for Additional Information for the Review of the License Renewal Application - Set 39.

Response to NRC Letter Dated February 2, 2016, Requests for Additional Information for the Review of the License Renewal Application - Set 39.

ML16056A636
Person / Time
Site:	Diablo Canyon
Issue date:	02/25/2016
From:	Strickland L Pacific Gas & Electric Co
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
DCL-16-023, TAC ME2896, TAC ME2897, FOIA/PA-2016-0438
Download: ML16056A636 (48)

Text

Pacific Gas and Electric Company L. Jearl Strickland, P.E. Diablo Canyon Power Plant Director P.O. Box 56 Technical Services Avila Beach, CA 93424 805.595.6476 J LS2@pge .com February 25, 2016 PG&E Letter DCL-16-023 U.S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20555-0001 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 February 2, 2016, "Requests for Additional Information for the Review of the Diablo Canyon Power Plant, Units 1 and 2, License Renewal Application -Set 39 (TAC Nos. ME2896 and ME2897)"

Dear Commissioners and Staff:

By Pacific Gas and Electric Company (PG&E) Letter DCL-09-079, "License Renewal Application," dated November 23, 2009, 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 LRA Appendix E, "Applicant's Environmental Report- Operating License Renewal Stage."

By letter dated February 2, 2016, the NRC staff requested additional information (RAI) needed to continue their review of the DCPP LRA. contains PG&E's responses to the RAis. Enclosure 2 contains PG&E's revised response to RAI3.0.3.2.6-3. Enclosure 3 contains the affected LRA pages resulting from the RAI responses with the changes shown as electronic markups (deletions crossed out and insertions italicized).

PG&E makes changes to existing commitments (as defined by NEI 99-04) in this letter. Revised commitments are contained in the changes to LRA Table A4-1 in .

• If you have any questions regarding this response, please contact Mr. Terence L. Grebel, License Renewal Project Manager, at (805) 458-0534.

I declare under penalty of perjury that the foregoing is true and correct.

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

• Diablo Canyon

• Palo Verde

• Wolf Creek

Document Control Desk PG&E Letter DCL-16-023 February 25, 2016 Page 2 Executed on February 25, 2016.

Lft 0 L. Jearl Strickland, P. E.

L!l__

Director, Technical Services mma0/50833020 Enclosures cc: Diablo Distribution cc/enc: Marc L. Dapas, NRC Region IV Administrator Siva P. Lingam, NRC Project Manager Richard A. Plasse, NRC Project Manager, License Renewal Binesh K. Tharakan, Acting NRC Senior Resident Inspector Michael J. Wentzel, NRC Project Manager, License Renewal (Environmental)

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

• Diablo Canyon

• Palo Verde

• Wolf Creek

Enclosure 1 PG&E Letter DCL-16-023 PG&E Response to NRC Letter dated February 2, 2016, "Requests for Additional Information for the Review of the Diablo Canyon Power Plant, Units 1 and 2, License Renewal Application - Set 39 (TAC Nos. ME2896 and ME2897)"

Enclosure 1 PG&E Letter DCL-16-023 Page 1 of 24 PG&E Response to NRC Letter dated February 2, 2016, "Requests for Additional Information for the Review of the Diablo Canyon Power Plant, Units 1 and 2, License Renewal Application - Set 39 (TAC Nos. ME2896 and ME2897)"

RAI2.1-4

Background:

10 CFR 54.4, "Scope," states, in part:

(a) Plant systems, structures and components within the scope of this part are -

(1) Safety-related systems, structures, and components which are those relied upon to remain functional during and following design-basis events (as defined in 10 CFR 50.49 (b)(1)) to ensure the following functions-(i) The integrity of the reactor coolant pressure boundary; (ii) The capability to shut down the reactor and maintain it in a safe shutdown condition; or (iii) The capability to prevent or mitigate the consequences of accidents which could result in potential offsite exposures comparable to those referred to in 10 CFR 50.34(a)(1), 10 CFR 50.67(b)(2), or 10 CFR 100.11 of this chapter, as applicable.

(2) All nonsafety-related systems, structures and components whose failure could prevent satisfactory accomplishment of any of the functions identified in paragraphs (a)(1 )(i), (ii), or (iii) of this section.

Issue:

The staff reviewed the applicant's, December 22, 2014, letter that provided an update to the Diablo Canyon License Renewal Application (LRA). Attachment 9 of the letter, *

"Updates to Reflect Installed Plant Equipment and Editorial Corrections," stated that the methodology contained in LRA Section 2.1.2.2, "Title 10 CFR 54.4(a)(2)- Nonsafety-Related Affecting Safety Related," had been modified.

LRA Section 2. 1. 2. 2, described the method used to identify nonsafety-related systems, structures, and components (SSCs), having the potential for spatial interaction with safety-related SSCs that could impact the ability of the safety-related SSCs to perform their intended functions, for inclusion within the scope of license renewal in accordance with 10 CFR 54.4(a)(2). LRA Section 2.1.2.2 originally stated:

Enclosure 1 PG&E Letter DCL-16-023 Page 2 of 24 Nonsafety-related systems and components that contain fluid or steam, and are located inside structures that contain safety-related SSCs are included in scope for potential spatial interaction under criterion 10 CFR 54.4(a)(2). modified LRA Section 2.1.2.2 as follows (italics added):

Nonsafety-related systems and components that contain fluid or steam, and are located inside structures that contain safety-related SSCs are included in scope for potential spatial interaction under criterion 10 CFR 54.4(a)(2) unless scoped out by a component-specific engineering evaluation.

Request:

The staff requests the applicant to provide the following:

1. Describe the component specific engineering evaluation process used to remove nonsafety-related SSCs from the scope of license renewal, which were originally documented in the LRA as being included within the scope of license renewal in accordance with the requirements of 10 CFR 54.4(a)(2)

2. List the nonsafety-related SSCs for which component specific engineering evaluations were performed.

3. List the nonsafety-related SSCs for which the component specific engineering evaluations resulted in a different conclusion than that originally documented in the LRA, as to whether the SSG was within or not within the scope of license renewal, and describe those conclusions.

PG&E Response to RAI2.1-4 Pacific Gas and Electric (PG&E's) response to each request is provided below.

(1) As indicated in PG&E Letter DCL-14-103, "10 CFR 54.21(b) Annual Update to the Diablo Canyon Power Plant License Renewal Application (LRA), Amendment 48 and LRA Appendix E, Applicant's Environmental Report- Operating License Renewal Stage, Amendment 1,"dated December 22, 2014, during the development of the License Renewal Application (LRA), PG&E included all nonsafety-related structures, systems, and components (SSCs) in the auxiliary building, containment, and the fuel handling building as being within the scope of license renewal for Criterion (a)(2) spatial interaction considerations, except as discussed in LRA Sections 3.1.1 and 3.1.2. As a result, no room by room, any similar structure breakdown, or spatial interaction walkdown was performed for these structures. However, preliminary walkdowns and engineering evaluations have determined that certain nonsafety-

Enclosure 1 PG&E Letter DCL-16-023 Page 3 of 24 related SSCs are located such that there is no potential to impact safety-related SSCs. Inclusion of these nonsafety-related SSCs in the scope of license renewal will present an unnecessary burden for inspection or component replacement.

PG&E is updating its seeping and screening methodology to allow nonsafety-related systems and components that contain fluid or steam included in-scope for potential spatial interaction under criterion 10 CFR 54.4(a)(2), and are located inside structures that contain safety-related SSCs, to be scoped out if a component-specific engineering evaluation is performed.

The component-specific engineering evaluation process used to remove nonsafety-related SSCs from the scope of license renewal consists of performing a detailed walkdown of the nonsafety-related SSCs to determine their potential to interact with safety-related SSCs and documenting the basis in an engineering report.

Nonsafety-related SSCs may be removed from the scope of license renewal using the following criteria:

Criterion Description Technical Basis 1.1 Electrical terminal boxes, pull The design of the enclosures is such boxes, junction boxes', and that significant leakage into the conduit bodies qualified for enclosures will not likely occur even leakage or spray with long term exposure to leaking fluids.

1.2 Intervening barriers -walls, Intervening barriers do not allow ceilings, floors, shielding, doors, leakage or spray to reach the safety or large interposing equipment- related SSC(s). Intervening barriers preclude interaction are in the scope of license renewal.

1.3 Floor drains or component Floor drains and component pedestals preclude interaction pedestals do not allow leakage to reach the safety related SSC(s).

(2) As discussed in the PG&E response to request for additional information (RAI) 82.1.22-6, in PG&E Letter DCL-15-121, "Response to NRC Letter dated September 24, 2015, Request for Additional Information for the Review of the Diablo Canyon Power Plant, Units 1 and 2, License Renewal Application- Set 38," dated October 21, 2015, for copper alloy piping portions of the domestic water system that are in the scope of license renewal, PG&E entered the in-scope a(2) piping into the corrective action program (CAP) to address recurring internal corrosion. PG&E is in the process of implementing corrective actions prior to the period of extended operation that include replacing the piping with a material that is more corrosion-resistant, or installing pipe shielding in accordance with NEI 95-10 Appendix F, which will be age managed in accordance with the External Surfaces Monitoring Program (82.1.20). To minimize the amount of copper alloy piping to be replaced, PG&E performed a detailed component-specific engineering evaluation of the domestic water piping in the auxiliary building. PG&E is still in the process of finalizing these component-engineering evaluations of the domestic water piping in

Enclosure 1 PG&E Letter DCL-16-023 Page 4 of 24 the auxiliary building. Thus, PG&E has not yet determined whether this evaluation will support removing nonsafety-related SSCs from the scope of license renewal.

No other component specific engineering evaluations have been performed to date.

(3) The only nonsafety-related SSCs for which component-specific engineering evaluations were performed were the domestic water piping. Because these engineering evaluations are still in process and have not been finalized to-date, there have been no changes to conclusions than those originally documented in the LRA. Any components removed from the scope of license renewal will be evaluated in accordance with 10 CFR 54.4(a)(2) and the associated LRA changes will be submitted to the Nuclear Regulatory Commission (NRC) as part of the annual update.

RAJ B2. 1. 13-5a

Background:

By letter dated October 21, 2015, PG&E responded to RAJ 82.1.13-5 by discussing corrective actions taken in the Fire Water System program for past occurrences of recurring internal corrosion (RIC). These actions included the development of long-term plans for monitoring and replacement of corroded piping with new corrosion-resistant piping and the use of high quality reverse osmosis water in the fire water system with chemistry controls to mitigate against corrosion starting in 2008. With respect to RIC, PG&E stated that augmented inspections are not necessary because follow-up inspections conducted since implementation of the corrective actions demonstrate the adequacy of the corrective actions.

Issue:

The RAJ asked that a discussion be included about the trend for internal corrosion occurrences in the fire protection system to show that the program adequately manages recurring aging effects. However, the response did not provide any trend information to demonstrate the adequacy of the corrective actions or identify the corrosion mechanism resulting in RIC. If the trend for internal corrosion occurrences has not decreased or the follow-up inspections were not conducted on piping prone to RIC (e.g. conducting follow-up inspections on random locations when the corrosion mechanism resulting in RIC does not affect the system uniformly), then it is unclear to the staff how the adequacy of the past corrective actions has been demonstrated, and whether augmented inspections are necessary.

Enclosure 1 PG&E Letter DCL-16-023 Page 5 of 24 Request:

Identify the corrosion mechanism resulting in RIC and describe the follow-up inspections that have been conducted since the implementation of corrective actions to demonstrate the adequacy of the corrective actions. Include trend data for internal corrosion occurrences in the fire water system to show that the program adequately manages recurring aging effects. If the trend for internal corrosion occurrences in the fire water system is not decreasing, then provide justification why augmented inspections are not warranted to address recurring internal corrosion.

