ML103220205
| ML103220205 | |
| Person / Time | |
|---|---|
| Site: | Diablo Canyon  |
| Issue date: | 11/17/2010 |
| From: | O'Keefe N NRC/RGN-IV/DRS/EB-2 |
| To: | Conway J Pacific Gas & Electric Co |
| References | |
| IR-10-008 | |
| Download: ML103220205 (82) | |
See also: IR 05000275/2010008
Text
November 17, 2010
John T. Conway
Senior Vice President-Energy & Supply and Chief Nuclear Officer Pacific Gas and Electric Company Diablo Canyon Nuclear Plant 77 Beale Street, Mail Code B32 San Francisco, CA 94105
SUBJECT: DIABLO CANYON POWER PLANT - NRC LICENSE RENEWAL INSPECTION REPORT 05000275/2010008 AND 05000323/2010008
Dear Mr. Conway:
On September 16, 2010, a U.S. Nuclear Regulatory Commission (NRC) team completed the onsite portion of an inspection of your application for license renewal of your Diablo Canyon Power Plant. The team discussed the inspection results with Mr. L. Sharp, Engineering Services Senior Director, and other members of your staff.
This inspection examined activities that supported the application for a renewed license for the Diablo Canyon Power Plant. The inspection addressed your processes for scoping and screening structures, systems, and components to select equipment subject to an aging management review. Further, the inspection addressed the development and implementation of aging management programs to support continued plant operation into the period of extended
operation. As part of the inspection, the NRC examined procedures and representative records, interviewed personnel, and visually examined accessible portions of various structures, systems, or components to verify license renewal boundaries and to observe any effects of equipment aging. The visual examination of structures, systems, and components also included some areas not normally accessible, which included the diesel fuel oil vaults. These NRC inspection activities constitute one of several inputs into the NRC review process for license renewal applications.
The team concluded that your staff appropriately implemented the screening and scoping of nonsafety-related structures, systems, and components that could affect safety-related structures, systems and components. The team concluded that your staff conducted an appropriate review of the materials and environments and established appropriate aging
management programs, as described in the license renewal application and as supplemented through your responses to requests for additional information from the NRC. The team concluded that your staff maintained the documentation supporting the application in an auditable and retrievable form. The team identified a number of issues that resulted in your staff supplementing or amending the application, programs, and procedures.
`UNITED STATESNUCLEAR REGULATORY COMMISSIONREGION IV612 EAST LAMAR BLVD, SUITE 400ARLINGTON, TEXAS 76011-4125
Pacific Gas and Electric Company - 2 -
Based on the samples reviewed by the team, the inspection results support a conclusion of reasonable assurance that actions have been identified and have been or will be taken to manage the effects of aging in the structures, systems, and components identified in your
application and that the intended functions of these structures, systems, and components will be maintained in the period of extended operation.
In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter, and its enclosure, will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records component of NRC's document system (ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).
Sincerely, /RA/ Neil O'Keefe, Chief Engineering Branch 2 Division of Reactor Safety
Dockets: 50-275; 50-323 Licenses: DPR-80; DPR-82
Sierra Club Santa Lucia Chapter ATTN: Andrew Christie
P.O. Box 15755 San Luis Obispo, CA 93406
Jane Swanson San Luis Obispo
Mothers for Peace P.O. Box 3608 San Luis Obispo, CA 93403
James Grant, County Administrative Officer
San Luis Obispo County Board of Supervisors 1055 Monterey Street, Suite D430 San Luis Obispo, CA 93408
Truman Burns\Robert Kinosian California Public Utilities Commission
505 Van Ness Ave., Rm. 4102 San Francisco, CA 94102
Pacific Gas and Electric Company - 3 -
Jennifer Post, Esq. Pacific Gas & Electric Co. 77 Beale Street, Room 2496 Mail Code B30A
San Francisco, CA 94120
Gary Butner Chief, Radiologic Health Branch California Department of Public Health 3
P.O. Box 997414 (MS 7610) Sacramento, CA 95899-7414
The City Editor of The Tribune 3825 South Higuera Street P.O. Box 112
San Luis Obispo, CA 93406-0112
James D. Boyd, Commissioner California Energy Commission 1516 Ninth Street (MS 31)
Sacramento, CA 95814
James R. Becker, Site Vice President Pacific Gas and Electric Company Diablo Canyon Nuclear Plant
P.O. Box 56, Mail Station 104/6/601 Avila Beach, CA 93424
Jennifer Tang Field Representative
United States Senator Barbara Boxer 1700 Montgomery Street, Suite 240 San Francisco, CA 94111
Chief, Technological Hazards Branch
FEMA Region IX 1111 Broadway, Suite 1200 Oakland, CA 94607-4052
Pacific Gas and Electric Company - 4 -
Electronic distribution by RIV: Regional Administrator (Elmo.Collins@nrc.gov) Deputy Regional Administrator (Chuck.Casto@nrc.gov) DRP Director (Kriss.Kennedy@nrc.gov)
DRP Deputy Director (Anton.Vegel@nrc.gov) DRS Director (Roy.Caniano@nrc.gov) DRS Deputy Director (Troy.Pruett@nrc.gov) Senior Resident Inspector (Michael.Peck@nrc.gov) Resident Inspector (Tony.Brown@nrc.gov)
Acting Branch Chief, DRP/B (Don.Allen@nrc.gov) Senior Project Engineer, DRP/B (Rick.Deese@nrc.gov) Project Engineer, DRP/B (Greg.Tutak@nrc.gov) Project Engineer, DRP/B (Nestor.Makris@nrc.gov) Reactor Inspector, DRP/B (Christie.Denissen@nrc.gov) DC Administrative Assistant (Agnes.Chan@nrc.gov) Public Affairs Officer (Victor.Dricks@nrc.gov)
Public Affairs Officer (Lara.Uselding@nrc.gov) Project Manager (Fred.Lyon@nrc.gov) Branch Chief, DRS/TSB (Michael.Hay@nrc.gov) RITS Coordinator (Marisa.Herrera@nrc.gov) Regional Counsel (Karla.Fuller@nrc.gov)
Congressional Affairs Officer (Jenny.Weil@nrc.gov) OEDO RIV Coordinator (Geoffrey.Miller@nrc.gov) RidsNrrDlr Resource RidsNrrDlrRpb1 Resource RidsNrrDlrRpb2 Resource
RidsNrrDlrRer1 Resource RidsNrrDlrRer2 Resource DLR Reading File File located: R:\_REACTORS\_DC\2010\DC 2010008 LRI GAP.doc SUNSI Rev Compl. Yes No ADAMS Yes No Reviewer Initials CFO Publicly Avail Yes No Sensitive Yes No Sens. Type Initials CFO DRS/EB2 DRS/EB2 DRS/PSB2 RI:DRS/EB1 DRS/EB2 GPick JWatkins LCarson GMeyer AErickson /RA/ /RA/ /RA/ /RA/ /RA/ 11/8/10 10/28/10 10/28/10 11/4/10 10/28/10 DRP/PBE C:DRS/EB2 C:DRP/PBB
JMelfi NO'Keefe DAllen /RA/ /RA/ /RA/ 10/28/10 11/17/10 11/16/10 OFFICIAL RECORD COPY T=Telephone E=E-mail F=Fax
- 1 - Enclosure U.S. NUCLEAR REGULATORY COMMISSION REGION IV
Dockets: 05000275, 05000323
Licenses: DPR-80, DPR-82 Report: 05000275/2010008, 05000323/2010008 Applicant: Pacific Gas and Electric Company Facility: Diablo Canyon Power Plant, Units 1 and 2 Location: 7 1/2 miles NW of Avila Beach Avila Beach, California
Dates: August 16 through September 16, 2010 Inspectors: G. Pick, Senior Reactor Inspector L. Carson, Senior Reactor Inspector G. Meyer, Senior Reactor Inspector J. Watkins, Reactor Inspector
J. Melfi, Reactor Engineer A. Erickson, Reactor Inspector
Approved By: Neil O'Keefe, Chief Engineering Branch 2 Division of Reactor Safety
- 2 - Enclosure TABLE OF CONTENTS
SUMMARY OF FINDINGS ..........................................................................................................
3 REPORT DETAILS ..................................................................................................................... 4 OTHER ACTIVITIES 4OA5 Other - License Renewal........................................................................................ 4 a. Inspection Scope ............................................................................................... 4 b.1 Evaluation of Scoping of Nonsafety-Related Structures, Systems, and Components ............................................................................................. 4
b.2 Evaluation of New Aging Management Programs ............................................ 6 .1 B2.1.16 One-Time Inspection (XI.M32) .................................................... 7 .2 B2.1.17 Selective Leaching of Materials (XI.M33) .................................... 7 .3 B2.1.18 Buried Piping and Tanks Inspection (XI.M34) ............................. .8 .4 B2.1.20 External Surfaces Monitoring (XI.M36) ...................................... 10 .5 B2.1.24 Electrical Cables and Connections Not Subject To 10 CFR 50.49 Environmental Qualification Requirements (XI.E1) ................................. 11 .6 B2.1.35 Electrical Connections Not Subject To 10 CFR 50.49 Environmental Qualification Requirements (XI.E6) ........................................................ 12
b.3 Evaluation of Existing Aging Management Programs ..................................... 13 .1 B2.1.2 Water Chemistry (XI.M2) ............................................................. 14
.2 B2.1.4 Boric Acid Corrosion (XI.M10) ..................................................... 15 .3 B2.1.6 Flow-Accelerated Corrosion (XI.M17) ......................................... 16 .4 B2.1.9 Open-Cycle Cooling Water System (XI.M20) .............................. 17 .5 B2.1.10 Closed-Cycle Cooling Water System (XI.M21) .......................... 18 .6 B2.1.13 Fire Water System (XI.M27) ...................................................... 21
.7 B2.1.14 Fuel Oil Chemistry (XI.M30) ...................................................... 22 .8 B2.1.23 Lubricating Oil Analysis (XI.M39) .............................................. 24 .9 B2.1.26 Inaccessible Medium Voltage Cables Not Subject To 10 CFR 50.49 Environmental Qualification Requirements (XI.E3) ................................. 25 .10 B2.1.27 ASME Section XI, Subsection IWE (XI.S1) .............................. 27 .11 B2.1.28 ASME Section XI, Subsection IWL (XI.S2) .............................. 28 .12 B2.1.29 ASME Section XI, Subsection IWF (XI.S3) .............................. 29 .13 B2.1.30 10 CFR Part 50, Appendix J (XI.S4) ........................................ 30 .14 B2.1.31 Masonry Wall Program (XI.S5) ................................................ 31 .15 B2.1.32 Structures Monitoring Program (XI.S6) .................................... 31
.16 B2.1.33 Regulatory Guide 1.127 Inspection of Water-Control Structures Associated with Nuclear Power Plants (XI.S7) ....................................... 32 .17 B2.1.36 Metal-Enclosed Bus (XI.E4) .................................................... 33 .18 B2.1.38 Transmission Conductor, Connections, Insulators, and Switchyard Bus Connections (PS) ............................................................................ 34
b.4 System Reviews ............................................................................................ 36
b.5 Significant Replacement Activities.................................................................. 38 c. Overall Conclusion ........................................................................................... 38
4OA6 Meetings, Including Exit ........................................................................................ 38 SUPPLEMENTAL INFORMATION .................................................................................... A-1
- 3 - Enclosure SUMMARY OF FINDINGS
IR 05000275/2010008, 05000323/2010008; 08/16/2010 - 09/16/2010; Diablo Canyon Power Plant, Scoping of Nonsafety-Related Affecting Safety-Related Systems and Review of License Renewal Aging Management Programs
NRC inspectors from Region IV and Region I performed onsite inspections of the applicant's license renewal activities. The team performed the evaluations in accordance with Manual Chapter 2516, "Policy and Guidance for the License Renewal Inspection Programs," and Inspection Procedure 71002, "License Renewal Inspection." The team did not identify any
findings as defined in NRC Manual Chapter 0612.