PG&E Response to RAI 82.1.13-5a This response supersedes the previous licensing basis on this topic as described in PG&E Letters DCL-14-103 and DCL-15-121. The RIC is general and pitting corrosion.

PG&E completed an engineering evaluation of previous failures in the fire water system to determine what corrective actions were necessary. The engineering evaluation included an assessment of wall thickness monitoring data to determine corrosion rates, baselining of wall thickness, and identified areas for piping replacement. As discussed in PG&E letter DCL-15-121, PG&E began an ongoing firewater piping replacement initiative. This ongoing initiative includes development of long-term plans for monitoring and replacement of corroded fire water piping that has not yet been replaced.

As discussed in PG&E Letters DCL-14-103 and DCL-15-121, PG&E performed an operating experience review of the fire water system and identified RIC. Since 2013, Diablo Canyon Power Plant (DCPP) has experienced no internal corrosion occurrences/

in the fire water system that meet the definition of RIC. Since beginning implementation of the corrective actions discussed in RAI response 82.1.13-5 in PG&E Letter DCL 121, there has been a decrease in system sedimentation and fire pump supply pressure testing has shown improved performance.

PG&E will continue to monitor the fire water system as described in the LRA. As discussed above, when the fire water piping replacement has been completed, PG&E will evaluate the effectiveness of these corrective actions to address the previous RIC operating experience. PG&E will implement the augmented inspections described below in the five years prior to period of extended operation (PEO). This will ensure that the RIC corrective actions are effective prior to entering the PEO.

• Loss of material will be monitored using ultrasonic testing (UT) examinations.

Representative inspection sites will be selected based on pipe configuration, flow conditions, operating history (known degradation or leakage), and will be updated periodically based on operating experience.

Enclosure 1 PG&E Letter DCL-16-023 Page 6 of 24

• The UT measurements will be compared to the nominal pipe wall thickness for initial measurements or to previous thickness measurements to determine rates of corrosion and the estimated time to reach minimum wall thickness.

• If UT ~xamination results indicate that the component did not meet DCPP acceptance criteria or is experiencing a reduction in wall thickness greater than 50 percent regardless of the minimum wall thickness, the issue will be entered into the CAP for resolution. PG&E will consider multiple RIC locations in the technical evaluation of the structural integrity of the pipe when identified by the volumetric RIC inspections.

• A minimum of 5 RIC UT examinations will be conducted per year until the rate of RIC occurrences no longer meets the criteria for RIC. If more than one RIC-caused leak or wall thickness less than minimum allowable wall thickness is identified in the annual inspection period, an additional 5 RIC UT examinations over the following 12-month period will be performed for each RIC leak or finding_

of wall thickness less than minimum allowable wall thickness. The total number of inspections need not exceed 25 RIC inspections per year.

• The cause of any newly identified RIC will be entered into the CAP for further evaluation and corrective actions.

• Perform internal visual inspections during opportunistic inspections The combination of continued piping replacement, monitoring of more specific trending criteria in the quarterly system health report, and implementation of augmented inspections beginning five years prior to PEO will ensure that the Fire Water System Program (82.1.13) is effective in preventing RIC prior to entering the PEO.

See revised LRA, Table A4-1, Item 3 in Enclosure 3.

RAJ 82.1.15-3

Background:

7 of the applicant's 2014 annual update (December 22, 2014) states that the Unit 2 capsules with the highest effective full power years are Capsules V, W, and Z. These capsules have a neutron fluence greater than 50 percent of the projected reactor vessel neutron fluence at the end of the PEO. Unit 2 Capsule V was removed in refueling outage 9 (2R9) at 52.5 effective full power years (EFPY) and tested. Unit 2 Capsules Wand Z were also removed in 2R9 at 61.5 EFPY. All these capsules are in storage.

Enclosure 1 PG&E Letter DCL-16-023 Page 7 of 24 Generic Aging Lessons Learned (GALL) Report, Rev. 2, aging management program (AMP) XI. M31 ({Reactor Vessel Surveillance," states that the plant-specific or integrated surveillance program shall have at least one capsule with a projected neutron fluence equal to or exceeding the 60-year peak reactor vessel wall neutron fluence prior to the end of the period of extended operation. The GALL Report also states that the program withdraws one capsule at an outage in which the capsule receives a neutron fluence of between one and two times the peak reactor vessel wall neutron fluence at the end of the period of extended operation and tests the capsule in accordance with the

• requirements of ASTM E 185-82 Issue:

The staff noted that UFSAR Table 5.2-22, ({Reactor Vessel Material Surveillance Program Withdrawal Schedule," states that Capsules Wand Z for Unit 2 were removed during refueling outage 9. It is unclear to the staff whether or not one of the 61.5 EFPY capsules (either Capsule Wor Z) will be tested in accordance with the requirements of ASTM E 185-82.

Request:

State whether or not one of the 61.5 EFPY capsules (either Capsule W or Z) will be tested in accordance with the requirements of ASTM E 185-82, for the purpose of license renewal. If not, justify why neither capsule will be tested.

PG&E Response to RAI 82.1.15-3 As described above, NUREG-1801, Revision 2, XI.M31 states that the plant-specific or integrated surveillance program shall have at least one capsule with a projected neutron fluence equal to or exceeding the 60-year peak reactor vessel wall neutron fluence prior to the end of the PEO. NUREG-1801 also states that the program withdraws one capsule at an outage in which the capsule receives a neutron fluence of between one and two *times the peak reactor vessel wall neutron fluence at the end of the PEO and tests the capsule in accordance with the requirements of American Society for Testing and Materials (ASTM) E 185-82. The requirements for NUREG-1801, Revision 2, XI.M31 are met for DCPP Unit 2 as described below.

Although the DCPP Updated Final Safety Analysis Report (UFSAR) Table 5.2-22 states that Unit 2 Capsule V was removed at 52.5 effective full power years (EFPY), this EFPY value does not account for the high-leakage loading patterns in Cycles 1-3, which are not representative of current and future loading patterns. Thus, the value of 52.5 EFPY is not representative of the actual capsule exposure EFPY.

As shown in DCPP UFSAR Table 5.2-22, the fluence at the center of Unit 2 Capsule V was 2.38 x1 019 n/cm 2 . The projected peak reactor vessel fluence (at the clad-base 19 metal interface) for Unit 2 is 2.25 x10 19 at 54 EFPY and 2.49 x10 at 60 EFPY. The

Enclosure 1 PG&E Letter OCL-16-023 Page 8 of 24 actual Capsule V fluence, therefore, interpolates to 57.25 EFPY, which corresponds to 60 years of operation with a capacity factor of 95.4 percent.

Because Unit 2 Capsule V meets the requirements for NUREG-1801, Revision 2, XI.M31, Unit 2 Capsules Wand Z will not be tested for the purposes of license renewal.

RAJ 82. 1. 18-4a

Background:

The response to RAJ 82. 1. 18-4, dated October 21, 2015, states an alternative to qualification of individuals responsible for determining the type and extent of coating degradation for buried piping to NA CE (formerly known as the National Association of Corrosion Engineers) or Electric Power Research Institute (EPRI) qualifications. The alternative is to use inspectors qualified to ASTM 04537, "Standard Guide for Establishing Procedures to Qualify and Certify Personnel Performing Coating and Lining Work Inspection in Nuclear Facilities."

Issue:

The staff noted that ASTM 04537 is endorsed by RG 1.54, "Service Levell, II, and Ill Protective Coatings Applied to Nuclear Power Plants." LR-/SG-2013-01, ('Aging Management of Loss of Coating or Lining Integrity for Internal Coatings/Linings on In-Scope Piping, Piping Components, Heat Exchangers, and Tanks," recommends that a coating specialist be used to assess degraded coatings.

Request:

State the basis for using an individual qualified to conduct inspections to assess the type and extent of coating degradation.

PG&E Response to RAI B2.1.18-4a Individuals responsible for conducting coating inspections for the Buried Piping and Tanks Inspection Program (82.1.18) will be qualified in accordance with ASTM 04537, which is endorsed by NRC Regulatory Guide (RG) 1.54. The individuals responsible for assessing the type and extent of coating degradation will be qualified in accordance with ASTM 07108-05, which is also endorsed by NRC RG 1.54.

See revised LRA, Section A1.18 and Table A4-1, Item 52, as shown in Enclosure 3.

Enclosure 1 PG&E Letter DCL-16-023 Page 9 of 24 RAJ B2.1.18-5a

Background:

The response to RAJ B2.1.18-5, dated October 21, 2015, states:

As stated in PG&E Letter DCL-14-1 03, Enclosure 1, Attachment 3, item 11, the buried piping encased in concrete for which PG&E states no aging effect requiring management is the ASW discharge piping. There is reasonable assurance that the exterior surface of the buried ASW piping encased in concrete will continue to perform its intended function during the period of extended operation consistent with the current licensing basis because the piping is encased in structural concrete. The ASW piping encased in concrete meets American Concrete Institute (ACI) 318. Cracking of this concrete is controlled through proper arrangement and distribution of reinforcing steel and is constructed of a dense, well-cured concrete with an amount of cement suitable for strength development, and achievement of a water-to-cement ratio which is characteristic of concrete having low permeability. This is consistent with the recommendations and guidance provided by ACI. In addition, the ASW discharge piping is located approximately 57 feet above the anticipated high ground water elevation.

Issue:

Although the concrete, consistent with the GALL Report, meets AC/318 and the pipe is well above the anticipated high ground water elevation, the piping is buried in soil that is exposed to rainwater. LR-/SG-2011-03, "Changes to the Generic Aging Lessons Learned (GALL) Report Revision 2 Aging Management Program XI.M41, 'Buried and Underground Piping and Tanks'," recommends that the top surfaces and at least 50 percent of the side surface of concrete (in soil) surrounding piping be visually inspected for cracks in the concrete that could admit groundwater to the external surfaces of the piping.

Request:

State the basis for why inspections are not proposed to verify that cracking is not occurring in the concrete surrounding buried piping encased in concrete.

PG&E Response to RAI 82.1.18-Sa As stated above and in PG&E Letter DCL-15-121, the buried auxiliary saltwater (ASW) discharge piping encased in concrete meets American Concrete Institute (ACI) 318.

Cracking of this concrete is controlled through proper arrangement and distribution of reinforcing steel and is constructed of a dense, well-cured concrete with an amount of cement suitable for strength development, and achievement of a water-to-cement ratio

Enclosure 1 PG&E Letter DCL-16-023 Page 10 of 24 which is characteristic of concrete having low permeability. In addition, the ASW discharge piping is located approximately 57 feet above the high ground water elevation.

The buried ASW discharge piping encased in concrete is located under asphalt pavement that is sloped to allow for adequate drainage. The asphalt extends well past the ASW discharge piping encased in concrete. Because the pavement provides protection from significant rainwater intrusion, inspections are not proposed to verify that cracking is not occurring in the concrete surrounding this buried piping encased in concrete. In addition, the subject piping is externally coated with two coats of coal tar epoxy with an embedded layer of 6 ounce treated square woven fiberglass cloth.

RAI3.0.3.2.6-2a

Background:

The response to RAJ 3.0.3.2.6-2, dated October 21, 2015, states that for fire water storage tanks, 7i]f adverse wall thickness trends are identified during routine inspections such that minimum wall thickness is projected to be reached prior to the next scheduled inspection (currently every 5 years), then the tank will be drained down, the 6 tests specified in NFPA-25, Section 9.2. 7 will be performed, corroded base metal will be restored, and degraded coatings will be repaired."

Issue:

The lack of adverse wall thickness measurements is not a sufficient basis to conclude that the coating tests cited in NFPA 25 Section 9.2. 7 are not required. Degraded coatings in and of themselves can cause a loss of intended function due to downstream flow blockage.

Request:

State the basis for why the lack of adverse wall thickness measurements is a sufficient criterion to conclude that degraded coating testing may not be required.

PG&E Response to RAI 3.0.3.2.6-2a The following updates information provided in PG&E Letters DCL-14-103, DCL-15-121, and DCL-15-027, "Update to the Diablo Canyon Power Plant License Renewal Application (LRA), Amendment 49 and LRA Appendix E, 'Applicant's Environmental Report- Operating License Renewal Stage,' Amendment 2," dated February 25, 2015.

As discussed in PG&E Letter DCL-14-103, Enclosure 1, Attachment 7C, Exception 5, and in PG&E Letter DCL-15-121, Enclosure 1 in response to RAI 3.0.3.2.6-2, PG&E will perform diver inspections of the fire water storage tank every 5 years, enter degradation found during inspections of the fire water storage tank into the CAP, and an engineering

Enclosure 1 PG&E Letter OCL-16-023 Page 11 of 24 evaluation will be performed to determine whether further actions are required. The diver inspections will include use of tools necessary to adequately conduct inspection for aging mechanisms (e.g., adequate lighting will be provided). The evaluation will include tank wall thickness as discussed in PG&E Letter OCL-15-121, and coating acceptability in accordance with PG&E's evaluation of LR-ISG-2013-01, as discussed in PG&E Letter OCL-15-027, Enclosure 1. In PG&E Letter OCL-15-027, with respect to the fire water storage tank internal coating, PG&E committed to enhancing the Fire Water Program (82.1.13) to include the relevant recommendations associated with training and qualification of personnel, acceptance criteria, and corrective actions from LR-ISG-2013-01, Appendix C. These corrective actions will ensure that degraded fire water storage tank coatings do not cause a loss of intended function due to downstream flow blockage.

PG&E clarifies the PG&E Letter OCL-15-027 licensing basis to indicate that individuals responsible for conducting coating inspections will be qualified in accordance with ASTM 04537, which is endorsed by the NRC RG 1.54. The individuals responsible for assessing the type and extent of coating degradation will be qualified in accordance with ASTM 07108-05, which is also endorsed by the NRC RG 1.54.

See LRA, SectionsA1.13, A1.18, and A1.42, and TableA4-1, Items 3, 52, and 74 as shown in Enclosure 3.

RAI3.4.2.3.1-1a

Background:

As amended by letter dated October 21, 2015, LRA Table 3.4.2-1 states that internally coated/lined carbon steel piping, valves, and tanks exposed to demineralized water may be temporarily exposed to sulfuric acid in the steam generator blowdown treatment demineralizer system. The letter states that the sulfuric acid concentration would be between 4 and 96 percent, flowing up to a rate of 24.5 gallons per minute at ambient temperature. The linings used in the system are polypropylene, ethylene, fluorinated ethylene propylene, and semi-hard rubber.

ASM Handbook, Volume 13C, states that polyethylene is compatible with sulfuric acid up to 98 percent concentration at ambient temperature for short durations of service, that fluorinated ethylene propylene is compatible with all concentrations of sulfuric acid up to 205 oc, and that polypropylene is used in linings for pipe that handles sulfuric acid. ASM Handbook, Volume 13C, did not provide information on the compatibility of semi-hard rubber and sulfuric acid.

Corrosion Resistant Linings and Coatings by Philip A. Schweitzer (2001) states that semi-hard natural rubber is compatible with sulfuric acid at 10 percent concentration up to 82 oc, compatible with sulfuric acid at 50 percent concentration up to 38 oc, and incompatible with sulfuric acid at concentrations of 70, 90, and 98 percent.

Enclosure 1 PG&E Letter DCL-16-023 Page 12 of 24 As amended by letter dated October 21, 2015, internally coated/lined carbon steel components in the steam generator blowdown treatment demineralizer system were evaluated and determined to meet the six alternative inspection criteria of LR-/SG-2013-01, '~ging Management of Loss of Coating or Lining Integrity for Internal Coatings/Lining on In-Scope Piping, Piping Components, Heat Exchangers and Tanks,"

and will now be managed using the Inspection of Internal Surfaces of Miscellaneous Piping and Ducting Components program. The fourth alternative inspection criteria listed in LR-/SG-2013-01 states "[t]he internal environment would not promote microbiologically-influenced corrosion (MIG) of the base metal."

EPRI Report 1010639, "Non-Class 1 Mechanical Implementation Guideline and Mechanical Tools," Revision 4, states "[a)/though MIG is not probable in treated water systems it cannot be categorically excluded due to the potential for contamination and subsequent damage if left untreated."

Issue:

1. Although components in the steam generator blowdown treatment demineralizer system would only be exposed to sulfuric acid in the event of a steam generator tube rupture or significant steam generator tube leak, lining systems should be compatible with sulfuric acid at the specified operating conditions for short durations of service. The staff has reviewed ASM Handbook, Volume 13, and has concluded that polypropylene, polyethylene, and fluorinated ethylene propylene linings would be compatible with sulfuric acid at the specified operating conditions.

The staff could not determine if the use of the term 'ethylene' in letter dated October 21, 2015, refers to polyethylene and could therefore not determine if this lining is adequate for the sulfuric acid operational environment. Furthermore, the staff could not determine whether semi-hard rubber would be compatible with the sulfuric acid operational environment based on review of the ASM Handbook and Corrosion Resistant Linings and Coatings by Philip A. Schweitzer (2001).

2. The staff notes that MIG is not addressed in GALL Report, Revision 2, for carbon steel exposed to treated water. However, the staff has concluded that MIG is an applicable aging effect for carbon steel exposed to treated water. It is unclear to the staff why MIG is not an applicable aging effect for this material/environment combination.

Enclosure 1 PG&E Letter DCL-16-023 Page 13 of 24 Request:

1. State whether the use of the term ethylene in letter dated October 21, 2015 refers to polyethylene. If not, justify why the Internal Surfaces in Miscellaneous Piping and Dueling Components program is adequate such that the intended function of ethylene lined carbon steel piping, valves, and tanks exposed to sulfuric acid for short durations will be maintained.

Justify why the Internal Surfaces in Miscellaneous Piping and Ducting Components program is adequate such that the intended function of semi-hard rubber lined carbon steel piping, valves, and tanks exposed to sulfuric acid for short durations will be maintained.

2. In order to determine if the six alternative inspection criteria of LR-ISG-2013-01 are met, state the basis for why MIG is not an applicable aging effect for carbon steel exposed to demineralized water in the Turbine Steam Supply System.

PG&E Response to RAI 3.4.2.3.1-1a Request 1:

Ethylene and polyethylene materials are not used for lining in the steam generator blowdown (SGBD) treatment demineralizer system. The linings used in the SGBD treatment demineralizer system consist of polypropylene, fluorinated ethylene propylene, and semi-hard rubber.

The demineralizers and the acid day tank in the SGBD treatment demineralizer system are the only components with a rubber liner material that are exposed to acid.

The SGBD treatment demineralizer system was designed so that the acid day tank with a rubber lining could be filled with a 96 percent sulfuric acid solution and the rubber liner of the SGBD treatment demineralizer could be exposed to a 4 percent solution of sulfuric acid for about 40 minutes a week while it was in operation. The acid was used to regenerate the demineralizer resin and then it was to be sent to the demineralizer regenerant receiver tank for storage. The DCPP UFSAR states that changes in the California Environmental Protection Agency regulations halted the neutralization of regenerants in the demineralizer regenerate receiver tanks. As discussed in the DCPP UFSAR, upon ion exchange exhaustion, the mixed bed demineralizer resin is replaced with new resin (i.e., the resin will not be regenerated). Since the SGBD treatment demineralizer resin will not be regenerated, the acid day tank will not be filled with acid.

Also, the acid and caustic supplies to the SGBD treatment demineralizer acid and caustic day tanks have been abandoned in place. Filling the acid day tank would require a design change. The regeneration portion of the SGBD treatment

Enclosure 1 PG&E Letter DCL-16-023 Page 14 of 24 demineralizer system with lined carbon steel piping, piping components, and tanks containing acid and caustic was flushed, neutralized, and laid up with nitrogen. There are a few stainless steel instrument and drain lines that may still contain acid or caustic.

In summary, the SG8D treatment demineralizer system will remain filled with demineralized water (NUREG-1801 treated water environment, see DCPP LRA Table 3.0-1), nitrogen, or plant indoor air and will not be filled with acid or caustic. The stainless steel lines exposed to acid or caustic will maintain an evaluated environment of NaOH (lnt) or Sulfuric Acid (lnt). The acid day tank was flushed, neutralized and laid up with nitrogen. The acid day tank has a vent to the atmosphere, so the internal environment of the tank is considered to be plant indoor air (lnt). The Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components (82.1.22) is the program used in the DCPP LRA for managing carbon steel components with an environment of plant indoor (lnt).

While evaluating this RAI, PG&E identified additional changes to component environments that were necessary to align LRA Table 3.4.2-1 with actual plant configuration of the SG8D treatment demineralizer system described above.

See LRA, Section 3.4.2.2.2.1, and Tables 3.4.1 and 3.4.2-1 as shown in Enclosure 3.

Request 2:

EPRI Report 1010639, "Non-Class 1 Mechanical Implementation Guideline and Mechanical Tools," Revision 4, indicates that microbiological induced corrosion (MIC) can occur in a wide variety of chemical environments, temperatures, in oxygen rich or depleted environments, and the microorganisms can metabolize various different substances. The guidance indicates that MIC is not likely in treated water systems, but contamination of the treated water system can lead to MIC. A review of operating experience of the SG8D treatment dem'ineralizer system did not identify any indications of MIC. However, PG&E is conservatively assuming that contamination in the system with substances which would promote MIC may be present, and is revising the licensing basis in Enclosure 1 of PG&E Letter DCL-15-121 to manage aging of the coated/lined piping, piping components, and tanks with an internal environment of demineralized water in the SG8D treatment demineralizer system using the Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks Program (82.1.42).

See LRA, Section 3.4.2.2.2.1, and Tables 3.4.1 and 3.4.2-1 as shown in Enclosure 3.

Enclosure 1 PG&E Letter DCL-16-023 Page 15 of 24 RAJ 3.4.2.3.1-3a

Background:

By Jetter dated September 24, 2015, RAJ 3.4.2.3.1-3 requested further information on coated/lined carbon steel piping, valves, and demineralizers exposed to secondary water in the turbine steam supply (LRA Table 3.4.2-1) and condensate systems (LRA Table 3.4.2-4).

Issue:

By letter dated October 21, 2015, the response to RA/3.4.2.3.1-3 does not address coated/lined carbon steel demineralizers exposed to secondary water in the condensate system (LRA Table 3.4.2-4).

Request:

Explain why coated/lined carbon steel demineralizers exposed to secondary water in the condensate system (LRA Table 3.4.2-4) are not addressed in the response to RAJ 3.4.2.3.1-3.

PG&E Response to RAI 3.4.2.3.1-3a NUREG-1801, Chapter IX.D, Revisions 1 and 2 define secondary feedwater as pressurized water reactor feedwater or steam at or near full operating temperature.

DCPP LRA Table 3.0-1 defines secondary water as steam, treated water, treated water greater than 60°C, secondary feedwater/steam, and secondary feedwater. Since the DCPP main feedwater system maximum design temperature is approximately 437°F, and the secondary water in the condensate polisher demineralizers is operated at approximately 100°F, the internal environment of the condensate polisher demineralizers is equivalent to the NUREG-1801, Chapter IX.D definition of treated water. The liner used for the condensate polisher demineralizers is made of rubber.

The ASM Handbook, Volume 138 indicates that rubber is adequate for use at temperatures below 150°F. The lined condensate polisher demineralizers are managed by the Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks Program (82.1.42).