The team concluded the applicant adequately performed screening and scoping of nonsafety-related structures, systems, and components as required in 10 CFR 54.4(a)(2). The team concluded that the applicant conducted an appropriate review of the materials and environments and established appropriate aging management programs, as described in the license renewal application and as supplemented through responses to requests for additional
information from the NRC. The team found that the applicant provided the documentation that supported the application and inspection process in an auditable and retrievable form. The team identified a number of issues that resulted in changes to the application, programs, and procedures.
Based on the samples reviewed by the team, the inspection results supported a conclusion of reasonable assurance that actions have been identified and have been taken or planned to manage the effects of aging in the structures, systems, and components identified in the application and that the intended functions of these structures, systems, and components would be maintained in the period of extended operation.
A. NRC-Identified and Self-Revealing Findings
No findings of significance were identified
B. Licensee-Identified Violations
No findings of significance were identified.
- 4 - Enclosure REPORT DETAILS
4. OTHER ACTIVITIES (OA)
4OA5 Other - License Renewal
a. Inspection Scope (IP 71002)
NRC inspectors performed this inspection to evaluate the thoroughness and accuracy of the applicant's screening and scoping of nonsafety-related structures, systems, and
components (SSC), as required in 10 CFR 54.4(a)(2). The team evaluated whether aging management programs will be capable of managing identified aging effects in an appropriate manner.
In order to evaluate scoping activities, the team selected a number of SSCs for review to evaluate whether the methodology used by the applicant appropriately addressed the nonsafety-related systems affecting the safety functions of a structure, system, or
component within the scope of license renewal. In addition, because of several requests for additional information related to scoping of nonsafety-related systems affecting safety-related systems, the team conducted walkdowns to verify information in the responses provided by the applicant.
The team selected a sample of 24 of the 40 aging management programs developed by the applicant to verify the adequacy of the applicant's guidance, implementation activities, and documentation. The team evaluated the programs to determine whether the applicant would appropriately manage the effects of aging and to verify that the applicant would maintain the component safety functions during the period of extended
operation.
The team reviewed supporting documentation and interviewed applicant personnel to confirm the accuracy of the license renewal application conclusions. For a sample of plant structures and systems, the team walked down accessible portions of the systems to observe aging effects. During the plant walkdowns, the team reviewed the material condition of the SSCs.
b.1 Evaluation of Scoping of Nonsafety-Related Structures, Systems, and Components
For scoping and screening, the team reviewed the applicant's program guidance and scoping and screening results for the facility to assess the thoroughness and accuracy of the methods used to bring SSCs within the scope of the license renewal application. Further, the team assessed documentation related to scoping nonsafety-related SSCs, as required in 10 CFR 54.4(a)(2). The team verified that the applicant established procedures consistent with the NRC-endorsed guidance contained in Nuclear Energy Institute 95-10, "Industry Guideline for Implementing the Requirements of 10 CFR Part
54 - The License Renewal Rule," Revision 6, Appendix F, Sections 3, 4, and 5. The team assessed whether the applicant evaluated (1) nonsafety-related SSCs within the scope of the current licensing basis, (2) nonsafety-related SSCs directly connected to safety-related SSCs, and (3) nonsafety-related SSCs not directly connected but spatially near safety-related SSCs, respectively.
- 5 - Enclosure
The team reviewed license renewal drawings, sampling between Units 1 and 2. The applicant had color-coded the drawings to indicate in-scope systems and components required by 10 CFR 54.4(a)(1), (a)(2), and (a)(3). The team interviewed personnel, reviewed program documents and independently walked down numerous areas and
structures within the plant, which included:
- Units 1 and 2 auxiliary buildings
- Units 1 and 2 turbine building
- Diesel generator rooms 1-3, 2-1, and 2-3
- Units 1 and 2 closed cooling water heat exchanger rooms
- Intake structure
- Oily waste sump room
- Unit 1 diesel generator fuel oil storage vault
- Discharge structure
- Raw water ponds
- 230 kV and 500 kV switchyards
For SSCs selected because of potential spatial interactions, where failure of nonsafety-related SSCs could adversely affect adjacent safety-related components, the
team determined that the applicant continued to submit changes to their license renewal application to accurately categorize the in-plant configuration in response to requests for additional information. The team determined the personnel involved in the process were knowledgeable and appropriately trained.
For SSCs selected because of potential structural interactions caused by an earthquake, the team determined that the applicant accurately identified and categorized the structural boundaries. Based on independent sampling of the isometric drawings and the seismic boundary determinations, the team determined that the applicant appropriately identified the seismic design boundaries and correctly included the
applicable SSCs within the license renewal scope.
Subsequent to the application submittal, the applicant added portions of additional systems to those already in scope based on lessons learned from another applicant and deficiencies identified during the Division of License Renewal scoping and screening audit. Specifically, the applicant determined that they had not adequately evaluated situations where age-related failures of systems in the turbine building could have affected nearby safety-related cables.
The team evaluated the plant configurations for SSCs that had been added since the
scoping and screening audit conducted in March 2010. Specifically, the team conducted interviews, reviewed walkdown reports, and walked down configurations of SSCs in the plant to evaluate the impact of nonsafety-related SSCs affecting safety-related SSCs in the turbine building, terminations points in the compressed air system, the configuration of the oily waste sump, and the configuration of SSCs in the diesel generator fuel oil vaults. Specifically, the team:
- 6 - Enclosure
- Verified that nonsafety-related service cooling water piping entered and exited the Diesel Generator 2-3 room and did not enter the other diesel generator rooms. * Verified that no safety-related electric cables entered the oily waste sump room by reviewing plant drawings and walking down the oily waste sump.
- Verified that water spray from the service cooling water surge tank would not have affected the safety-related control room pressurization system components. Further, the team determined that control room pressurization electrical and instrumentation system components would not be affected.
- Verified that the applicant evaluated the impact of high-energy fluid piping failures on in-scope safety-related components in the turbine building.
- Verified that the applicant identified nonsafety-related components that could impact Class II components required to respond to a seismic event.
The applicant issued Notification 50341848 to document that they had not included the service cooling water surge tank as a component within the scope of license renewal.
The team determined the applicant planned to revise Topical Report TR-6DC, "Criterion (a)(2) - License Renewal Feasibility Study Position Paper," Revision 1. The revised topical report would describe their basis for excluding the service water system surge tank since the tank would not impact the control room pressurization system. The team considered this an appropriate resolution after verifying that the water spray would
not affect the control room pressurization system components.
In summary, the team concluded that the applicant had implemented an acceptable method of scoping of nonsafety-related SSCs and that this method resulted in accurate scoping determinations for the samples reviewed with some exceptions noted.
b.2 Evaluation of New Aging Management Programs
The team reviewed six of the nine new aging management programs to determine whether the applicant had established appropriate actions or had actions planned to manage the effects of aging. At the time of the inspection, the applicant had completed many of the elements identified in the programs, including drafting implementing
procedures. The team reviewed site-specific operating experience to determine whether there were any aging effects for the systems and components within the scope of these programs that had not been identified when considering applicable industry operating experience.
The team selected in-scope SSCs to assess how the applicant maintained plant equipment under existing programs and to visually observe examples of nonsafety-related equipment determined to be within scope because of the proximity to safety-related equipment and the potential for failure as a result of aging effects.
- 7 - Enclosure .1 B2.1.16 One-Time Inspection (XI.M32)
The one-time inspection program was a new program, consistent with NUREG-1801, "Generic Aging Lessons Learned (GALL Report) Tabulation of Results," Volume 2, Revision 1 (hereafter referred to as the GALL Report). The applicant credited the one-
time inspection program with verifying the effectiveness of the Water Chemistry, Fuel Oil Chemistry, and Lubricating Oil Analysis programs through nondestructive evaluation of a sample of components maintained by these programs. Qualified personnel will perform the nondestructive evaluation by using procedures and processes consistent with the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code
and 10 CFR Part 50, Appendix B. The applicant planned to implement these inspections in the 10 years prior to the period of extended operation.
The team reviewed the license renewal application, the NRC aging management program audit results, aging management program evaluation report, and program procedure. The team evaluated the bases used to identify the inspection samples, and the team discussed the program evaluations and planned activities with the responsible
staff. The team noted that the applicant had evaluated component data, established a detailed sampling plan based on the material and environment combinations, and identified a population of 35 samples to inspect out of an estimated 12,000 components. The team
informed the applicant that the NRC and industry had developed improved guidelines for identifying samples based on combinations of materials and the environment. The new guidance was to be included in the next revision of the GALL Report. Applying the improved guidance at Diablo Canyon would result in a more appropriate, increased number of samples for the program. Further, the team noted that the applicant's
sampling approach emphasized testing of the material judged to be most susceptible to degradation (typically carbon steel), which could result in failure to identify other susceptible materials. The team considered that the inspection scope should be expanded to other potentially susceptible materials. The applicant initiated Notification 50341874 to re-evaluate the sampling plan to identify the appropriate sample
size and scope and address the above concerns.
For the one-time inspection program, the team concluded that the applicant had performed appropriate evaluations and considered pertinent industry experience and plant operating history to determine the effects of aging in the affected systems. The
team concluded that, if implemented as described including re-evaluating the sample size and the sampling plan scope of materials to identify the most appropriate samples, the applicant provided guidance to appropriately identify and address aging effects during the period of extended operation.
.2 B2.1.17 Selective Leaching of Materials (XI.M33)
The Selective Leaching of Materials program was a new program, consistent with the GALL Report, credited with managing the aging of components made of cast iron, bronze, brass, and other alloys exposed to raw water, treated water, soil, or other environments that may lead to selective leaching. The program will include a one-time visual inspection of a sample of components with metallurgical properties susceptible to
- 8 - Enclosure selective leaching to determine whether loss of material has occurred and to determine whether any identified selective leaching would affect the ability of the components to perform the intended function during the period of extended operation.
The team reviewed the license renewal application, the NRC aging management
program audit results, aging management program evaluation report, and program procedure. The team evaluated the basis used to identify the inspection sample and discussed the program evaluations and planned activities with the responsible staff.
The team also evaluated site-specific operating experience by reviewing relevant action
requests. The team noted that Diablo Canyon had previously identified that the December 2008 failure of a buried, gray cast iron fire water system pipe had occurred because of selective leaching. The team concluded that the selective leaching program should be revised to address this known aging effect, including specifying on-going aging management activities to address this aging effect and updating the application, if appropriate. The applicant issued Notification 50341752 to evaluate the most appropriate aging management program to use to monitor this piping.
The team noted that, in 1997, the applicant had also identified indications of "dealloying" on aluminum bronze saltwater system valves. The team was concerned that this dealloying could have resulted from selective leaching of the aluminum bronze. The team concluded that two planned samples of the 26 such components provided an
insufficient sample based on this possibility. The applicant would not be able to thoroughly evaluate whether selective leaching existed on this material and environment combination without increasing the sample size or performing destructive examination. The applicant agreed with the team's concern and added this additional concern in Notification 50341752 to consider revising the sampling plan.
For the Selective Leaching of Materials program, the team concluded that the applicant had performed appropriate evaluations and considered pertinent industry experience and plant operating history, with exceptions noted above, to determine the effects of aging in components and systems that have metal alloys subject to this aging
mechanism. The team concluded that, pending specification of suitable aging management activities for gray cast iron fire protection system piping and aluminum bronze auxiliary saltwater piping and, if implemented as described, the applicant provided guidance to appropriately identify and address aging effects during the period of extended operation.