PG&E revises LRA Table 3.4.2-4 in Enclosure 3 by revising a plant-specific note to clarify that the LRA-evaluated environment of secondary water for the condensate polisher demineralizers represents the NUREG-1801 environment of treated water.

Enclosure 1 PG&E Letter DCL-16-023 Page 16 of 24 RAI4.2.1-2

Background:

of the applicants 2011 annual update (December 21, 2011) indicates that for both units, the nozzle shell course and the associated nozzle shell to intermediate shell weld are projected to exceed the 1x10 17 nlcm2 threshold. The applicant also stated, however, that the nozzles themselves as well as the nozzle to nozzle shell welds remain below the 1x1017 n/cm2 threshold through 54 effective full-power year (EFPY).

Issue:

It is not clear to the staff why the nozzle shell course and the associated nozzle shell to intermediate shell weld are projected to exceed 1x1017 nlcm2 while the nozzles themselves, the nozzle to nozzle shell welds, and the lower shell to lower head weld remain below the 1x1017 nlcm2 threshold through 54 EFPY.

Request:

Identify the specific nozzles and nozzle-to-nozzle weld components that are being referred to in the above statement and identify what the inside surface neutron f/uences are for these components, as projected to 54 EFPY. If any of the neutron fluences for these components are projected to exceed a value of 1x10 17 nlcm2 (E > 1.0 MeV) at 54 EFPY, provide the associated pressurized thermal shock (PTS) and upper shelf energy (USE) calculations for the components at 54 EFPY.

PG&E Response to RAI 4.2.1-2:

The 54 EFPY maximum fast neutron fluences for the Unit 1 and Unit 2 nozzles, nozzle to nozzle shell welds, and lower shell to lower head welds are provided below.

Fluence (n/cm 2 )

Material Unit 1 Unit 2 54 EFPY 54 EFPY Nozzle Shell to Intermediate Shell Circumferential Weld 3.41 x10 17 6.77 x10 17 (Unit 1 8-442; Unit 2 8-201)

Nozzle Shell Plates 1, 2, and 3 3.41 x10 17 6.77 x1 0 17 Nozzle Shell Longitudinal Welds Weld 1 (Unit 1 1-4428; Unit 2 1-201A) 1.49 x1 0 17 6.33 x10 11 Weld 2 (Unit 1 1-442C; Unit 2 1-201 B) 3.06 x1 0 11 6.29 x10 11 1

Weld 3 (Unit 1 1-442A; Unit 2 1-201 C) 2.45 x10 ' 5.14 x1 01(

Intermediate Shell Plates Unit 1 Plates 1, 2, and 3 (841 06-3, 84106-2, and 2.02 x1 0 19 NA 84106-1)

Unit 2 Plates 1, 2, and 3 (85454-2, 85454-3, and NA 2.25 x10 19 85454-1)

Enclosure 1 PG&E Letter DCL-16-023 Page 17 of 24 Fluence (n/cm 2 )

Material Unit 1 Unit2 54 EFPY 54 EFPY Intermediate Shell Longitudinal Welds Weld 1 (Unit 1 2-442B; Unit 2 2-201A) 1.49 x1 0 HI 1.24 x1 0 1 !:1 Weld 2 (Unit 1 2-442C; Unit 2 2-201 B) 7.68 X10HS 1.53 x1 0 1 !:1 Weld 3 (Unit 1 2-442A; Unit 2 2-201 C) 1.49 x1 0 1 !:1 1.30 x1 0 1 !:1 Intermediate Shell to Lower Shell Circumferential Weld 2.01 x10 19 2.22 x10 19 (Unit 1 9-442; Unit 2 9-201)

Lower Shell Plates 1 , 2, and 3 Unit 1 Plates 1, 2, and 3 (B41 07-2, B41 07-3, and 2.01 x10 19 NA B4107-1)

Unit 2 Plates 1, 2, and 3 (B5455-2, B5455-1, and NA 2.22 x10 19 B5455-3)

Lower Shell Longitudinal Welds Weld 1 (Unit 1 3-442B; Unit 2 3-201A) 1.19x10 1 !j 1.28 x10 1 !j Weld 2 (Unit 1 3-442C; Unit 2 3-201 B) 2.01 x1 0 1 !:1 1.23 x1 0 1 !:1 Weld 3 (Unit 1 3-442A; Unit 2 3-201 C) 1.19x10 1 !j 1.51 x10 1 !j Lower Shell to Lower Vessel Head Circumferential Weld 4.46 x1 0 15 1.87 x1 0 15 (Unit 1 10-442; Unit 2 10-201)

NA =not applicable Note: the terms "nozzle plate" and "shell plate" are used interchangeably.

As shown above, the nozzle shell plates, nozzle shell longitudinal welds, and nozzle shell to intermediate shell circumferential welds have projected 54 EFPY fluences above the 1x1017 n/cm 2 threshold.

The associated pressurized thermal shock (PTS) and upper shelf energy (USE) 2 calculations for the components projected to exceed the 1x1017 n/cm threshold are shown in LRA Tables 4.2-4 through 4.2-7. Information related to the subject locations is extracted from these LRA tables and is presented in the tables below.

Enclosure 1 PG&E Letter DCL-16-023 Page 18 of 24 Excerpt from LRA Table 4.2-4 DCPP Unit 1 Vessel RTPTs at 54 EFPY Chemical EOLE Material Description R.G Chemistry Initial Screening Extended 1.99, Composition Fluence Fluence ~RTNoT Margin RTPTS Factors RTNDT 19 Criteria Beltline Rev.2 OF OF 10 n/cm 2 Factor OF OF OF OF Heat Cu Ni Region Location Type Position E>1.0 MeV No. Wt% Wt%

Upper Shell to Intermediate Linde Shell 13253 1.1 0.25 0.730 197.5 -56 0.0341 0.2365 46.7 57.8 48  :=:;300 Yes 1092 Circumferential Weld 8-442 Upper Shell  :=:;270 C2624 A5338 1.1R 0.120 0.56 82 .2 28 0.0341 0.2365 19.4 39.2 87 Yes Plate 84105-1 Upper Shell C2624-2 A5338 1.1 0.120 0.57 82.4 9 0.0341 0.2365 19.5 39.2 68 S270 Yes Plate 841 05-2 Upper Shell C2608-A5338 1.1 0.140 0.56 98.2 14 0.0341 0.2365 23.2 41 .2 78 S270 Yes Plate 841 05-3 28 Upper Shell 27204/ Linde Long. Weld 1.1 0.190 0.970 215.7 -20 0.0245 0.1948 42 42.0 64 S270 Yes 12008 1092 1-442 A Upper Shell 27204/ Linde  :=:;270 Long. Weld 1.1 0.190 0.970 215.7 -20 0.0149 0.1428 30.8 30.8 42 Yes 12008 1092 1-442 8 Upper Shell 27204 I Linde Long. Weld 1.1 0.190 0.970 215.7 -20 0.0306 0.2222 47.9 47.9 76 S270 Yes 12008 1092 1-442 c Intermediate Shell Plate C2884-1 A5338 1.1 0.125 0.53 85.3 -10 2.02 1.1917 101.7 34 126 S270 No 84106-1 Intermediate Shell Plate C2854-2 A5338 1.1 0.12 0.50 81 -3 2.02 1.1917 96.5 34 128  :=:;270 No 84106-2 Intermediate Shell Plate C2793-1 A5338 1.1 0.086 0.476 55.2 30 2.02 1.1917 65.8 48.1 144 S270 No 84106-3 Intermediate Linde Shell Long. 27204 1.1 0.203 1.018 226.8 -56 1.49 1.1104 251.8 65.5 261  :=:;270 No 1092 Welds 2-442A, 8

~using credible Linde 27204 2.1 0.203 1.018 214.1 -56 1.49 1.1104 237.7 44.0 226  :=:;270 No I

surveillance data 1092 I Intermediate Linde Shell Long. Weld 27204 1.1 0.203 1.018 226.8 -56 0.768 0.9259 210.0 65.5 220 S270 No 1092 I

2-442C

~using credible Linde 27204 2.1 0.203 1.018 214.1 -56 0.768 0.9259 198.2 44.0 186  :=:;270 No surveillance data 1092 - - - - - - - -- - *- - - -

Enclosure 1 PG&E Letter DCL-16-023 Page 19 of 24 Chemical EOLE Material Description R.G Chemistry Initial Screening Extended 1.99, Composition Fluence Fluence ~RTNoT Margin RTPTS Factors RTNDT 19 2 OF OF Criteria Beltline Rev.2 Cu Ni OF OF 10 n/cm Factor OF OF Heat Region Location Type Position E>1.0 MeV No. Wt% Wt%

Intermediate to Lower Shell Linde  ::;300 21935 1.1 0.183 0.704 172.2 -56 2.01 1.1904 205.0 65.5 215 No Circumferential 1092 Weld 9-442 Lower Shell  ::;270 C3121-1 A5338 1.1 0.13 0.56 89.8 15 2.01 1.1904 106.9 34 156 No Plate 84107-1 Lower Shell  ::;270 C3131-2 A5338 1.1 0.12 0.56 82.2 20 2.01 1.1904 97.9 34 152 No Plate 841 07-2 Lower Shell  ::;270 C3131-1 A5338 1.1 0.12 0.52 81.4 -22 2.01 1.1904 96.9 34 109 No Plate 841 07-3 Lower Shell Linde  ::;270 Long. Welds 3- 27204 1.1 0.203 1.018 226.8 -56 1.19 1.0485 237.8 65.5 247 No 1092 442A, 8

---!-Using credible Linde 27204 2.1 0.203 1.018 214.1 -56 1.19 1.0485 224.5 44.0 213  ::;270 No surveillance data 1092 Lower Shell Linde  ::;270 Long. Weld 3- 27204 1.1 0.203 1.018 226.8 -56 2.01 1.9404 270.0 65.5 280 No 1092 442C

---!-Using credible Linde  ::;270 27204 2.1 0.203 1.018 214.1 -56 2.01 1.1904 254.9 44.0 243 No surveillance data 1092 - ------

L_ _ _ _ _

EOLE = end-of-license extended Excerpt from LRA Table 4.2-5 DCPP Unit 2 Vessel RTPTS at 54 EFPY Chemical EOLE Material Description R.G Chemistry Initial Screening Extended 1.99, Composition Fluence Fluence ~RTNoT Margin RTPTS Factors RTNDT 19 2 Criteria Beltline Rev.2 10 n/cm Factor OF OF OF Heat Cu Ni OF OF OF Region Location Type Position E>1.0 MeV No. Wt% Wt%

Upper Shell to Intermediate Linde  ::;300 Shell 21935 1.1 0.183 0.704 172.2 -56 0.0677 0.3434 59.1 65.5 69 Yes 1092 Circumferential Weld 8-201 Upper Shell C5162-1 A5338 1.1 0.110 0.600 74 28 0.0677 0.3434 25.4 25.4 79  ::;270 Yes Plate 85453-1 Upper Shell  ::;270 C5162-2 A5338 1.1 0.110 0.600 74 5 0.0677 0.3434 25.4 42.4 73 Yes Plate 85453-3 Upper Shell  ::;270 C4377-1 A5338 1.1 0.110 0.650 74.8 0 0.0677 0.3434 25.7 42.6 68 Yes Plate 85011-1 R

Enclosure 1 PG&E Letter DCL-16-023 Page 20 of 24 Chemical EOLE Material Description R.G Chemistry Initial Screening Composition ~RTNoT Extended 1.99, Fluence Fluence Margin RTPTS Factors RTNDT 19 2 OF OF Criteria Beltline Rev.2 *oF OF 10 n/cm Factor OF Heat Cu Ni OF Region Location Type Position E>1.0 MeV No. Wt% Wt%

Upper Shell 21935/ Linde Long. Weld 1.1 0.220 0.870 211.2 -50 0.0633 0.3317 70.1 56.0 76 =:;270 Yes 12008 1092 1-201 A

~using credible 21935/ Linde 2.1 0.220 0.870 204.6 -50 0.0633 0.3317 67.9 28 46 =:;270 Yes surveillance data 12008 1092 Upper Shell 21935/ Linde Long. Weld 1.1 0.220 0.870 211.2 -50 0.0629 0.3306 69.8 56.0 76 =:;270 Yes 12008 1092 1-201 8

~using credible 21935/ Linde 2.1 0.220 0.870 204.6 -50 0.0629 0.3306 67.6 28 46 =:;270 Yes surveillance data 12008 1092 Upper Shell 21935/ Linde Long. Weld 1.1 0.220 0.870 211 .2 -50 0.0514 0.2971 62.7 56 69 S270 Yes 12008 1092 1-201 c

~using credible 21935/ Linde 2.1 0.220 0.870 204.6 -50 0.0514 0.2971 60.8 28 39 =:;270 Yes surveillance data 12008 1092 Intermediate Shell Plate C5161-1 A5338 1.1 0.140 0.650 101.3 52 2.25 1.2196 123.5 34 210 S270 No 85454-1

~using credible C5161-1 A5338 2.1 0.140 0.650 105.7 52 2.25 1.2196 128.9 17 198 S270 No surveillance data Intermediate Shell Plate C5168-2 A5338 1.1 0.14 0.59 99.6 67 2.25 1.2196 121.5 34 222 S270 No 85454-2 Intermediate Shell Plate C5161-2 A5338 1.1 0.15 0.62 110.5 33 2.25 1.2196 134.8 34 202 =:;270 No 85454-3 Intermediate 2193/ Linde Shell Long. Weld 1.1 0.22 0.87 211.2 -50 1.24 1.0599 223.9 56 230 =:;270 No 12008 1092 2-201A

~using credible 21935/ Linde 2.1 0.22 0.87 204.6 -50 1.24 1.0599 216.9 28 195 =:;270 No surveillance data 12008 1092 Intermediate 2193/ Linde Shell Long. Weld 1.1 0.22 0.87 211.2 -50 1.53 1.1176 236.0 56 242 =:;270 No 12008 1092 2-2018

~using credible 21935/ Linde 2.1 0.22 0.87 204.6 -50 1.53 1.1176 228.7 28 207 S270 No surveillance data 12008 1092 Intermediate 2193/ Linde Shell Long. Weld 1.1 0.22 0.87 211.2 -50 1.30 1.0730 226.6 56 233 =:;270 No 12008 1092 2-201C

~using credible 21935/ Linde 2.1 0.22 0.87 204.6 -50 1.30 1.0730 219.5 28 198 S270 No

'---5_L!rveilla_11ce data . 12008 1092 - - - - - - - - -- -- -

Enclosure 1 PG&E Letter DCL-16-023 Page 21 of 24 Chemical EOLE Material Description R.G Chemistry Initial Screening Extended 1.99, Composition Fluence Fluence ~RTNoT Margin RTPTS Factors RTNDT 19 2 OF OF Criteria Beltline Heat Rev.2 Ni OF OF 10 n/cm Factor OF OF Cu Region Location Type Position E>1.0 MeV No. Wt% Wt%

Intermediate to Lower Shell Linde 10120 1.1 0.046 0.082 34 -56 2.22 1.2161 41.3 53.5 39 :5300 No Circumferential 0091 Weld 9-201 Lower Shell C5175-1 A5338 1.1 0.14 0.56 98.2 -15 2.22 1.2161 119.4 34 138 :5270 No Plate 85455-1 Lower Shell C5175-2 A5338 1.1 0.14 0.56 98.2 0 2.22 1.2161 119.4 34 153 :5270 No Plate 85455-2 Lower Shell C5176-1 A 5338 1.1 0.1 0.62 65.~ 15 2.22 1.2161 79.3 34 128 :5270 No Plate 85455-3 Lower Shell Linde Long. Weld 3- 33A277 1.1 0.258 0.165 126.3 -56 1.28 1.0687 135.0 65.5 144 :5270 No 124 201A

-using credible Linde 33A277 2.1 0.258 0.165 115.9 -56 1.28 1.0687 123.9 44.0 112 :5270 No surveillance data 124 Lower Shell Linde Long. Weld 3- 33A277 1.1 0.258 0.165 126.3 -56 1.23 1.0577 133.6 65.5 143 :5270 No 124 2018

-using credible Linde 33A277 2.1 0.258 0.165 115.9 -56 1.23 1.0577 122.6 44.0 111 :5270 No surveillance data 124 Lower Shell Linde Long. Weld 3- 33A277 1.1 0.258 0.165 126.3 -56 1.51 1.1141 140.7 65.5 150 :5270 No 124 201C

-using credible Linde 33A277 2.1 0.258 0.165 115.9 -56 1.51 1.1141 129.1 44.0 117 :5270 No surveillance data 124 EOLE = end-of-license extended Excerpt from LRA Table 4.2-6 DCPP Unit 1 Reactor Vessel Material Cv USE at EOLE EOL %T EOL Cv USE 1

Material Description Unirradiated Projected Cu Fluence %Drop in Cv Acceptance CvUSE 19 2 CvUSE Reactor Vessel Beltline Region Heat wt% 10 n/cm USE Criterion '

Type ft-lbf ft-lbf ~

Location Number (E>1 MeV) ft-lbf Upper Shell to Intermediate Shell Weld 8-13253 Linde 1092 0.250 111 0.020 17 92.1 ~50 442 I I

Upper Shell Plate 841 05-1 C2624 A5338 0.120 80 0.020 8.6 73.1 ~50 Upper Shell Plate 841 05-2 C2624-2 A5338 0.120 74 0.020 8.6 67.6 ~50 L _ __ _ _ _

--- ---- --- - - - -

Enclosure 1 PG&E Letter DCL-16-023 Page 22 of 24 EOL%T EOL Cv USE Material Description Unirradiated Projected Cu Fluence %Drop in Cv Acceptance CvUSE 19 2 CvUSE Reactor Vessel Beltline Region Heat wt% 10 n/cm USE Criterion Type ft-lbf ft-lbf Location Number (E>1 MeV) ft-lbf Upper Shell Plate 841 05-3 C2608-28 A5338 0.140 81 0.020 9.4 73.4 ~50 Upper Shell Long. Weld 1-442A 27204/12008 Linde 1092 0.190 86 0.015 14 74.0 ~50 Upper Shell Long . Weld 1-4428 27204/12008 Linde 1092 0.190 86 0.009 14 74.0 ~50 Upper Shell Long. Weld 1-442C 27204/12008 Linde 1092 0.190 86 0.018 14 74.0 ~50 Intermediate Shell Plate 84106-1 C2884-1 A5338 0.125 116 1.204 23 89.3 ~50 Intermediate Shell Plate 84106-2 C2854-2 A5338 0.12 114 1.204 22 88.9 ~50 Intermediate Shell Plate 84106-3 C2793-1 A5338 0.086 77 1.204 20 61.6 ~50

~using surveillance data C2793-1 A5338 0.086 77 1.204  ?.iii) 71.5 ~50 Intermediate Shell Long. Welds 2-442A, 8 27204 Linde 1092 0.203 91 0.888 34 60.1 ~50

~using surveillance data 27204 Linde 1092 0.203 91 0.888 33(ii) 61.0 ~50 Intermediate Shell Long. Weld 2-442C 27204 Linde 1092 0.203 91 0.458 29 64.6 ~50

~using surveillance data 27204 Linde 1092 0.203 91 0.458 28.5(ii) 65.1 ~50 Intermediate Shell to Lower Shell 21935 Linde 1092 0.183 109 1.198 34 71.9 ~50 Circumferential Weld 9-442 Lower Shell Plate 841 07-1 C3121-1 A5338 0.13 110 1.198 23 84.7 ~50 Lower Shell Plate 841 07-2 C3131-2 A5338 0.12 103 1.198 22 80.3 ~50 Lower Shell Plate 841 07-3 C3131-1 A5338 0.12 116 1.1 98 22 90.5 ~50 Lower Shell Long. Welds 3-442A, 8 27204 Linde 1092 0.203 91 0.709 32 61 .9 ~50

~using surveillance data 27204 Linde 1092 0.203 91 0.709 31 62.8 ~50

Enclosure 1 PG&E Letter DCL-16-023 Page 23 of 24 EOL %T EOL Cv USE Material Description Unirradiated Projected Cu Fluence %Drop in Cv Acceptance CvUSE 19 CvUSE Reactor Vessel Beltline Region Heat wt% 10 n/cm 2 USE Criterion Type ft-lbf ft-lbf Location Number (E>1 MeV) ft-lbf Lower Shell Long. Weld 3-442C 27204 Linde 1092 0.203 91 1.198 36 S8.2  ::::so

~using surveillance data 27204 Linde 1092 0.203 91 1.198 3S S9.2  ::::so EOLE =end-of-license extended Excerpt from LRA Table 4.2-7 DCPP Unit 2 Reactor Vessel Material Cv USE at EOLE EOL %T EOLCvUSE Material Description Unirradiated Projected Cu Fluence %Drop in Cv Acceptance CvUSE 19 CvUSE Reactor Vessel Beltline Region Heat wt% 10 n/cm 2 USE Criterion Type ft-lbf ft-lbf Location Number (E>1 MeV) ft-lbf Upper Shell to Intermediate Shell Weld 8-2193S Linde 1092 0.183 109 0.040 16 91.6  ::::so 201 Upper Shell Plate 8S4S3-1 CS162-1 AS338 0.110 82 0.040 9.4 74.3  ::::so Upper Shell Plate 8S4S3-3 CS162-2 AS338 0.110 86.S 0.040 9.4 78.4  ::::so Upper Shell Plate 8S011-1 R C4377-1 AS338 0.110 72 0.040 9.4 6S.2  ::::so Upper Shell Long . Weld 1-201A 2193S/12008 Linde 1092 0.220 118 0.038 18 96.8  ::::so

~using surveillance data 2193S/12008 Linde 1092 0.220 118 0.038 20 94.4  ::::so Upper Shell Long . Weld 1-2018 2193S/12008 Linde 1092 0.220 118 0.037 18 96.8  ::::so

~using surveillance data 2193S/12008 Linde 1092 0.220 118 0.037 2 94.4  ::::so Upper Shell Long. Weld 1-201 C 2193S/12008 Linde 1092 0.220 118 0.031 17 97.9  ::::so

~using surveillance data 2193S/12008 Linde 1092 0.220 118 0.031 19 9S.6  ;::so Intermediate Shell Plate 8S4S4-1 CS161-1 AS338 0.14 91 1.341 2S 68.3  ;::so

~using surveillance data CS161-1 AS338 0.14 91 1.341 22'ii) 71.0  ;::so

Enclosure 1 PG&E Letter DCL-16-023 Page 24 of 24 EOL %T EOLCv USE Material Description Unirradiated Projected 1

Cu Fluence %Drop in Cv Acceptance CvUSE CvUSE i

19 Reactor Vessel Beltline Region Heat wt% 10 n/cm 2 USE Criterion

• Type ft-lbf ft-lbf Location Number (E>1 MeV) ft-lbf I Intermediate Shell Plate 8S4S4-2 CS168-2 AS338 0.14 99 1.341 2S 74.3  ::::so I I

I Intermediate Shell Plate 8S4S4-3 CS161-2 AS338 0.1S 90 1.341 26 66.6  ::::so I

I Intermediate Shell Long. Weld 2-201A 2193S/12008 Linde 1092 0.22 118 0.739 34 77.9  ::::so