.3 B2.1.18 Buried Piping and Tanks Inspection (XI.M34)
The Buried Piping and Tanks Inspection program was a new program, consistent with the GALL Report, credited with managing cracking, loss of material, and change in the surface conditions of buried components. The applicant included asbestos cement piping in this aging management program because the in-scope fire water systems had
this type of piping. The applicant identified that they would manage the effects of aging through inspection either during an opportunistic excavation for other maintenance or during a specifically planned excavation. The applicant will perform one excavation prior to the period of extended operation and one excavation within the first 10 years of the
- 9 - Enclosure period of extended operation. This program included the auxiliary saltwater, diesel generator fuel transfer, fire protection, and the makeup water systems.
The team reviewed the license renewal application, the NRC aging management program audit results, and applicant's responses to requests for additional information.
The team interviewed the system engineers for the auxiliary saltwater, diesel fuel oil transfer and storage, fire protection, and cathodic protection systems. The team interviewed personnel cognizant of aspects of the buried pipe program, including the program owner. The team reviewed the program documents, drawings, corrective actions for previous buried piping issues, plant-specific operating experience
evaluations, and procedures. The team also evaluated applicant activities related to the operation and maintenance of the cathodic protection system.
The applicant took two exceptions to the GALL Report. The applicant included buried stainless steel and asbestos cement piping because the applicant had in-scope systems that contained these materials (Elements 1 and 3). The applicant planned visual inspections of stainless steel piping that was not coated or wrapped to detect loss of
material resulting from corrosion. Also, visual inspections of buried asbestos cement piping that was not coated or wrapped will be performed to detect evidence of cracking, loss of material, and material changes in surface conditions (Elements 1, 2, 3, 4, and 6). The team agreed that these exceptions ensured that the applicant would meet the intent of the GALL Report after including unwrapped stainless steel and asbestos lined cement
piping within the scope of license renewal. The applicant had included applicable requirements for conducting the piping and tank inspections for to be consistent with the GALL Report.
The team determined that the applicant had recently upgraded the cathodic protection
system and programs. Nuclear Energy Institute 09-14, "Guideline for the Management of Buried Pipe Integrity," dated January 2010, recommended following the guidance contained in Electric Power Research Institute Report 1016456, "Recommendations for an Effective Program to Control the Degradation of Buried Pipe." The initiative included ranking piping that contained regulated material. The team determined that the
applicant had taken actions prior to this initiative to understand and monitor the condition of underground piping. Further, the team determined that the applicant adopted appropriate milestone dates recommended in the initiative letter and had initiated actions to begin risk ranking the systems by January 2011. Also, the applicant was implementing Procedure TS5.ID3, "Buried Piping and Tanks Program," Revision 1, as
part of its groundwater contamination and protection initiative.
As a result of external operating experience related to degradation of fire protection systems caused by inadequate backfilling of soil around the piping, the applicant reviewed their fire protection piping design conditions. The applicant determined that original methods of backfilling soil onto the fire protection piping were unlikely to degrade fire protection piping. The applicant further determined that the fire protection pipe
installation met the nonsafety-related pipe installation specifications, and once buried components were replaced the system would last beyond the re-licensed period. The applicant had replaced the safety-related fuel oil storage and transfer tanks and piping to comply with state regulations. In 1997 and 1998 for Units 1 and 2, respectively, the applicant replaced portions of the auxiliary saltwater piping.
- 10 - Enclosure
For the Buried Piping and Tanks Inspection program, the team concluded that the applicant had performed appropriate evaluations of the piping conditions and considered pertinent industry experience and plant operating history to determine the effects of aging on buried piping and tanks. The team concluded that, if implemented as
described, the applicant developed guidance to appropriately identify and address aging effects during the period of extended operation.
.4 B2.1.20 External Surfaces Monitoring (XI.M36)
The External Surfaces Monitoring program was a new program, consistent with the GALL Report, credited with managing loss of material for external surfaces of steel, aluminum, copper alloy components, as well as hardening and loss of strength for elastomers in ventilation and mechanical systems. Because the applicant had copper and aluminum alloy components, the applicant expanded the inspections to include those items. The applicant will also visually inspect for aging effects related to hardening and loss of strength of elastomers. The program will use visual inspections
during engineering walk downs each refueling cycle to evaluate the condition of bolting, ducting, fans, and flexible connections in ventilation systems, and external surfaces of pumps, valves, piping, tanks, expansion joints, and other mechanical components. During the 10 years prior to the period of extended operation, the applicant planned to incorporate additional plant-specific operating experience and associated lessons
learned into this aging management program and their procedures.
The team reviewed license renewal program basis documents, aging management review documents, existing and draft procedures, long-range planning documents, and system engineer qualification procedures. The team interviewed personnel involved with
the development of the external surface inspection procedure and performed walk downs to assess the external condition of piping and components. The team confirmed that system engineers presently monitored the external surfaces of their systems in accordance with the guidance contained in Procedure TS5.ID1, "System Engineering Programming," Revision 15.
The applicant took three exceptions to the GALL Report that expanded the scope of the program (Elements 1, 3, and 4). The first exception included expanding the visual inspections for the effects of aging to include aluminum, copper alloy, and elastomers. Because the applicant included elastomers within this program, the second exception
identified elastomer hardening and loss of strength as additional aging effects that required managing. The third exception specified manually moving elastomers as an appropriate method to augment the visual inspections. The team considered these exceptions appropriate since they expanded the program to include materials of in-scope components and included actions to manage the effects of aging. Although the applicant had historically required system engineers to look for degraded conditions, the applicant had not specifically identified those conditions (e.g., corrosion, through wall
leaks) as signs of aging effects in Procedure TS5.ID1, the applicant considered this a new program.
- 11 - Enclosure
The team determined from review of corrective action documents that system engineers had successfully identified degraded conditions on plant equipment external surfaces since establishing system engineers in 1993. Issues identified included systems within the scope of license renewal, and involved corrosion, leaks, and pitting issues. The
team concluded that the applicant implemented the current program in a manner that detected and corrected age-related degradation of external surfaces.
The applicant specified that personnel performing external surface inspections would be specifically qualified. The team reviewed the type of external surface inspection training
that system engineers have had related to erosion, corrosion, and degraded coatings on piping. The team reviewed training records of several system engineers related to the qualification specified in Procedure TS5.ID1. The team determined that the training provided to system engineers at the time of the inspection did not meet the commitment the applicant described in the External Surfaces Monitoring program aging management program evaluation report. The applicant initiated Notification 50335453 to identify this deficiency and to identify the new training and skills to ensure system engineers could
effectively monitor external corrosion and material condition of structures systems and components, as required by this program. The applicant indicated that they would provide the appropriate training to personnel based upon the analysis as part of their Project Plan for License Renewal Implementation.
For the External Surfaces Monitoring program, the team concluded that the applicant had performed appropriate evaluations and considered pertinent industry experience and plant operating history to determine the effects of aging on the external surfaces of the included components. The team concluded that, if implemented as described, the applicant provided guidance to appropriately identify and address aging effects during
the period of extended operation.
.5 B2.1.24 Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements (XI.E1)
The Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements program was a new program, consistent with the GALL Report, credited with managing the aging effects of cables/cable jackets, connections and terminal blocks exposed to adverse localized environments caused by heat, radiation, or moisture. The aging effects included embrittlement, melting, cracking,
swelling, surface contamination, or discoloration of cables, connections, and terminal blocks. The applicant planned to monitor the aging effects through periodic visual inspections of cables, connectors and terminal blocks in accessible areas. As further specified in the GALL Report for inaccessible cables, the applicant planned to use engineering evaluations to demonstrate that they would be similarly unaffected or requires corrective actions. The applicant will complete the first inspection sample of these cables prior to entering the period of extended operation and once every 10 years
thereafter. At the time of the inspection the applicant had not established a sample size for evaluation.
- 12 - Enclosure
The team reviewed relevant license renewal program basis documents, aging management review documents, existing and new procedures, plant specific operating experience, and preventive maintenance requirements. The team interviewed the license renewal project personnel and the responsible engineers. The team walked
down numerous accessible areas within the plant where cable trays and exposed cables were installed, including the cable spreading rooms. The team interviewed plant personnel regarding their plans for developing a procedure and conducting these aging effects evaluations. Plant personnel described that their program will be closely modeled on, and incorporate the guidance in, Electric Power Research Institute
Report TR-109619, "Guideline for Management of Adverse Localized Environments," dated June 1999.
From review of plant-specific operating experience, the team identified examples where the applicant had already successfully identified aging of cables and replaced cables subject to adverse localized environments. In 1992, a scheduled inspection of Reactor Coolant Pump 1-4 identified heat related cracking of the cable jacket in the high
temperature environment surrounding the reactor coolant pump terminal box. Because the cable continued to deteriorate, the applicant replaced the power cables for all of the reactor coolant pumps to protect against future failure. The applicant performed follow-up inspections as part of normal plant maintenance, testing, and inspections and had not identified any additional degradation for the replaced cables.
For the Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements program, the team concluded that the applicant had performed appropriate evaluations and considered pertinent industry experience and plant operating history to determine the effects of aging for cables/cable jackets,
connections, and terminal blocks exposed to adverse localized environments. The team concluded that, if implemented as described, the applicant provided guidance to appropriately identify and address aging effects during the period of extended operation.
.6 B2.1.35 Electrical Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements (XI.E6)
The Electrical Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements program was a new, one-time program, consistent with the GALL Report, credited with managing aging effect of loosening of bolted external connections because
of thermal cycling, ohmic heating, electrical transients, vibration, chemical contamination, corrosion, and oxidation to ensure that electrical connections remained capable of performing their intended function.
The team reviewed relevant license renewal program basis documents, aging management review documents, existing and new procedures, and preventive maintenance requirements. The team interviewed license renewal project personnel
and the responsible engineers. Because this is a new one-time inspection program, the applicant had not yet developed any program or procedure documents for performing these inspections to verify whether a periodic aging management program would be required.
- 13 - Enclosure The applicant took exception to the GALL Report periodic program and specified a one-time program in accordance with draft interim staff guidance. The interim staff guidance, the draft GALL Report, Revision 2 and the applicant's program narrowed the scope of connections to external connections, specifically excluding internal connections, limiting the frequency of testing, and adjusting the sample size of
connections to be tested. Therefore, the team concluded the applicant had established a program consistent with the latest NRC guidance and consistent with the intent of the GALL Report.
The applicant planned to: (1) conduct a one-time test of a representative sample of
external connections prior to the period of extended operation using infrared thermography to determine whether aging effects existed that require management; (2) select the sample based upon application (medium and low voltage), circuit loading (high load), and environment (temperature, high humidity, vibration, etc.), and (3) document the technical basis for the sample selected and the acceptance criteria used for each inspection or test for the specific type of cable connections. The applicant had not developed a specific sample size at the time of the inspection.
The applicant planned to establish acceptance criteria for thermography testing on the temperature rise above the reference temperature. The reference temperature will be the ambient temperatures or baseline temperature data from the same type of connections being tested. If thermography inspection was not possible or if the results
were inconclusive, the connection integrity can be confirmed by another acceptable connection integrity test method such as contact resistance measurement.
The applicant routinely performed infrared thermography on electrical components and connections as part of the current predictive maintenance program. A search and
review of the plant operating experience identified electrical connections showing thermal anomalies that resulted from significant temperature variances between phases or from normal temperatures. When the applicant detected anomalies, they monitored the condition closely for degradation or initiated corrective actions. No loss of equipment intended function had occurred.