~using surveillance data 2193S/12008 Linde 1092 0.22 118 0.739 37.S(ii) 73.8  ::::so Intermediate Shell Long. Weld 2-2018 2193S/12008 Linde 1092 0.22 118 0.912 36 75.S  ::::so

~using surveillance data 2193S/12008 Linde 1092 0.22 118 0.912 39.S(ii) 71.4  ::::so Intermediate Shell Long. Weld 2-201 C 2193S/12008 Linde 1092 0.22 118 0.77S 3S 76.7  ::::so

~using surveillance data 2193S/12008 Linde 1092 0.22 118 0.77S 38(iQ 73.2  ::::so Intermediate Shell to Lower Shell 10120 Linde 0091 0.046 12S 1.323 21 98.8  ::::50 Circumferential Weld 9-201 Lower Shell Plate 8S4SS-1 CS17S-1 A5338 0.14 112 1.323 2S 84.0  ::::so Lower Shell Plate 85455-2 CS17S-2 A5338 0.14 122 1.323 25 91.5  ::::so Lower Shell Plate 8545S-3 CS176-1 AS338 0.1 100 1.323 21 79.0  ::::so Lower Shell Long. Weld 3-201A 33A277 Linde 124 0.2S8 88 0.763 38 S4.6  ::::so Lower Shell Long. Weld 3-2018 33A277 Linde 124 0.258 88 0.733 38 54.6  ::::so Lower Shell Long . Weld 3-201 C 33A277 Linde 124 0.2S8 88 0.900 39 S3.7  ::::so

- - - ------ - ---

EOLE =end-of-license extended

Enclosure 2 PG&E Letter DCL-16-023 Revised Response to Request for Additional Information (RAI) 3.0.3.2.6-3

Enclosure 2 PG&E Letter DCL-16-023 Page 1 of 3 RA/3.0.3.2.6-3

Background:

Annual update Jetter dated December 22, 2014, Attachment 7C, Exception 6 for the Fire Water System program, states that inspection frequencies may be adjusted based on testing and inspection results, in accordance with NFPA-25, Section 4. 6.

Issue:

Although NFPA-25, Section 4. 6, uPerformance-Based Programs," allows adjustments to inspection frequencies, as noted in Section A.4.6, a performance-based program requires that a maximum allowable failure rate be established and approved by the authority having jurisdiction in advance of implementation. In addition, a formal process for reviewing failure rates and making adjustments to test frequencies must be documented and have concurrence from the authority having jurisdiction prior to any changes to the test program. Furthermore, adjusted frequencies must be technically defensible and supported by evidence of reliability, and data collection and retention must be established so that data used to alter frequencies are representative, statistically valid, and evaluated against firm criteria. Without the details relating to the proposed maximum allowable failure rate and the formal process for reviewing and making adjustments, the staff has insufficient information to evaluate this exception.

Request:

Provide details, as discussed in NFPA-25, Section 4. 6, uperformance-Based Programs,"

for all aspects related to adjusting inspection or test frequencies based on past data.

Alternatively, propose exceptions to specific inspection frequencies and provide the bases to justify the change to these frequencies.

PG&E Revised Response to RAI 3.0.3.2.6-3 PG&E updates the response to RAI 3.0.3.2.6-3 as submitted in PG&E Letter DCL 121 as shown below:

V'lith the exception of the frequency associated vlfth fire v1ater storage tank tests/inspections, underground flov1 tests, and inspections of normally dry but periodically Vl-etted piping that vii!/ not drain due to its configuration, PG&E will enhance the Fire Water System Program (82.1.13) to revise plant procedures to document the process for using performance-based monitoring (testing, maintenance, inspection, consequence of system maloperation). Prior to making any changes to inspection/test frequencies, PG&E will establish a maximum allowable failure rate, and proceduralize a process for reviewing failure rates and making adjustments to inspection/test intervals.

The process 'llill be technically defensible to Nuclear Electric Insurance Limited (NEIL) ,

the authority having jurisdiction , and supported by evidence of higher or lo'Ner reliability.

Enclosure 2 PG&E Letter DCL-16-023 Page 2 of 3 TesUinspection results data utilized for establishing reliability metrics will be statistically valid, evaluated against firm criteria, and retained for reference. Concurrence of

.Nuclear Electric Insurance Limited (NEIL) will be obtained on the process used to determine tesUinspection frequencies, and the maximum allowable failure rate, in advance of any alternations to the tesUinspection program. The procedure will contain a formalized method of increasing or decreasing the frequency of testing/inspection

• when systems exhibit either a higher than expected failure rate or an increase in reliability as a result of a decrease in failures, or both. The justification for changing the interval will be documented using the CAP, and referenced in the revision history for the implementing inspection/testing procedure.

The inspections/testing intervals of the Fire Water System program will be determined by a performance based approach as allowed in NFPA-25, Section 4.6, "Performance-Based Programs". The minimum inspection/testing interval (the interval approved in the DCPP Fire Water System program) may be extended when acceptable performance is established, as defined by EPRI Report 1006756, ::uFire Protection Equipment Surveillance Optimization and Maintenance Guide,'~ Section 11 .2. Acceptable performance is defined as "as found" inspections/testing where the number of instances the acceptance criteria is not met does not exceed the maximum allowable failure rate approved in advance by NEIL. NEIL has provided the period of time over which the previous results should be reviewed to establish the failure rate. The period of time (and minimum sample size) is dependent on the revised interval of testing/inspection.

Data to be used in analyzing the potential for modifying test and inspection frequencies would not be obtained any earlier than five years prior to the period of extended operation. The NEIL recommendations are documented in Section 11.2.1.1 of EPRI 1006756, July 2003, Implementation Guidelines for a Performance Based Surveillance Program . Those intervals are shown in the table below.

Minimum Recent Data Collection Period for Expanding TesUinspection Intervals Test/Inspection Required Data Frequency Up to quarterly 2 years of most recent data Quarterly up to annual 3 years of most recent data Annual up to fuel cycle 5 years of most recent data Fuel cycle or longer Extension currently not permitted Because there is not sufficient industry operating experience, EPRI Report 1006756, Section 11. 2 will not be used to modify the frequency associated with fire water storage tank tests/inspections, underground flow tests, and inspections of normally dry but periodically wetted piping that will not drain due to its configuration. PG&E will not make

Enclosure 2 PG&E Letter DCL-16-023 Page 3 of 3 performance-based frequency modifications of these inspections until NRC approves use of a methodology for modification of these inspection frequencies.

When an equipment failure occurs, it is entered into the CAP, trended, and an engineering evaluation is performed. Resulting corrective actions are taken based on the cause of the problem. Test results would be evaluated upon completion of each test seeped in the program to ensure compliance with the established performance based criteria. If the maximum allowable failure rate is exceeded during the required data interval, the inspection/test interval will be adjusted in accordance with NEIL approved method for increasing inspection/test frequency. Once cause determination and corrective actions have been completed, acceptable performance may be re-established.

Enclosure 3 PG&E Letter DCL-16-023 License Renewal Application (LRA) Amendment 52 Affected LRA Sections and Tables

Enclosure 3 PG&E Letter DCL-16-023 Page 1 of 16 License Renewal Application (LRA) Amendment 52 Affected LRA Sections and Tables LRA Section Reason for Change Section 3.4.2.2.2.1 RAI 3.4.2.3.1-1 a Table 3.4.1 RAI 3.4.2.3.1-1a Table 3.4.2-1 RAI 3.4.2.3.1-1 a Table 3.4.2-4 RAI 3.4.2.3.1-3a Section A 1. 13 RAI 3.0.3.2.6-2a Section A 1. 18 RAI 3.0.3.2.6-2a RAI 82.1.18-4a Section A 1.42 RAI 3.0.3.2.6-2a RAI 3.0.3.2.6-2a Table A4-1 , Items RAI 82.1.13-Sa 3, 52, 74 RAI 82.1.18-4a Section 3.4 PG&E Letter DCL-16-023 AGING MANAGEMENT OF STEAM AND POWER CONVERSION SYSTEM Page 2 of 16 3.4.2.2.2.1 Steel piping and components, tanks, and heat exchangers exposed to treated water and steel piping and components exposed to steam The Water Chemistry program (82.1.2) and the One-Time Inspection program (82.1.16) manages loss of material due to general, pitting, and crevice corrosion for carbon steel and gray cast iron components exposed to secondary water. The one-time inspection includes selected components at susceptible locations where contaminants could accumulate (e.g. stagnant flow locations).

A different aging management program is credited for the main condenser shell and hotwell internal surfaces. The aging of main condenser shell and hotwell internal surfaces exposed to the treated water and steam environment is managed by Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components program (82.1.22).

A different aging management program is credited for abandoned-in-place components or components in long-term layup . The aging of internal component surfaces exposed to the treated water environment of the abandoned-in-place or long-term layup portions of systems are managed by Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components program (82.1.22).

A different aging management program is credited for internally lined components. The aging of the internal coated/lined component surfaces exposed to a treated water environment will be managed by Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks program (82.1.42) .

Section 3.4 PG&E Letter DCL-16-023 AGING MANAGEMENT OF STEAM AND POWER CONVERSION SYSTEM Page 3 of 16 Table 3.4.1 Summary of Aging Management Evaluations in Chapter VIII of NUREG-1801 for Steam and Power Conversion Svst Item Component Type Aging Effect I Mechanism Aging Management Further Discussion Number Program Evaluation Recommended 3.4.1.04 Steel piping, piping Loss of material due to Water Chemistry (82. 1.2) Yes Consistent with NUREG-1801 components, and general, pitting and crevice and One-Time Inspection for all non abandoned-in-place, piping elements corrosion (82 .1.16) non long-term layup exposed to treated components, and non water coated/lined components. A different aging management program is credited for abandoned-in-place or long-term layup components. The aging of internal component surfaces exposed to the treated water environment of the abandoned-in-place or laid up portions of systems will be managed by Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components (82.1.22).

A different aging management program is credited for coated/lined components. The aging of the internal coated/lined component surfaces exposed to a treated water environment will be managed by Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks (82.1.42).

See further evaluation in

---

-- --

Section 3.4.2.2.2 .1.

- - - - - - -- - - - -

Section 3.4 PG&E Letter DCL-16-023 AGING MANAGEMENT OF STEAM AND POWER CONVERSION SYSTEM Page 4 of 16 Table 3.4.2-1 Steam and Power Conversion System - Summary of Aging Management Evaluation - Turbine Steam Supply System Component Intended Material Environment Aging Effect Aging Management NUREG- Table 11tem Notes Type Function Requiring Program 1801 Vol.

Management 21tem Demineralizer LBS Carbon Steel Demineralized Loss of material Internal VIII .G+-4F- 3.4.1.4-904 E, 3, 5 (with coating Water (lnt) Coatings/Linings for In- 25 or lining) Scope Piping, Piping Components, Heat Exchangers, and Tanks (82.1.42) 1nspection of "

lnteFnal S~:~Ffaces in Miscellaneo~:~s Pipin§ ane Q~:~ctin§ Demineralizer L8S Carbon Steel Demineralized Loss of coating

-- *.-- - *-

f' .

Internal

/0') -1 ')')\

--* *--

None None H, 3, 5 (with coating Water (lnt) integrity Coatings/Linings for In-or lining) Scope Piping, Piping Components, Heat Exchangers, and Tanks (82.1.42)

Filter L8S Carbon Steel Demineralized Loss of material Inspection of Internal V/1/.F-25 3.4.1.04 E, 3, 9 Water (lnt) Surfaces in Miscellaneous Piping and Ducting Components (82. 1. 22)

Flow Element L8S Stainless Demineralized Loss of material Inspection of Internal VIII.D1-4 3.4.1.16 E, 3, 9 Steel Water (lnt) Surfaces in Miscellaneous Piping and Ducting Components (82. 1. 22)

Indicator LBS Carbon Steel Soei~:~m Loss of material Inspection of Internal V/11.81- 3.4.1.30N-oo 8 , 3, 11G,--

~yeFoxiee Piant Surfaces in 7Nooe- e a Indoor Air (lnt) Miscellaneous Piping and Ducting Components (82.1.22)

Section 3.4 PG&E Letter DCL-16-023 AGING MANAGEMENT OF STEAM AND POWER CONVERSION SYSTEM Page 5 of 16 Table 3.4.2-1 Steam and Power Conversion System - Summary of Aging Management Evaluation - Turbine Steam Supply System Component Intended Material Environment Aging Effect Aging Management NUREG- Table 11tem Notes Type Function Requiring Program 1801 Vol.

Management 21tem IAeisateF hBS GaFeeA Steel S~::Jif~::JFis Asia (I At) bess ef rnateFial IAs~estieA ef IAteFAal Nooe-- Nooe G,J S~::JFfases iA MissellaAee~::Js Pi~iA§ aAe Ql:JGtiA§

(',

-~ *.-~ ~ **~ ,--* *--

10') 1 ')')\

Piping L8S Carbon Steel Demineralized Loss of material Inspection of Internal V/1/.F-25 3.4.1.04 E, 3, 9 Water (tnt) Surfaces in Miscellaneous Piping and Ducting Components (82. 1. 22)

Piping LBS Carbon Steel Demineralized Loss of material Internal VIII .Q4.-4.F- 3.4. 1.+904 E,3, 5 (with coating Water (lnt) Coatings/Linings for In- 25 or lining) Scope Piping, Piping Components, Heat Exchangers, and Tanks (82.1.42) 1AS~eGtieA ef IAteFAal S~::JFfases iA MissellaAeel:Js Pi~iA§ aAe Ql:JGtiA§ lr- 10') 1 ')')\

- . .

Piping L8S Carbon Steel Demineralized Loss of coating Internal None None H, 3, 5 (with coating Water (tnt) integrity Coatings/Linings for In-or lining) Scope Piping, Piping Components, Heat Exchangers, and Tanks (82.1.42)

Piping L8S Carbon Steel Plant Indoor Air Loss of material Inspection of Internal V/11.81-7 3.4.1.30 8, 3, 11 (with coating (tnt) Surfaces in or lining) Miscellaneous Piping and Ducting Components (82.1.22)

Section 3.4 PG&E Letter DCL-16-023 AGING MANAGEMENT OF STEAM AND POWER CONVERSION SYSTEM Page 6 of 16 Table 3.4.2-1 Steam and Power Conversion System- Summary of Aging Management Evaluation- Turbine Steam Supply System Component Intended Material Environment Aging Effect Aging Management NUREG- Table 11tem Notes Type Function Requiring Program 1801 Vol.

Management 21tem Piping LBS Carbon Steel Dry Gas (lnt) None None V/11.1-15 3.4.1.44 A, 3, 12 (with coating or lining)

Piping L8S Polyvinyl SL:JifL:JFiG Aei9 None None None None G Chloride flffitDemineralized (PVC) Water (lnt)

Piping L8S Stainless Sodium Hydroxide Loss of material Inspection of Internal None None G, 2, 3, 10 Steel (lnt) Surfaces in Miscellaneous Piping and Ducting Components (82 .1.22)

Piping L8S Stainless Sulfuric Acid (lnt) Loss of material Inspection of Internal None None G, 3, 10 Steel Surfaces in Miscellaneous Piping and Ducting Components (82 .1.22)

Pump L8S Carbon Steel Se9iwll Less ef lnspeetien ef lntemal VIII./- 3.4.1.44-Noo C, 3, 12 Hy9mxi9eDry Gas mateFiaiNone SL:Jrtaees in 15Nooe-- e (lnt) MiseellaneeL:Js Pipin§ an9 QL:Jetin§ Gempenents

{82 .1 .22' None

~ ~ GaF~en Steel SL:JifL:JFiG ~~ei9 ~lnt) Less ef mateFial lnspeetien ef lntemal Nooe-- NeRe ~

SL:Jrtaees in MiseellaneeL:Js Pipin§ an9 QL:Jetin§

(" /0') 1 ')')\

Sight Gauge L8S Carbon Steel Demineralized Loss of material Inspection of Internal V/1/.F-25 3.4.1.04-Noo GE, 3, 9G, Water (lnt) Se9iL:Jm Surfaces in Nooe-- e § Hy9mxi9e (lnt) Miscellaneous Piping and Ducting Components (82.1 .22)

Section 3.4 PG&E Letter DCL-16-023 AGING MANAGEMENT OF STEAM AND POWER CONVERSION SYSTEM Page 7 of 16 Table 3.4.2-1 Steam and Power Conversion System- Summary of Aging Management Evaluation- Turbine Steam Supply System Component Intended Material Environment Aging Effect Aging Management NUREG- Table 11tem Notes Type Function Requiring Program 1801 Vol.

Management 21tem Si~t:lt Ga~:~~e bBS GaF9eA Steel S~:~lf~:~Fis Asia (I At) bess ef mateFial IAspestieA ef IAtemal NeRe- Nooe G S~:~Ffases iA MissellaAee~:~s PipiA~

aA9 Q~:~stiA~

-

(',

• r-- - ,_

/C'J 1 ')')\

-- . *--

Sight Gauge LBS Glass Seei~:~m bess ef I AspestieA ef IAtemal NeRe- Nooe3.4.1.4 GA Hydm:xieeOeminer mateFiaiNone S~:~Ffases iA Vlll.l-8 0 alized Water (tnt) MissellaAeet:IS PipiA~

aAe Q~:~stiA~

GempeAeAts (82. 1 .22\None Si~t:lt Ga~:~~e bBS Glass S~:~lf~:~Fis Asid (I At) Nooe Nooe NeRe- Nooe G Tank LBS, SIA Carbon Steel QemiAeFali:2:e9 Loss of material Inspection of Internal VIII. B1 - 3.4.1. 3049 eo, 3, 11 (with coating Water-Plant Indoor Surfaces in 7G4-4 or lining) Air (lnt) Miscellaneous Piping and Ducting Components (82.1.22)

• Valve LBS, SIA Carbon Steel Demineralized Loss of material Internal VIII.G4-4F- 3.4.1.4904 E,3, 5  !

(with coating Water (lnt) Coatings/Linings for In- 25 or lining) Scope Piping, Piping Components, Heat Exchangers, and Tanks (82.1.42)1AspestieA ef IAtemal S~:~Ffases iA MissellaAee~:~s PipiA~

aAe Q~:~stiA~

(' /C'J 1 ')')\

Valve LBS, SIA Carbon Steel Demineralized Loss of coating Internal None None H, 3, 5 (with coating Water (tnt) integrity Coatings/Linings for In-or lining) Scope Piping, Piping Components, Heat Exchangers, and Tanks (82.1.42)

Section 3.4 PG&E Letter DCL-16-023 AGING MANAGEMENT OF STEAM AND POWER CONVERSION SYSTEM Page 8 of 16 Table 3.4.2-1 Steam and Power Conversion System- Summary of Aging Management Evaluation- Turbine Steam Supply System Component Intended Material Environment Aging Effect Aging Management NUREG- Table 11tem Notes Type Function Requiring Program 1801 Vol.

Management 21tem Valve L8S Carbon Steel Plant Indoor Air Loss of material Inspection of Internal V/11.81-7 3.4.1 .30 8, 3, 11 (with coating (lnt) Surfaces in or lining) Miscellaneous Piping and Ducting Components (82. 1. 22)

Valve L8S Carbon Steel Dry Gas (lnt) None None V/11.1-15 3.4.1.44 A, 3, 12 (with coating or lining)

Valve L8S Stainless Demineralized Loss of material Inspection of Internal VIII.D1-4 3.4.1.16 E, 3, 9 Steel Water (lnt) Surfaces in Miscellaneous Piping and Ducting I I

Components (82.1 .22)

Valve L8S Stainless Sodium Hydroxide Loss of material Inspection of Internal None None G, 2, 3, 10 !

Steel (lnt) Surfaces in Miscellaneous Piping and Ducting Components (82 .1.22)

Valve L8S Stainless Sulfuric Acid (lnt) Loss of material Inspection of Internal None None G, 3, 10 Steel Surfaces in Miscellaneous Piping and Ducting Components (82.1 .22)

Plant Specific Notes:

3 These piping, piping components, and tanks are in the steam generator blowdown (SG8D) treatment demineralizer system. This system was designed to handle may be temporarily exposed to sulfuric acid, sodium hydroxide, or secondary water at 11 ooF for short periods of time in the event of a steam generator tube leak. ,...9ut--tAs documented in PG&E's response to RAJ 3.4.3.2.1 -1a in PG&E Letter DCL- 16-023 the system has been laid up and the normal long-term internal environment will be demineralized water, plant indoor air, or dry gas. It is possible to use sulfuric acid and sodium hydroxide to regenerate the demineralizer resins, but the FSAR requires the SG8D treatment demineralizer resins to be replaced (i.e. not regenerated) . Therefore, sulfuric acid and sodium hydroxide will not be introduced into this system. Hl-Section 3.4 PG&E Letter DCL-16-023 AGING MANAGEMENT OF STEAM AND POWER CONVERSION SYSTEM Page 9 of 16 accordance with LR ISG 2013 01, as documented in PG&E Letter DCL 15 121 in response to RAis 3.4.2.3.1 1, 3.4 .2.3.1 2, 3.4 .2.3.1 3 these components will be managed using the Inspection of Internal Surfaces of Miscellaneous Piping and Ducting Components program (82 .1.22).

5 In accordance with LR-ISG-2013-01, as documented in PG&E Letter DCL-16-023 in response to RAI3.4.2.3.1-1a, coated or lined piping, piping components, and tanks with an internal environment of demineralized water in the SGBD treatment de mineralizer system will be managed using the Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks (82.1.42) Program for loss of material and loss of coating integrity. There is no NUREG 1801 line for the environment of NaOH . The use of carbon steel up to 200°F and 50 weight percent NaOH is common in industrial applications with no special consideration for aging. The NaOH concentration is not monitored . The Inspection of Internal Surfaces program is used to age manage the components.

9 As documented in PG&E's response to RAI3.4.3.2.1-1a in PG&E letter DCL-16-023, aging of piping, piping components, and tanks in the SG8D treatment demineralizer system fabricated of carbon steel with no internal lining/coating, or stainless steel, with an internal environment of demineralized water will be managed using thelnspection oflnternal Surfaces in Miscellaneous Piping and Ducting Components (82.1.22)

Program.

10 These piping and piping components were part of the SG80 treatment demineralizer regeneration skid filled with sulfuric acid or NaOH and were not flushed when the system was laid up.

11 As documented in PG&E's response to RAI3.4.3.2.1-1a in PG&E letter DCL-16-023, aging of piping, piping components, and tanks with an internal lining/coating and an internal environment of plant indoor air in the SG8D treatment demineralizer system will be managed using the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components (82. 1. 22) program.

12 As documented in PG&E's response to RAI3.4.3.2.1-1a in PG&E letter DCL-16-023, the portion of the SG8D treatment demineralizer system used to regenerate the de mineralizers was flushed, neutralized, and laid up with dry gas.

Section 3.4 PG&E Letter DCL-16-023 AGING MANAGEMENT OF STEAM AND POWER CONVERSION SYSTEM Page 10 of 16 Table 3.4.2-4 Steam and Power Conversion System - Summary of Aging Management Evaluation - Condensate Svst Component Intended Material Environment Aging Effect Aging Management NUREG- Table 1 Item Notes Type Function Requiring Program 1801 Vol.