For the Electrical Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements program, the team concluded that the applicant had performed appropriate evaluations and considered pertinent industry experience and plant operating history to determine the effects of aging on electrical connections. The team
concluded that, if implemented as described, the applicant provided guidance to appropriately identify and address aging effects during the period of extended operation that was consistent with the current licensing basis.
b.3 Evaluation of Existing Aging Management Programs
The team sampled 18 of the 31 existing aging management programs, which included
one plant specific aging management program, to determine whether the applicant had taken or planned to take appropriate actions to manage the effects of aging, as specified in the GALL Report.
- 14 - Enclosure The team reviewed site-specific operating experience to determine whether there were any aging effects for the systems and components within the scope of these programs that had not been identified from the applicant's review of industry operating experience.
The team evaluated whether the applicant implemented or planned to implement
appropriate actions to manage the affects of aging. These programs have established procedures, records of past corrective actions, and previous operating experience related to applicable components. Further, some programs required the applicant to implement enhancements (i.e., program aspects that will be implemented prior to the period of extended operation) to ensure consistency with the GALL Report.
The team walked down selected in-scope SSCs to assess how the applicant maintained plant equipment under the current operating license, to visually observe examples of nonsafety-related equipment determined to be in-scope because of the proximity to safety-related equipment, and to assess the potential for failure as a result of aging effects.
.1 B2.1.2 Water Chemistry (XI.M2)
The Water Chemistry program was an existing program, consistent with the GALL Report, credited with managing the effects of aging caused by cracking, denting, hardening and loss of strength, loss of material, reduction of heat transfer, and wall
thinning in primary and secondary water systems. The Water Chemistry program maintained the chemical environment in the reactor coolant system and related auxiliary systems, and maintained the chemical environment in the steam generator secondary side and the secondary cycle systems. The one-time inspection program described inspections planned to verify the effectiveness of chemistry control programs by
evaluating whether significant degradation has occurred prior to entry into the period of extended operation.
The team reviewed the license renewal application, the NRC aging management program audit results, the aging management program evaluation report, and program
procedures. The team also reviewed: site strategic chemistry plans; chemistry operating experience evaluations; chemistry procedures; chemistry-related action requests; and primary and secondary chemistry data/trends for the past 5 years. In addition, the team interviewed plant chemists. The team verified that the applicant administered the water chemistry programs in accordance with Technical Specifications
and guidance contained in Electrical Power Research Institute Reports TR-1014986, "Pressurized Water Reactor Primary Water Chemistry Guidelines," Revision 6, and TR-1016555, "Pressurized Water Reactor Secondary Water Chemistry Guidelines," Revision 7. The team reviewed the last three quality assurance chemistry audits and the periodic quality verification reports completed since 2005.
The team determined that the applicant had maintained their chemistry parameters well
within their administrative limits and had not exceeded any action levels. The team verified that the applicant took appropriate corrective actions in response to deficiencies identified in corrective action documents. The applicant used zinc injection to help minimized primary water stress corrosion cracking in their steam generators by creating a protective oxide layer. The applicant maintained a lithium control program to create a
- 15 - Enclosure pH environment that was not conducive to corrosion in the primary plant. The licensee established a reducing environment in their steam generators by addition of an amine and hydrazine to scavenge oxygen.
For the Water Chemistry program, the team concluded that the applicant had performed
appropriate evaluations and considered pertinent industry experience and plant operating history to determine the effects of aging. The team concluded that, if implemented as described, the applicant provided guidance to appropriately address aging effects for the reactor coolant system and the steam generators during the period of extended operation.
.2 B2.1.4 Boric Acid Corrosion (XI.M10)
The Boric Acid Corrosion program was an existing program, consistent with the GALL Report, credited with managing the loss of material resulting from boric acid leakage. The program implemented the recommendations in NRC Generic Letter 88-05, "Boric Acid Corrosion of Carbon Steel Pressure Boundary Components in PWR Plants," to
monitor the condition of the reactor coolant pressure boundary for borated water leakage. The program inspected for leakage during normal operations and during reactor coolant system pressure tests, identified leak paths and quantified the leakage, removed the boric acid residues, assessed for any damage caused by boric acid leakage, and conducted follow-up inspections to verify the adequacy of corrective
actions taken to isolate the leakage. The program maintained tracking and trending records for boric acid leakage from plant components and established a component-based visual history of boric acid leakage/seepage. The applicant managed the effects of aging by visually inspecting the external surfaces of mechanical and structural components in any system that contained borated water and protected electrical components on which borated water may leak.
The team reviewed the aging management program evaluation report, the NRC aging management program audit report, implementing procedures, self assessments, relevant action requests, notifications, work orders, summaries of associated plant and
industry operating experience, and the applicant's tracking data base of boric acid indications. In addition, the team discussed program development, response to NRC generic communications, program implementation, and self-assessment results with engineers to understand the program and how assessments and operating experience have been incorporated into the program. The team walked down accessible systems
containing borated water to assess the material condition of plant components and the status of any boric acid leakage. The team reviewed corrective actions taken for leaks identified during boric acid inspections to assess the effectiveness of the program for identifying, monitoring, trending, and correcting boric acid leaks from systems containing borated water.
For the Boric Acid Corrosion program, the team concluded that the applicant had
performed the appropriate evaluations and considered pertinent industry experience and site-specific operating history to determine the effects of aging on piping and component surfaces. The team concluded that, if implemented as described, the applicant provided guidance to appropriately identify and address aging effects during the period of extended operation.
- 16 - Enclosure .3 B2.1.6 Flow-Accelerated Corrosion (XI.M17)
The Flow-Accelerated Corrosion program was an existing program, consistent with the GALL Report, designed to manage wall thinning resulting from flow-accelerated corrosion on the internal surfaces of carbon or low alloy steel piping, elbows, reducers,
expanders, and valve bodies that contain high energy fluids (both single-phase and two-phase fluids). The program implemented the Electric Power Research Institute guidelines in NSAC-202L, "Recommendations for an Effective Flow-Accelerated Corrosion Program," Revision 3, using Procedures TS1.ID1, "Flow-Accelerated Corrosion Monitoring Program Interfaces and Responsibilities," Revision 2,
and TS1.NE1, "Flow-Accelerated Corrosion Monitoring Program," Revision 6, to detect, measure, monitor, predict, and mitigate component wall thinning.
The team reviewed applicable license renewal program basis documents, aging management review documents, and existing procedures. In addition, the team searched the applicant's corrective action database for relevant operating experience. The team also interviewed plant personnel, examined specimens of piping
demonstrating the effects of flow-accelerated corrosion, and reviewed specifications for specific chromium-content piping.
The team determined that the GALL Report endorsed Revision 2 of NSAC-202L. The team reviewed an Electric Power Research Institute document that compared
NSAC-202L, Revisions 2 and 3, and determined that Revision 3 incorporated lessons learned and improvements to detection, modeling, and mitigation technologies that became available since the Electric Power Research Institute had published Revision 2. The updated recommendations refined and enhanced those of previous revisions without contradictions to ensure continuity of existing plant flow-accelerated corrosion
programs.
The applicant achieved the objectives of the Flow-Accelerated Corrosion program by: (1) identifying system components susceptible to flow-accelerated corrosion; (2) performing analysis using the predictive code CHECWORKS to determine critical
locations for inspection and evaluation; (3) providing guidance for follow-up inspection; (4) repairing, replacing, or performing evaluations for components not acceptable for continued service; and (5) evaluating and incorporating the latest technologies, industry and site-specific operating experience. The team determined the procedures and methods used in the flow-accelerated corrosion program were consistent with
commitments to Bulletin 87-01, "Thinning of Pipe Wall in Nuclear Power Plants," and Generic Letter 89-08, "Erosion/Corrosion-Induced Pipe Wall Thinning."
To aid in the planning of inspections and choosing inspection locations, the applicant utilized Electric Power Research Institute predictive code CHECWORKS that used the implementation guidance described in NSAC-202L, Revision 3. The applicant periodically updated the CHECWORKS model based on the inspection results, changes
in the plant design or operating conditions, and changes in pipe configurations. For example, the applicant included criteria in the model to account for small bore piping inspections for piping 2 to 4 inches in diameter. However, the applicant did not model small-bore piping with a nominal diameter of two inches or less since it was not suitable for CHECWORKS modeling.
- 17 - Enclosure
For the Flow-Accelerated Corrosion program, the team concluded that the applicant had performed appropriate evaluations and had considered pertinent industry experience and plant operating history to determine the effects of aging on carbon and low-alloy steel piping and component surfaces. The team concluded that, if implemented as
described, the applicant provided guidance to appropriately identify and address aging effects during the period of extended operation.
.4 B2.1.9 Open-Cycle Cooling Water System (XI.M20)
The Open-Cycle Cooling Water System program was an existing program, consistent with the GALL Report, credited with managing the aging effects resulting from material loss and reduction of heat transfer for components in, or cooled by, open-cycle cooling water systems. The applicant managed the aging effects of material loss and heat transfer reduction through heat exchanger performance monitoring and periodic maintenance, surveillance tests and chemistry control techniques. The applicant implemented the maintenance and test requirements in accordance with their
commitments to Generic Letter 89-13, "Service Water System Problems Affecting Safety-Related Equipment," dated July 18, 1989, and in response to Letters DCL 94-037, "Auxiliary Saltwater System Operability," dated February 15, 1994, and DCL 94-174, "Reply to Notice of Violation in NRC Enforcement Action 94-056 (NRC Inspection Report Nos. 50-275/94-08 and 50-323/94-08), dated June 3, 1994. The
components included within the scope of this program included the auxiliary saltwater system piping and the component cooling water heat exchangers.
The team reviewed the implementing procedures and selected test results related to pipe inspections, monthly flow tests, intake bay inspections, and heat exchanger
macrofouling inspections for each component cooling water heat exchanger. The team reviewed selected corrective actions for identified deficiencies. In addition, the team interviewed the program manager and walked down accessible portions of the auxiliary saltwater piping. The team determined from interviews with the program owner, reviews of selected heat transfer test results, and other pipe inspection information that the
applicant successfully monitored heat transfer and loss of material in component cooling water heat exchangers and auxiliary saltwater piping, respectively. The team verified that Procedure MA1.ID20, "Testing and Inspections for the Auxiliary Saltwater System for Compliance with NRC Generic Letter 89-13," Revision 2, appropriately established requirements to perform activities that enabled the applicant to manage the effects of
aging. The team verified that the applicant continuously chlorinated the auxiliary saltwater system and alternated flow through each component cooling water heat exchanger weekly to minimize low flow and stagnant areas and to ensure that each heat exchanger was chlorinated to minimize microbiologically induced corrosion and biological fouling. From a review of the heat exchanger test results, the team determined that the mid-cycle
and refueling outage heat exchanger tube cleaning by a mechanical brush ensured the heat exchanger remained capable of removing the design basis heat load. The applicant inspected the inside of the auxiliary saltwater piping at the intake structure, the component cooling water heat exchangers, and the vacuum breaker vaults on a 4-cycle frequency. From a review of corrective action documents, the team determined that the
- 18 - Enclosure applicant effectively monitored for corrosion inside the auxiliary saltwater piping and maintained the plastic pipe coating in good condition. The applicant conducted eddy current testing on 20 percent of the tubes in each component cooling water heat exchanger every refueling outage plus any tubes that had prior evidence of wall thinning.
From a review of Procedure MA1.ID20, the team determined that the applicant identified that heat transfer testing was prudent although not required by their commitments to Generic Letter 89-13. The team verified that the applicant had completed heat transfer tests on each of the heat exchangers prior to entering refueling outages since 2004. In addition, the component cooling water heat exchangers were tested prior to each outage
to demonstrate their heat transfer capability. The team identified that the current program procedure did not match the commitments specified in the license renewal application. Notification 50359698 documented the need to revise Procedure MA1.ID20 to align with the requirements in the license renewal application.