Management 21tem Demineralizer L8S Carbon Steel Secondary Water Loss of coating Internal None None H,5 (with coating (lnt) integrity Coatings/Linings for In-or lining) Scope Piping, Piping Components, Heat Exchangers, and Tanks I (82 .1.42) i Demineralizer k8S Gareen Steel Secendary 'Nater Less ef ceating lnspectien ef Internal NeRe NeRe ~ I

~with ceati ng fffit} integrity St:Jrfaces in i

er lining) Miscellaneet:Js Piping I and Dt:Jcting

("

-- *r-

- ,_ /C') .1. ')')\

Plant Specific Notes:

5 The Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks (82.1.42) program is used to monitor condensate polisher demineralizers fabricated from carbon steel (with internal coating or lining) with an internal environment of secondary water for loss of coating integrity. Reference PG&E Letter DCL-15-027, Enclosure 1 in response to LR-ISG-2013-01, Appendix 8, Table VIII. The evaluated environment from Table 3.0-1 for the condensate polisher demineralizers is secondary water, but the NUREG-1801 environment is treated water. As documented in PG&E's response to RAI3.4.2.3.1-3a in PG&E Letter DCL-16-023, internal rubber lining for tanks exposed to treated water are included within the scope of NUREG-1801 XI.M42, "Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks."

Appendix A PG&E Letter DCL-16-023 Final Safety Analysis Report Supplement Page 11 of 16 A1.13 FIRE WATER SYSTEM The Fire Water System program manages loss of material due to corrosion, including MIC, fouling, flow blockage because of fouling, and loss of integrity for water-based fire protection systems and internal coatings/linings for the fire water storage tank within the scope of license renewal. Internal and external inspections and tests of fire protection equipment are performed consistent, with exceptions identified in PG&E Letters DCL-14-103, Enclosure 1, Attachment 7C, and DCL-15-121, with NFPA-25 (2011 edition).

Testing or replacement of sprinklers that have been in place for 50 years is performed in accordance with NFPA-25 (2011 edition). Portions of the deluge systems that are

• normally dry but periodically subjected to flow and cannot be drained or allow water to collect will undergo augmented testing beyond that in NFPA-25 consisting of volumetric wall thickness examinations. The fire water system is managed by performing routine preventive maintenance, inspections and testing; operator rounds, performance monitoring, and reliance on the corrective action program; and system improvements to address aging and obsolescence issues. The fire water system is normally maintained at required operating pressure and is monitored such that loss of system pressure is immediately detected and corrective actions are initiated.

The Fire Water System program will conduct a flow test with air, water, or other medium through each open spray nozzle to verify that deluge systems nozzles are unobstructed.

Water flow tests will verify that the deluge system provide full coverage of the equipment it protects. Visual inspections will be performed on firewater piping. Non-intrusive follow-up volumetric examinations will be performed if internal visual inspections detect surface irregularities to determine if wall thickness is within acceptable limits. Visual inspections will evaluate for the presence of sufficient foreign material to obstruct fire water pipe or sprinklers.

Inspections of the firewater tank will be performed to detect loss of material.

As discussed in PG&E Letter DCL 15 027, Enclosure 1, in response to LR ISG 2013 01, the program consists of pPeriodic visual inspections will be performed of the internal liner of the fire water storage tank exposed to raw water where loss of lining integrity could impact the components' and downstream components' current licensing basis intended function(s). For coated surfaces determined to not meet the acceptance criteria, physical testing is performed where physically possible (i.e., sufficient room to conduct testing) in conjunction with repair, replacement, or removal of the lining.

Individuals responsible for conducting coating inspections will be qualified in accordance with ASTM 04537, which is endorsed by Regulatory Guide (RG) 1.54. The individuals responsible for assessing the type and extent of coating degradation will be qualified in accordance with ASTM 07108-05, which is also endorsed by RG 1.54.+Aer training and qualification of individuals involved in coating inspections are conducted in accordance 'Nith ASTM International Standards endorsed in RG 1.54 including guidance from the NRC associated 'Nith a particular standard .

Appendix A PG&E Letter DCL-16-023 Final Safety Analysis Report Supplement Page 12 of 16 The Fire Water program implements the recommendations in LR-ISG-2012-02, as discussed in PG&E Letters DCL-14-1 03, Enclosure 1, Attachments 7C and DCL 121, and the recommendations in LR-ISG-2013-01, as discussed in PG&E Letters DCL-15-027 and DCL-16-023.

Appendix A PG&E Letter DCL-16-023 Final Safety Analysis Report Supplement Page 13 of 16 A1.18 BURIED PIPING AND TANKS INSPECTION The Buried Piping and Tanks Inspection program manages cracking, loss of material, and change in surface conditions of buried and underground piping, piping components and tanks in the auxiliary saltwater system, diesel generator fuel transfer system, fire protection system, and the makeup water system. The program manages aging through preventive, mitigative, (i.e., coatings, backfill quality, and cathodic protection) and inspection activities. Visual inspections monitor the condition of protective coatings and wrappings found on steel and copper alloy components and directly assess the surface condition of cast iron, polyvinyl chloride, and asbestos cement components with no protective coatings or wraps. Evidence of damaged wrapping or coating defects is an indicator of possible age-related degradation to the external surface of the components. The presence of discolorations, discontinuities in surface texture, cracking, crazing, changes in material properties or loss of material of unwrapped cast iron, polyvinyl chloride, and asbestos cement components is an indicator of possible aging of the external surface of the components. The program includes opportunistic inspection of buried piping and tanks as they are excavated or on a planned basis if opportunistic inspections have not occurred.

Soil samples will be conducted in the vicinity of in-scope buried, non-cathodically protected steel piping and piping components. Soil samples will be conducted in the vicinity of in-scope buried auxiliary saltwater system steel piping in which the cathodic protection system does not meet the availability or effectiveness requirements. Soil samples will be conducted during the ten-year period prior to the period of extended operation and in each subsequent ten-year period during the period of extended operation.

Alternative to visual inspection of the external surface of steel piping, hydrostatic testing or an inspection of the internal surface of the piping that is capable of precisely determining pipe wall thickness may be used.

The Buried Piping and Tanks Inspection program is a new program that will be implemented prior to the period of extended operation. Inspections will be conducted during each 10-year period beginning 10 years prior to entering the period of extended operation. Examinations of buried piping will consist of visual inspections. Significant indications of degradation observed during visual inspections of buried piping will require a supplemental surface and/or volumetric non-destructive testing.

The Buried Piping and Tanks Inspection program implements the specific additional guidance provided in LR-ISG-2011-03 as discussed in PG&E Letter DCL-14-103, , Attachment 3 and the specific changes provided in draft LR-ISG-2015-01 as discussed in PG&E Letters DCL-15-121, Enclosures 1 and 2, and DCL-16-023.

Appendix A PG&E Letter DCL-16-023 Final Safety Analysis Report Supplement Page 14 of 16 A1.42 INTERNAL COATINGS/LININGS FOR IN-SCOPE PIPING, PIPING COMPONENTS, HEAT EXCHANGERS, AND TANKS The program consists of periodic visual inspections of all coatings/linings applied to the .

internal surfaces of in-scope components exposed to closed-cycle cooling water, raw water, demineralized water, treated borated water, lubricating oil, or fuel oil where loss of coating or lining integrity could impact the component's and downstream component's current licensing basis intended function(s). For coated/lined surfaces determined to not meet the acceptance criteria, physical testing is performed where physically possible (i.e., sufficient room to conduct testing) in conjunction with repair or replacement of the coating/lining. The training and qualification of individuals involved in coating/li ning inspections of non cementitious coatings/linings are conducted in accordance with ASTM International Standards endorsed in Regu latory Guide 1.54 including gu idance from the staff associated 'A'ith a particular standard . Individuals responsible for conducting coating inspections will be qualified in accordance with ASTM 04537, which is endorsed by Regulatory Guide (RG) 1.54. The individuals responsible for assessing the type and extent of coating degradation will be qualified in accordance with ASTM 07108-05, which is also endorsed by RG 1.54. For cementitious coatings, training and qualifications are based on an appropriate combination of education and experience related to inspecting concrete surfaces.

The internal fire water storage tank liner will be managed using the Fire Water System program (A 1.13). The in scope lined components in the steam generator blo'A'do\vn treatment demineralizer system tNill be m*anaged using the Inspection of Internal Surfaces of Miscellaneous Piping and Ducting Components program (A1.22).

The Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks program is a new program that will be implemented no later than six months prior to the period of extended operation with inspections beginning no later than the last refueling outage before the period of extended operation. The Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks program implements the recommendations in LR-ISG-2013-01, as discussed in PG&E Letters DCL-15-027, Enclosure 1, aRd-DCL-15-121 , and OCL-16-023.

Appendix A PG&E Letter DCL-16-023 FINAL SAFETY ANALYSIS REPORT SUPPLEMENT Page 15 of 16 Table A4-1 License Renewal Commitments Item# Commitment LRA Implementation Section Schedule 3 Enhance the Fire Water System program: Program is implemented 5 (a) Sprinkler heads in service for 50 years will be replaced or representative B2.1.13 years before the period of samples from one or more sample areas will be tested consistent with extended operation.

NFPA 25, Inspection, Testing and Maintenance of Water-Based Fire Protection Augmented inspections to Systems, 2011 Edition guidance. Test procedures will be repeated at 10-year address recurring internal intervals during the period of extended operation, for sprinkler heads that were corrosion and il nspections not replaced prior to being in service for 50 years, to ensure that signs of of wetted normally dry degradation, such as corrosion, are detected prior to the loss of intended piping segments that function, and cannot be drained or that (b) To perform non-intrusive follow-up volumetric examinations if internal visual allow water to collect inspections detect surface irregularities to determine if wall thickness is within begin 5 years before the acceptable limits. Visual inspections will evaluate for the presence of sufficient period of extended foreign material to obstruct fire water pipe or sprinklers operation. Internal linings (c) To be in conformance with LR-ISG-2012-02, Section Cas discussed in PG&E inspections begin no later Letter DCL-14-103, Enclosure 1, Attachment 7C. than the last refueling (d) To be in conformance with LR-ISG-2013-01 as discussed in PG&E Letters outage before the period DCL-15-027, Enclosure 1, and DCL-16-023 in response to RAI3.0.3.2.6-2a. of extended operation.

(e) Test deluge system nozzles in accordance with the 2011 Edition of NFPA 25, The program's remaining Section 10.3.4.3.1. inspections begin during fet(f) Conduct augmented inspections to address recurring internal corrosion as the period of extended discussed in PG&E Letter DCL-16-023. operation 52 The Buried Piping and Tanks Inspection Program will be revised to conform to the specific additional guidance provided in LR-ISG-2011-03 and the specific changes provided in draft LR ISG 2015 01 as discussed in PG&E Letter DCL-14-1 03, Enclosure 1, Attachment 3, and the specific changes provided in draft LR-ISG-2015-01 and in PG&E Letters DCL-15-121, Enclosures 1 and 2, and DCL--16-023respectively. Within 10 years prior to B2.1 .18 the period of extended Fire mains will be subject to a periodic flow test in accordance with NFPA 25 operation Section 7.3 at a frequency of at least one test in each one year period. These flow tests will be performed in lieu of excavating buried portions of Fire Water pipe for visual inspections.

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Appendix A PG&E Letter DCL-16-023 FINAL SAFETY ANALYSIS REPORT SUPPLEMENT Page 16 of 16 Table A4-1 License Renewal Commitments Item# Commitment LRA Implementation Section Schedule Implement the Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat No later than six months 74 Exchangers, and Tanks program in conformance with LR-ISG-2013-01 as discussed in before the period of PG&E Letters DCL-15-027, Enclosure 1, and PG&E Letter DCL-15-121 , and DCL extended operation and 023. inspections begin no later 82.1.42 than the last refueling outage before the period of extended operation