For the Open-Cycle Cooling Water System program, the team concluded that the applicant had performed appropriate evaluations and considered pertinent industry
experience and plant operating history to determine the effects of aging in components cooled by open-cycle cooling water. The team concluded that, if implemented as described, the applicant provided guidance to appropriately identify and address aging effects during the period of extended operation.
.5 B2.1.10 Closed-Cycle Cooling Water System (XI.M21)
The Closed-Cycle Cooling Water System program was an existing program, consistent with the GALL Report after enhancement, credited with managing loss of material, cracking, and reduction in heat transfer for components in closed-cycle cooling water
systems. The program included maintenance of system corrosion inhibitor concentrations and chemistry parameters following the guidance of Electric Power Research Institute TR-107396, "Closed Cooling Water Chemistry Guideline," Revision 1, to minimize the effects of aging. The program included periodic testing and inspections to evaluate system and component performance. Inspection methods included visual,
ultrasonic, and eddy current testing.
The applicant maintained water chemistry in the component cooling water and service cooling water systems by adding corrosion inhibitors (potassium molybdate, potassium nitrite, and tolyltriazole), pH control chemicals (potassium hydroxide), and biocides (glutaraldehyde and isothiazoline). The systems addressed by this license renewal program included diesel generator jacket water, component cooling water, service cooling water, and the auxiliary building heating, ventilation and air conditioning chill water systems. The team confirmed that the applicant only included the service cooling water and the heating, ventilation and air conditioning chill water systems because of their potential for spatial interactions with safety-related systems.
The team reviewed the implementing procedures, self-assessments, strategic chemistry plans, and chemistry data for the component cooling water and diesel jacket water systems. The team reviewed selected corrective action documents and confirmed that the applicant had satisfactorily resolved the identified problems. The team interviewed
- 19 - Enclosure the component cooling water system engineer, the diesel generator system engineer, and chemistry personnel.
The team determined that the applicant planned to enhance this program by performing inspections of the component cooling water isolation check valves to the reactor coolant
pumps (Valves CCW-1-585 and CCW-2-585) as a leading indicator of the interior piping components otherwise inaccessible for visual inspection. The applicant planned to perform the inspections every 5 years (Elements 4, 5, 6, and 7). Because the applicant had experienced some fouling and had low flow areas and because the applicant had not selected these valves based on a technical evaluation regarding whether the flow
conditions represented the typical low flows in the component cooling water system, the team questioned whether these valves would provide the needed information since they were not located in low flow areas. The applicant initiated Notification 50341717 to evaluate whether performing inspections at these locations provided representative low-flow conditions for the closed cooling water system.
The applicant took five exceptions to the GALL Report. The first exception related to the
concentration of chromates in the diesel jacket water system (Elements 2, 3, and 6). The applicant used a chromate concentration that ranged from 1580 to 3150 ppm, whereas, the guidelines in Electric Power Research Institute Report TR-107396 specified a range of 150 to 300 ppm. The chromate limit resulted from a study identified in National Association of Corrosion Engineers 7G181 that documented chromate levels
above 500 ppm had degraded some mechanical seals. The team determined that the applicant had experienced some leaks of their jacket water pump seals; however, the applicant concluded the seal leakage had not resulted from high chromate levels. The applicant initiated Notification 50341936 to evaluate the cause for the seal failures. The team verified that the applicant had experienced leakage from jacket water pump seals,
but no catastrophic seal failures. Further, the majority of the seal replacements had occurred after 15 years in service. The applicant replaced the jacket water pumps every 13 years. Although no definitive proof existed that the seal leakage resulted from high chromate levels in the jacket water, the team determined that the frequency of the preventive maintenance task provided an appropriate means to manage any aging
effects.
The second exception related to the decision to not monitor chloride and fluoride as control parameters for the diesel jacket water system (Elements 2 and 3). The applicant supported this exception to the GALL Report by noting that demineralized water was
used to makeup to the system, no pathways existed to allow chlorides and fluorides into the system, and the chromate prevented pitting by chlorides and fluorides because of the anodic inhibitor properties of the high chromate concentration. The team verified that the applicant used demineralized water to makeup to the diesel jacket water system and confirmed that chromate acts as an anodic inhibitor. The team identified no concerns with this exception.
The third exception related to the monitoring frequency for the jacket water control parameters quarterly instead of monthly, as specified in the GALL Report (Elements 2 and 3). The team determined that the chemistry parameters remained stable for long periods of time such that decreasing the sampling frequency to quarterly remained frequent enough to detect changes in chemistry in a timely fashion. The team verified
- 20 - Enclosure that the applicant had maintained stable water chemistry for the past 25 years and verified that the jacket water system remained closed with little chance of contamination. The team identified no concerns with this exception.
The fourth exception related to using chemistry controls and other evaluation techniques
for the different closed cooling water systems instead of monitoring heat exchanger parameters such as flow, inlet and outlet temperatures, and differential pressure (Elements 3, 4, and 5). Instead of testing the heat exchangers serviced by component cooling water system (e.g., component cooling water, centrifugal charging pump, safety injection pump lubricating oil coolers and the residual heat exchanger), the applicant
credited monitoring of corrosion coupons, heat transfer testing of the component cooling water heat exchanger, inspection of the interior of the component cooling water isolation valves to the reactor coolant pumps, and inspection of low flow spool pieces. For the diesel jacket water system, the applicant credited monitoring of the jacket water supply and return header temperatures, hydrostatic testing of the jacket water after coolers, and visual inspection of the jacket water radiators. The team had no concerns with this exception.
The fifth exception related to using Electric Power Research Institute 1007820, "Closed Cooling Water Chemistry Guideline," Revision 1 instead of Revision 0, as described in the GALL Report (Elements 2, 3, 4, 5, 6, and 7). The team identified no concerns related to implementing a newer version of the chemistry guideline.
From a review of plant operating experience, the team determined the applicant had appropriately resolved past contamination of their closed cooling water systems. The applicant had experienced a significant biofouling event in 2005 in the closed cooling water system. The applicant identified the root cause as poor chemistry control after
changing corrosion control from chromates to molybdates in 1991. The applicant began adding a dispersant to the closed cooling water system that enabled the molybdates to penetrate throughout the biofilm minimizing any biological growth.
From a review of plant operating experience, the team confirmed that the applicant had
taken appropriate actions to maintain chemistry controls in the auxiliary building heating, ventilation, and air conditioning chill water system. The team determined that, for the service cooling water system, the applicant took appropriate actions to mechanically clean and chemically treat the service cooling water system whenever chemistry parameters exceeded their recommended ranges.
For the Closed-Cycle Cooling Water System program, the team concluded that the applicant had performed appropriate evaluations and considered pertinent industry experience and plant operating history to determine the effects of aging in components cooled by closed-cycle cooling water. The team concluded that, if implemented as described, the applicant provided guidance to appropriately identify and address aging effects during the period of extended operation.
- 21 - Enclosure .6 B2.1.13 Fire Water System (XI.M27)
The Fire Water System program was an existing program, consistent with the GALL Report after enhancement, credited with managing loss of material resulting from general, pitting, crevice, and galvanic corrosion; microbiological corrosion; or biofouling of carbon steel, stainless steel, cast-iron, copper, bronze, brass, galvanized, and ductile iron components in fire protection systems exposed to water. The Fire Water System program managed the aging of piping, pipe components, pump casings, sprinkler heads, tanks, and hydrants as well as loss of material in fire protection system components through periodic hydrant inspections, fire main flushing, sprinkler inspections and flow
testing in accordance with National Fire Protection Association codes and standards.
The team reviewed applicable license renewal program basis documents, aging management review documents, procedures and surveillances, and surveillance results. In addition, the team searched the applicant's corrective action database for relevant operating experience. The team also interviewed plant personnel and walked down fire water system equipment, including the fire pumps, associated piping, and the reservoir. The team determined that plant specific operating experience did not reveal anything that would require changes to this aging management program.
The applicant intended to enhance the Fire Water System program to replace sprinkler heads in service for 50 years or to test representative samples from one or more fire
areas consistent with guidance in National Fire Protection Association 25, "Inspection, Testing and Maintenance of Water-Based Fire Protection Systems." The applicant will repeat the tests at 10-year intervals during the period of extended operation for sprinkler heads not replaced prior to being in service for 50 years to manage the effects of aging.
The applicant planned to enhance procedures to perform either periodic, non-intrusive volumetric examinations or visual inspections on firewater piping. Non-intrusive volumetric examinations would detect loss of material resulting from corrosion to ensure that aging effects were managed, wall thickness remained within acceptable limits, and degradation would be detected before the loss of intended function. The applicant
planned to use volumetric examination techniques generally accepted in the industry, such as ultrasonic or eddy current testing. For monitoring and trending, the licensee planned to enhance Procedure STP M-71, "Fire Water System Flow Test," Revision 8, to specify trending requirements.
The applicant took exception to the GALL Report recommendations to conduct annual fire hose hydrostatic tests and annual hose station gasket inspections. The applicant specified that they would continue to maintain their 18-month hose station gasket inspection frequency and their 3-year fire hose hydrostatic test frequency. The team concluded that the planned frequencies for the hose station gasket inspections and the fire hose hydrostatic tests were satisfactory and capable of detecting degradation that resulted from aging effects since these frequencies agreed with the periodicity typically
observed.
For the Fire Water System program, the team concluded that the applicant had performed appropriate evaluations and considered pertinent industry experience and plant operating history to determine the effects of aging on fire water system internal
- 22 - Enclosure pipe and component surfaces. With the enhancements to be incorporated prior to the period of extended operation, the team concluded that, if implemented as described, the applicant provided guidance to appropriately identify and address aging effects during the period of extended operation.
.7 B2.1.14 Fuel Oil Chemistry (XI.M30)
The Fuel Oil Chemistry program was an existing program, consistent with the GALL Report after enhancement, credited for managing the loss of material that resulted from general, pitting, crevice, and microbiological influenced corrosion on the internal surface
of components in the diesel engine generator diesel fuel oil storage and transfer system, portable diesel-driven fire pump fuel oil tanks, and portable caddy fuel oil tanks. The program included surveillance and monitoring procedures for maintaining fuel oil quality. The applicant controlled contaminants in accordance with applicable American Society of Testing Materials (ASTM) standards (ASTM D1796, D2276, and D4057). Further, the applicant conducted periodic draining of water from fuel oil tanks, visual inspection of internal surfaces, one-time ultrasonic wall thickness measurements of accessible
portions of fuel oil tank bottoms, and testing of new fuel oil before introducing it into the fuel oil tanks. In addition, the applicant planned supplemental one-time inspections of a representative sample of components in systems that contain fuel oil by the one-time inspection program.
The team reviewed the aging management program evaluation report, the NRC aging management program audit report, responses to requests for additional information, implementing procedures, self-assessments, and relevant action requests. The team reviewed trends and data for the diesel fuel oil parameters and determined the applicant maintained the chemistry parameters within limits. The team interviewed plant
personnel and conducted walk downs of the diesel engine generators, diesel engine generator day tanks, portable diesel-driven fire pump, and portable caddy pumps. From a review of plant operating experience, the team determined that no additional aging effects were identified and identified no concerns.
The applicant specified enhancements needed to ensure consistency with the GALL Report for all the fuel oil tanks that required aging effects management. Specifically, the applicant identified needed procedure changes to: (1) require periodic draining, cleaning, and visual inspection of the diesel engine generator day tanks, portable diesel-driven fire pump fuel oil tanks, and portable caddy fuel oil tanks (Elements 2 and 4);
(2) require sampling of new fuel oil prior to introduction into the portable diesel-driven fire pump and caddy fuel oil tanks (Elements 3 and 5); (3) require one-time supplemental ultrasonic thickness measurements of accessible portions of fuel oil storage tank bottoms (Element 4); (4) specify trending of water and particulate levels specified in Technical Specifications and plant procedures for the diesel fuel oil storage tanks and diesel engine generator day tanks (Element 5); (5) require monitoring and trending of water and sediment levels for new fuel oil for the portable diesel-driven fire pump and
caddy fuel oil tanks (Element 5), and (6) specify acceptance criteria for new fuel oil being introduced into the portable diesel-driven fire pump or caddy fuel oil tanks (Element 6). After review of the aging management program and discussions with applicant personnel, the team determined that these enhancements enabled the applicant to
- 23 - Enclosure ensure their aging management program procedures monitored the in-scope components for aging effects.
The applicant described six separate exceptions to the GALL Report that affected several aging management program elements. The team discussed the basis for each
exception with the program owner and verified the applicant remained capable of managing aging effects, as required by the GALL Report.
The first exception related to the scope of the Fuel Oil Chemistry program and the specific ASTM standards used. The applicant used ASTM D1796, -D2276, and -D4057,
as specified in their Technical Specifications (Element 1). The applicant specified that testing conducted using ASTM D1796 provided quantitative results that, together with the Technical Specifications acceptance criteria, met the intent of the ASTM D2709. Additionally, Technical Specification 5.5.13.c specified the use of ASTM D2276, along with acceptance criteria for total particulate concentration of less than 10 mg/liter. The team determined the applicant specified fuel oil chemistry monitoring that would manage aging effects.
The second exception related to periodic removal of water from the tanks (Elements 2 and 5). The applicant did not have a low point drain to periodically remove water from the portable diesel-driven fire pump fuel oil tanks, portable caddy fuel oil tanks, or the fuel oil pump head tanks. The team confirmed that the fuel oil pump head tanks
replenished the fuel oil in the head tanks daily and confirmed the fuel came from the diesel generator day tanks. The applicant checked for the presence of water in the diesel generator day tanks every 31 days and drained as necessary.
Although the applicant operated the portable diesel-driven fire pump and caddy pumps
quarterly, the team determined that the test duration would not empty the fuel oil tanks and would not, necessarily, prevent water collection. The team verified that the annual maintenance on the portable diesel-driven fire and caddy pumps required draining and cleaning of the fuel oil tanks. The team concluded this frequency of maintenance, draining and drying the interior of the tanks, and the future enhancement of monitoring
for the presence of water prior to adding fuel oil would provide sufficient preventive actions to manage the effects of aging.
The third exception related to the fuel oil in the portable diesel-driven fire pump and caddy fuel oil tanks not being monitored for particulate concentration (Element 3). The
team concluded this frequent maintenance that the drained and dried the interior of the tanks and the future enhancement of monitoring for the presence of particulates prior to adding fuel oil would provide sufficient monitoring to manage any aging effects. The fuel oil pump head tanks replenished the fuel oil in the head tanks daily and that the applicant checked for particulates quarterly in accordance with ASTM D2276 and the Technical Specifications.
The fourth exception related to the inability to take multi-level representative fuel oil samples from the small tanks in accordance with ASTM D4057 (Elements 3 and 4). From walk downs, the team confirmed that the system design of the portable diesel-driven fire pump fuel oil tanks, portable caddy fuel oil tanks, and the fuel oil pump
- 24 - Enclosure head tanks did not allow performing multi-level sampling. The team identified no concerns with this exception.
The fifth exception identified that testing conducted using ASTM D1796 gives quantitative results that, together with the Technical Specification acceptance criteria,
meet the intent of the ASTM D2709 method (Elements 3 and 6). Specifically, the applicant used ASTM D1796, along with acceptance criteria for water and sediment contamination of 0.05 volume percent, as specified in Technical Specifications Bases for Surveillance Requirement 3.8.3.3.c. The team determined that the applicant used a sample volume smaller than that recommended in ASTM D2276. The team determined
that the ASTM standard recommended a larger volume but allowed for smaller sample volumes so long as the volume was recorded. Further, the team confirmed that the applicant had specified this methodology and the use of a smaller sample volume in the bases of their Improved Technical Specifications submittal. The team identified no concerns with this exception.
The sixth exception related to the filter pore size used to determine the particulate levels
in the fuel oil samples. The applicant used a 0.8-micron filter in accordance with ASTM D2276 along with acceptance criteria for total particulate concentration less than 10 mg/liter, as specified in Technical Specification 5.5.13.c; whereas, the GALL Report recommended using a larger 3.0-micron filter and a minimum flow of at least one gallon in accordance with ASTM D6217. The team determined that the 0.8-micron filters would
not create any adverse conditions since this filter size was a more sensitive measurement.
The team determined the applicant had established aging management program elements that implemented the GALL Report elements in a manner that would manage
the effects of aging with the exceptions described above. The team determined the aging management program description of the exceptions did not clearly describe why their alternative methods ensured that they provide the same level of protection for aging effects described in the GALL Report. The applicant initiated Notification 50341844 to ensure they clearly describe the basis for the exceptions and how they met the intent of
the aging management program elements.
For the Fuel Oil Chemistry program, the team concluded that the applicant had performed appropriate evaluations and considered pertinent industry experience and plant operating history to determine the effects of aging on internal surfaces of the diesel
fuel oil system tanks. With the enhancements to be incorporated prior to the period of extended operation, the team concluded that, if implemented as described, the applicant provided guidance to appropriately identify and address aging effects during the period of extended operation.
.8 B2.1.23 Lubricating Oil Analysis (XI.M39)
The Lubricating Oil Analysis program was an existing program, consistent with the GALL Report after enhancement, credited for managing the quality of lubricating oil in mechanical systems within specified limits. The program provided for sampling and analysis to maintain lubricating oil contaminants, primarily water and particulates, within the acceptance criteria established in vendor or industry guidelines. In addition,
- 25 - Enclosure ferrography may be performed on oil samples for trending of particle concentrations for diagnostic purposes.
The team reviewed the aging management program evaluation report, the NRC aging management program audit report, program assessments, implementing procedures,
and relevant notifications. The team interviewed plant personnel, reviewed a sample of oil analysis results, trending results, and lubricant evaluations for systems within the scope of license renewal, verified acceptance criteria consistency with vendor manuals and industry guidance, and reviewed the plant's operating experience summary document to ensure adequate operating experience was considered. The team
determined that the applicant already evaluated the condition of lubricating oil samples using preventive maintenance tasks; however, the applicant had developed a draft procedure that they planned to implement to monitor for aging effects as part of their license renewal activities.
The Lubricating Oil Analysis program enhancements necessary to meet the GALL Report included developing a procedure to: (1) govern program testing, evaluation, and
disposition for in-scope equipment (Element 1); (2) provide guidance for oil sampling and analysis for chemical and physical properties (Element 2); (3) specify standard analyses (Element 3); and (4) incorporate the acceptance criteria for lubricating oils associated with the equipment within the scope of the program (Elements 4 and 6).
The applicant took exception to the GALL Report because the applicant measured fuel dilution (fuel contamination of the lubricating oil) by gas chromatography rather than the flash point testing of industrial oil applications as described in the GALL Report. The applicant measured fuel dilution by gas chromatography on internal combustion engine applications where the potential exists for contamination of the lubricating oil. During
interviews, applicant personnel provided information that demonstrated that measuring fuel dilution by gas chromatography accomplished the same goal as the flash point test by determining the percent by volume of fuel contaminants in the lubricating oil. The team found this exception acceptable.
For the Lubricating Oil Analysis program, the team concluded that the applicant had performed appropriate evaluations and considered pertinent industry experience and plant operating history to determine the effects of aging. With the enhancements to be incorporated prior to the period of extended operation, the team concluded that, if implemented as described, the applicant provided guidance to appropriately identify and
address aging effects during the period of extended operation.
.9 B2.1.26 Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements (XI.E3)
The Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements program was an existing program, consistent with the GALL
Report after enhancement, credited with managing localized damage and breakdown of insulation in inaccessible medium voltage cables exposed to adverse environments. The adverse environments for these cables could include exposure to significant moisture while energized. The applicant had been managing the aging effects by periodic inspection for water collection in susceptible cable manholes, pull boxes, and
- 26 - Enclosure conduits and pumping or draining water as needed. The applicant planned to periodically test in-scope cables to assess the condition of the insulation. The applicant will complete the testing of the inaccessible medium voltage cabling prior to entering the period of extended operation and once every 10 years thereafter. The components and cables included within the scope of this program included control and power cables for
the auxiliary saltwater pumps, 480 Vac Buses F, G, and H bus supply cables, component cooling water pumps, and Unit 2 startup transformer feeder cables.
The team reviewed applicable license renewal program basis documents, aging management review documents, program procedures, and records for completed
maintenance activities. In addition, the team searched the applicant's corrective action database for relevant action requests. The team interviewed plant personnel, reviewed numerous photographs of previous pull-box inspections, and reviewed records regarding water removed from pull-boxes and conduits. The team walked down several underground cable vaults.
The applicant planned to enhance this existing program to be consistent with the GALL
Report and to conduct testing that will provide an indication of the conductor insulation condition for the in-scope cables. The applicant will conduct a polarization index test, as described in Electric Power Research Institute TR-103834-P1-2, "Effects of Moisture on The Life of Power Plant Cables," or other testing considered state-of-the-art at the time of the testing to detect deterioration of insulation. The acceptance criteria for each test
will be specific for the type of test performed and the specific cable tested.
The team determined that the applicant did not have any criteria in their Maintenance Rule program structural inspections to evaluate the condition of the supports within pull-boxes that supported the safety-related cable, and that the applicant did not specify a maximum droop for the cables stretched across a cable pull-box. The applicant added these items to Notification 50313350 to ensure they were added when the applicant revised their procedures to examine the effects of aging for license renewal. The applicant provided a schedule for pull-box inspections during the upcoming Unit 1 outage. The team provided inspection recommendations to the resident inspectors who
will visually verify the condition of those pull-boxes and associated cables.
The applicant had inspected cable pull boxes with a potential for water intrusion that contain in-scope non-environmentally qualified inaccessible medium voltage cables since January 2000 on a 2-year frequency. The applicant based the frequency of the
inspections on plant experience with water accumulation in the cable pull boxes. If the applicant found water inside any of the pull boxes, the applicant removed the collected water and considered adjusting the inspection frequency.
The applicant had experienced several water accumulation issues relating to the sump pumps and had taken appropriate corrective action to resolve these issues. The applicant verified the functionality and condition of the sump pumps annually. Since
November 2003, no alarms or pump failures had occurred. The applicant had removed conduit seals or installed vents to allow air circulation to prevent water accumulation in the conduits. When the applicant found conduits with water accumulation, they drained the water and monitored the conduits to verify that no water returned. The applicant had identified no water accumulation in any conduits since April 2005 and no cables had
- 27 - Enclosure been submerged in pull boxes for at least 10 years. The team determined that the applicant had replaced the original cable with new cable between December 1994 and April 2009. The team determined that none of the original cable that may have been submerged remained in the plant.
For the Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements program, the team concluded that the applicant had performed appropriate evaluations and considered pertinent industry experience and plant operating history to determine the effects of aging for inaccessible cables. The team concluded that, if implemented as described, the applicant provided
guidance to appropriately identify and address aging effects during the period of extended operation.
.10 B2.1.27 ASME Section XI, Subsection IWE (XI.S1)
The ASME Section XI, Subsection IWE program was an existing program, consistent with the GALL Report, credited with managing aging effects related to loss of material
and loss of integrity of the steel liner of the concrete containment building by performing visual inspections of accessible portions of the containment liner. The applicant inspected accessible portions of the containment liner plate and its integral attachments, such as piping and electrical penetrations, access hatches, the fuel transfer tube, and pressure-retaining bolting. The general visual examination looked for indications of
degradation that may affect the containment structural integrity or leak tightness. The applicant recorded indications of material loss, excessive corrosion, pitting, excessive wear, loss of protective coatings, or general deformation; assessed the initial condition of surfaces; and determined the magnitude and extent of indications of degradation of these containment components.
The team reviewed applicable license renewal program basis documents, aging management review documents, and industry documents related to containment liners. In addition, the team reviewed selected relevant corrective action documents and interviewed responsible system and civil engineers. The team reviewed the applicant's
program and inspection procedures. The team found the program implemented the inspection requirements of the ASME,Section XI, Subsection IWE. In addition, the team verified that the applicant used inspection criteria that met the regulatory requirements and used qualified personnel to perform the visual examinations. From a review of corrective action documents, the team determined that the applicant had taken
appropriate corrective actions for identified deficiencies.
The applicant took six exceptions to the GALL Report. The first exception credited the Appendix J program with testing the pressure retaining seals and gaskets, electrical penetrations and access hatches, respectively. The team confirmed during review of the 10 CFR Part 50, Appendix J, program that the program did test pressure retaining seals and gaskets. The other five exceptions related to difference between the ASME
Section XI, Subsection IWE, requirements referenced in the GALL Report and newer ASME 2001 Code edition including the 2002 and 2003 Addenda that the applicant was required to meet. The applicant took the: (1) second exception because the ASME code no longer required that pressure-retaining bolting be disassembled or torque and tension tested; (2) third exception because Table IWE-2500-1 no longer contains seven
- 28 - Enclosure examination categories; (3) fourth exception because Subsection IWE, Paragraphs IWE 2420(b) and (c) specified that flaws or areas of degradation accepted by an engineering evaluation shall be reexamined during the next inspection period and accepted if essentially unchanged, whereas the GALL Report specified three consecutive inspections; (4) fifth exception since the remaining categories in Table IWE-2500-1 all require 100 percent examination and there remained no need to expand the examination for any identified deficiency; and (5) sixth exception because the acceptance standards had been moved from Table IWE-3410-1 to Section IWE-3500.
For the ASME Section XI, Subsection IWE program, the team concluded that the applicant had performed appropriate evaluations and considered pertinent industry experience and plant operating history to determine the effects of aging for the containment liner, penetrations and integral attachments. The team concluded that, if implemented during each 10-year inservice inspection interval, the applicant provided guidance to appropriately identify and address aging effects during the period of extended operation.
.11 B2.1.28 ASME Section XI, Subsection IWL (XI.S2)
The ASME Section XI, Subsection IWL program was an existing program, consistent with the GALL Report, credited with managing the aging effects of cracking, loss of
material, and increase in porosity and permeability of the concrete containment building. The containment did not use a post-tensioning system. The applicant planned to manage the effects of aging by visually inspecting accessible portions of the concrete structure (including all of the concrete dome and cylinder walls).
The team reviewed applicable license renewal program basis documents, aging management review documents, the ASME Section XI, Subsection IWL program documents, and implementing procedures. The team discussed the relevant industry experience with plant personnel. The team confirmed that inspection procedures had personnel inspect for the following: (1) evidence of leeching or chemical attacks,
(2) areas of corrosion, erosion, or abrasion, (3) evidence of scaling or disintegration, (4) deep gouges, spalls, popouts, or voids, (5) evidence of efflorescence, exudation, or incrustation, (6) blistering or peeling of coatings, and (7) exposed reinforcing steel. The procedures included acceptance criteria for documenting crack sizes and conditions requiring an evaluation.
The team identified a concern related to openings in the containment structure. As described in Final Safety Analysis Report Section 3.8.1.7, the applicant had installed strain gauges on selected rebar in the containment concrete. The applicant used these strain gauges during the initial structural integrity tests (Unit 1 - 1975; Unit 2 - 1977) to verify that the rebar responded as expected at various containment internal pressure levels. The team determined that the applicant had protected the strain gauges by
covering them with a steel conduit box. The applicant routed the strain gauge wires from this conduit box inside flexible metal conduit to another conduit box on the outside of containment. The conduit box on the outside of containment was similar in size to a household electrical outlet box. After completing the structural integrity tests, the
- 29 - Enclosure applicant abandoned the strain gauges. A note on Drawing 663075-657-01 states that a plastic plate covered the conduit box and silicone sealant was applied.
The team identified that the photographs from the most recent Subsection IWL inspection demonstrated that these outside boxes no longer maintained a watertight seal
and corrosion was present. This strain gauge configuration might allow corrosion of the containment rebar since salt air and moisture may go through the outside box and conduit to the rebar. The team determined that the applicant had used silicone sealant around the plastic plate covering the exterior box. However, the team concluded that the applicant had neither evaluated the condition of the silicone sealant nor replaced the
sealant in the last 30 years. The licensee had observed the condition of the outside surface of containment on a 10-year cycle and initiated actions to conduct the inspections on a 5-year frequency.
The applicant noted that no significant rebar corrosion existed since the Subsection IWL inspections of concrete did not indicate the presence of cracking or spalling near the strain gauges. The applicant evaluated this condition under Notification 50341635. The
applicant established actions to enhance monitoring of the strain gauges and their cover plates for degraded conditions. Civil Engineering planned to issue a modification to correct the deficiency (including sealing up of the entire strain gauge wire box).
For the ASME Section XI, Subsection IWL program, the team concluded that, with
exception of the issue identified above, the applicant had performed appropriate evaluations and considered pertinent industry experience and plant operating history to determine the effects of aging for the containment structure. The team concluded that, if implemented during each 10-year inservice inspection interval, the applicant provided guidance to appropriately identify and address aging effects during the period of
extended operation.
.12 B2.1.29 ASME Section XI, Subsection IWF (XI.S3)
The ASME Section XI, Subsection IWF program was an existing program, consistent
with the GALL Report, credited with managing loss of material, cracking, and loss of mechanical function. For ASME Class 1, 2, and 3 piping and components and their associated supports, the applicant performed inspections consistent with the ASME 2001 Code edition including the 2002 and 2003 Addenda. The program conformed to Inspection Program B of ASME Section XI. The applicant completed 100 percent of the
VT-3 visual examinations during every 10-year inspection interval.
The team reviewed applicable sections of the license renewal application, the NRC aging management program audit results, selected corrective action documents, operating experience, program procedures, and inspection procedures. The team also interviewed the program engineers. The team reviewed a sample of the listed inspections in the attachment from the Unit 1 1R15 refueling outage summary report.
During plant tours, the team observed the condition of the facility including component supports required by this program.
The inspections examined the general mechanical and structural condition of components and their supports by verifying parameters such as clearances, settings,
- 30 - Enclosure and physical displacements. The program required inspection of the following aspects of component supports: (1) deformations or structural degradations of fasteners, springs, clamps, or other support items, (2) missing, detached, or loosened support items, (3) arc strikes, weld splatter, paint scoring, roughness, or general corrosion on close tolerance machined or sliding surfaces, (4) improper hot or cold setting of spring
supports and constant loads, (5) misalignment of supports, and (6) improper clearances of guides and stops.
For the ASME Section XI, Subsection IWF program, the team concluded that the applicant had performed appropriate evaluations and considered pertinent industry
experience and plant operating history to determine the effects of aging for the ASME Class 1, 2, and 3 components and supports. The team concluded that, if implemented during each 10-year inservice inspection interval, the applicant provided guidance to appropriately identify and address aging effects during the period of extended operation.
.13 B2.1.30 10 CFR Part 50, Appendix J (XI.S4)
The 10 CFR Part 50, Appendix J program was an existing program, consistent with the GALL Report, credited with managing loss of material, loss of leak tightness, and loss of sealing. The program monitored leakage rates through the containment pressure boundary, including the electrical penetrations and access hatch openings, in order to detect degradation of the containment pressure boundary. The team determined that
the mechanical penetrations had welds instead of pressure retaining seals. This aging management program included the steel containment liner and its integral attachments, as well as welds, gaskets, seals, and bolted connections for the primary containment pressure boundary. The team determined that the applicant would continue to perform leak rate testing during the period of extended operation to monitor leakage rates.
The team reviewed applicable parts of the license renewal application, the NRC aging management program audit results, corrective action documents, program assessments, and applicant responses to requests for additional information. The team reviewed the Unit 1 integrated leak rate test results completed after replacing the steam generators
(Refuel Outage 1R14) and the local leak rate test for Penetration 68. Since the leak rate test program was performance-based, the applicant performed integrated leak rate tests on a 10-year frequency and performed Type B and Type C at their allowable frequencies. The program owner demonstrated detailed knowledge of the test requirements including the exceptions allowed by Appendix J.
The team confirmed that the 10 CFR Part 50, Appendix J program leak tested the seals and gaskets specified in their ASME Section XI, Subsection IWE program. The ASME Section XI, Subsection IWE program took an exception to the GALL Report to credit this program for testing seals and gaskets penetrating the containment liner. However, the team determined the aging management program evaluation report and the aging management program description in the license renewal application did not identify that
the 10 CFR Part 50, Appendix J program tested seals and gaskets required by the ASME Section XI, Subsection IWE program. The applicant agreed to modify the program descriptions and documented this issue in Notification 50341877.
- 31 - Enclosure For the 10 CFR Part 50, Appendix J program, the team concluded that the applicant had performed appropriate evaluations of existing plant conditions and considered pertinent industry experience and plant operating history to determine the effects of aging on the primary containment. The team concluded that, if implemented as described, the applicant provided guidance to appropriately identify and address aging effects during
the period of extended operation.
.14 B2.1.31 Masonry Wall (XI.S5)
The Masonry Wall program was an existing program, consistent with the GALL Report,
credited with managing cracking of masonry walls and structural steel restraint systems for masonry walls. The Masonry Wall program used guidance contained in the Maintenance Rule structures monitoring program. The Masonry Wall program contained visual inspection guidelines listing aging attributes (such as cracking, missing/broken blocks, or deteriorated penetrations) and established examination criteria, evaluation requirements, and acceptance criteria.
The team reviewed the applicable license renewal program basis documents, aging management program documents, plant procedures, and prior inspection results. In addition, the team searched the corrective action database for relevant action requests and evaluated the use of industry information. The team discussed the program with civil and program engineers and visually examined accessible masonry block walls to
assess the condition. The team determined that the applicant had developed effective procedures to track changes to masonry wall conditions and had performed inspections to substantiate the masonry wall analyses and classifications. The licensee did not have any enhancements or exceptions to the GALL guidance.
The applicant planned to revise the program to require following the requirements of American Concrete Institute 349.3R-96, "Evaluation of Existing Nuclear Safety-Related Concrete Structures," and American Concrete Institute 201.1R-08, "Guide for Conducting a Visual Inspection of Concrete in Service," which provided information related to conducting visual inspections of concrete in service. The team determined
that the applicant will conduct the masonry block wall inspections at the same frequency required by the Maintenance Rule program during the period of extended operation.
For the Masonry Wall program, the team concluded that the applicant had performed appropriate evaluations and considered pertinent industry experience and plant operating history to determine the effects of aging on masonry walls and supports. The team concluded that, if implemented as described, the applicant provided guidance to appropriately identify and address aging effects during the period of extended operation.
.15 B2.1.32 Structures Monitoring (XI.S6)
The Structures Monitoring program was an existing program, consistent with the GALL
Report after enhancement, credited with managing cracking, loss of material, and change in material properties of concrete structures and structural supports. The applicant included the following structures within the scope of this program: auxiliary building (including the control room), containment structure, turbine building, radwaste storage facilities, pipe-way (underground pipe tunnel) structure, fuel handling building
- 32 - Enclosure steel superstructure, commodity supports and anchorages, outdoor tanks and foundations, buried structural commodities, electrical structures and foundations, and water control structures. The Structures Monitoring program provided inspection guidelines for concrete elements, structural steel, masonry walls, structural features (e.g., caulking, sealants, roofs, etc.), structural supports, and miscellaneous components
such as doors. The Structures Monitoring program also monitored settlement of each major structure and inspected supports for equipment, piping, conduit, cable tray, metal-enclosed bus, heating ventilation and air conditioning, and instrument components.
The team reviewed the applicable license renewal program basis documents, aging management review documents, and existing procedures. The team searched the corrective action database for relevant action requests and evaluated the applicant's evaluation of operating experience. The team interviewed system and civil engineers involved with performing the inspections and conducted detailed system walk downs. The applicant used guidance contained in Procedures MA1.NE1, "Maintenance Rule Monitoring Program - Civil Implementation," Revision 3, AWP E-016, "Inspection
Guidelines for the Maintenance Rule Monitoring Program - Civil Implementation," Revision 4, and MA1.ID17, "Maintenance Rule Monitoring Program," Revision 21.
The applicant planned to enhance the program to meet the GALL Report by revising plant procedures to monitor groundwater for pH, sulfates, and chloride concentrations,
including consideration for potential seasonal variations, prior to the period of extended operation and every 5 years thereafter. Also, the applicant planned to revise plant procedures to inspect trash bar racks and associated structural components in the intake structure.
For the Structures Monitoring program, the team determined that the applicant had implemented and performed appropriate evaluations of structures. Further, the applicant had considered pertinent industry experience and plant operating history to determine the effects of aging on plant structures and structural commodities. The team concluded that, if implemented as described, the applicant would have provided adequate guidance to identify and address aging effects during the period of extended operation.
.16 B2.1.33 Regulatory Guide 1.127, "Inspection of Water-Control Structures Associated with Nuclear Power Plants"
The Regulatory Guide 1.127 program was an existing program, consistent with the GALL Report, credited with managing cracking, loss of material, loss of form, loss of bond, loss of strength, and increase in porosity and permeability resulting from extreme environmental conditions and the effects of natural phenomena. The applicant implemented this program as part of the Structures Monitoring program. Although the applicant was not committed to Regulatory Guide 1.127 as part of their current licensing basis, the applicant followed the recommendations from the regulatory guide for
inspection frequency and monitored all the in-scope components described in Regulatory Guide 1.127. For example, the applicant inspected the intake structures on a 5-year frequency consistent with Regulatory Guide 1.127, instead of the 10-year frequency specified by their maintenance rule program. The program included the following structures: intake structure, discharge structure, circulating water conduits,
- 33 - Enclosure earth slopes over the auxiliary saltwater pipes, east and west breakwaters, and the raw water reservoirs.
The team reviewed the applicable license renewal program basis documents, aging management program documents, plant procedures, and prior inspection results. In
addition, the team searched the corrective action database for relevant action requests and evaluated the use of industry information. The team discussed the program with civil and program engineers and visually examined accessible portions of the intake control structures to assess their condition. The team determined that the applicant had developed effective procedures to inspect and monitor the conditions of the water control
structures and had performed inspections to demonstrate that they maintained the water control structures consistent with guidance contained in American Concrete Institute 349.3R-96 and American Society of Civil Engineers-11-90, "Guidelines for the Structural Condition Assessment of Existing Buildings," dated January 1990.
For the Regulatory Guide 1.127 program, the team concluded that the applicant had performed appropriate evaluations and considered pertinent industry experience and
plant operating history to determine the effects of aging on water control structures. The team concluded that, if implemented as described in the applicant's aging management program, the applicant would appropriately identify and address aging effects during the period of extended operation.
.17 B2.1.36 Metal-Enclosed Bus (XI.E4)
The Metal-Enclosed Bus program was an existing program, consistent with the GALL Report after enhancement, credited with managing the aging affects associated with loosening of bolted bus bar connections and reduced insulation and insulator resistance
on bus ducts. Metal-enclosed buses were electrical buses installed on electrically insulated supports enclosed in a metal duct. The parameters monitored include connection tightness, embrittlement, cracking, melting, swelling or discoloration of insulation, loss of material of bus enclosure assemblies, hardening of boots and gaskets, and cracking of internal bus supports. The program scope included bus sections that
were specifically required for station blackout recovery and other metal-enclosed bus sections whose failure could affect the station blackout recovery.
The team reviewed applicable license renewal program basis documents, aging management review documents, existing and new procedures, plant specific operating
experience, and preventive maintenance requirements. The team interviewed the license renewal project personnel and the responsible plant and design engineers. The team walked down all the in-scope non-segregated bus and isolated-phase bus ducts.
The applicant will check accessible bolted connections of the in-scope metal-enclosed buses for evidence of overheating prior to the period of extended operation and every 10 years thereafter. The applicant planned to perform contact resistance tests or
infrared thermography on the accessible connections. As an alternative to the thermography or measuring connection resistance of accessible bolted connections covered with insulating material, the applicant could elect to visually inspect insulation for surface anomalies, such as discoloration, cracking, chipping or surface
- 34 - Enclosure contamination. If the applicant performs visual inspections, the applicant must complete the first inspection prior to the period of extended operation and every 5 years thereafter.
The applicant planned to enhance the Metal-Enclosed Bus program by creating a formal procedure rather than relying on periodic work orders to monitor the metal-enclosed
buses for aging effects. The applicant indicated the procedure would specify the activities required to inspect and test the metal-enclosed buses, including the inspection scope, frequencies, and actions to be taken when acceptance criteria were not met.
The applicant had developed several procedures, as listed in the attachment, to monitor
the condition of their metal-enclosed buses in response to their site-specific operating experience. Because the applicant implemented their infrared thermography activities as predictive maintenance monitoring, Procedure MPE-101A, "Infrared Thermography Inspections," Revision 6, specifically identified that the inspection results did not constitute quality records. The team concluded the procedure provided inappropriate guidance regarding the record retention requirements for thermography results related to in-scope component license renewal activities. The team determined these specific
thermography results will be quality records since they would be used to demonstrate that the connections remained tight and had no adverse aging effects. The applicant updated Notification 50333175 to document the need to correct this procedure deficiency. The applicant indicated that they would include this required procedure change in the Project Plan for License Renewal Implementation.
The team reviewed plant-specific operating experience, which confirmed the need to perform aging management activities on metal-enclosed buses. The applicant had experienced several independent failures of their metal-enclosed buses related to: Noryl insulation aging; cracked welds on 25 kV iso-phase bus neutral enclosures;
cracked, corroded, or loose 4 kV bus supports; and faults on the 12 kV bus. The applicant had repaired the respective buses following each failure. The applicant replaced aluminum bus with copper bus, added Belleville washers to bolted connections, performed bus cleaning, initiated periodic micro-ohm testing, and re-torqued bolts. In addition, the applicant identified aging effects on Noryl insulated buses and replaced
the insulation as part of the existing corrective action program. The team verified that the applicant had replaced all aluminum non-segregated buses associated with station blackout recovery with copper buses.
For the Metal-Enclosed Bus program, the team concluded that the applicant had
performed appropriate evaluations and considered pertinent industry experience and plant operating history to determine the effects of aging for the metal enclosed non-segregated bus ducts and metal-enclosed isolated-phase bus ducts. The team concluded that, if implemented as described, the applicant provided guidance to appropriately identify and address aging effects during the period of extended operation.
.18 B2.1.38 Transmission Conductor, Connections, Insulators and Switchyard Bus and Connections
The Transmission Conductor, Connections, Insulators and Switchyard Bus and Connections program was an existing plant-specific program, which has no comparable GALL Report aging management program. The applicant credited this program with
- 35 - Enclosure managing aging effects related to: insulator, conductor, connector and support degradation including corrosion, mechanical wear, and contamination; and conductor degradation including conductor strand breakage, excessive corrosion and swelling. The program considered the technical information provided in Electric Power Research Institute 1001997, "Parameters that Influence the Aging and Degradation of Overhead
Conductors." The applicant included both 230 kV and 500 kV switchyard structures and components required for station blackout recovery in this aging management program.
The team reviewed applicable license renewal program basis documents, aging management review documents, existing and new procedures, and preventive
maintenance requirements. The team interviewed the license renewal project personnel and the responsible engineers. The team walked down the in-scope 230 kV and 500 kV switchyards, transmission lines, conductors, structures, disconnects, breakers, switchyard buses and connections.
Prior to the period of extended operation, the applicant planned to enhance the existing program by: (1) issuing a plant procedure that defined the program scope,
responsibilities, objectives, and inspection activities required for components within the scope of license renewal; (2) requiring personnel to gather and review completed maintenance and inspection results to identify any adverse trends, and (3) requiring engineering to evaluate any detected degraded conditions and consider the extent of condition, reportability, potential root causes, probability of recurrence, and the
corrective actions required.
The applicant inspected switchyard components related to their overhead transmission systems. The inspections met the state guidelines for overhead transmission lines to ensure public safety and reliability. This program required that all 230 kV and 500 kV
transmission lines be inspected by performance of aerial, ground, and climbing inspections at specified frequencies. The inspections look for, but were not limited to, insulator, conductor, connector, and support degradation including corrosion, mechanical wear, and contamination. Conductors were also monitored for indications of degradation including strand breakage, excessive corrosion, and swelling. The applicant documented, evaluated, and trended the inspection results.
In addition to the inspections, the applicant hot washed the 500 kV high voltage insulators on a 6-week frequency to remove salt spray contamination and inspected 230 kV and 500 kV insulators annually to verify connectivity using ground or overhead
infrared thermography inspections. The applicant had replaced all insulators on the 230 kV and 500 kV transmission lines between the plant and the switchyard dead end structures (transmission line termination points) in 1999 and 2000. In addition, the applicant had replaced any individual insulator that had experienced a fault or had degraded insulation.
Based on observations by the team during the switchyard walk down, the applicant
generated Notification 50341749 to address cracking identified in concrete and grout, a bent structural member, discoloration of an insulator bell, and rust on some connectors. During review of the license renewal application, the team identified an error in the designator for the for the in-scope switchyard breakers. The applicant had listed the
- 36 - Enclosure numbers for the switchyard disconnects. The applicant issued to Notification 50341482 to have the application corrected.
For the Transmission Conductor, Connections, Insulators and Switchyard Bus and Connections program, the team concluded that the applicant had performed appropriate
evaluations and considered pertinent industry experience and plant operating history to determine the effects of aging for inaccessible cables. The team concluded that, if implemented as described, the applicant provided guidance to appropriately identify and address aging effects during the period of extended operation.
b.4 System Reviews
For selected plant systems within the scope of license renewal, the team performed a vertical slice review of the applicant's scoping, screening, and aging management reviews of selected components to confirm whether the applicant accurately determined the appropriate material and environment and correctly assigned the appropriate aging management programs.
The team selected the following systems for review:
- Diesel engine generator
- Compressed air
The team interviewed the license renewal staff members and the system engineers responsible for the auxiliary feedwater, diesel engine generator, and the compressed air systems. The team: (1) selected components and verified material specifications; (2) walked down the systems to confirm that the applicant had properly identified
scoping boundaries (including structural and spatial interactions); identified the environments affecting the systems and had properly identified aging management programs to manage the effects of aging for these systems; and (3) evaluated the physical condition of the sampled systems. The team met with license renewal staff to determine how the applicant identified the applicable aging effects and assigned the
applicable aging management program for each structure, system, or component.
For the auxiliary feedwater system, the aging effects requiring management included loss of material, loss of preload, and reduction of heat transfer. The applicant credited the following aging management programs for managing the identified aging effects:
Water Chemistry, Bolting Integrity, one-time inspection, External Surfaces Monitoring, Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components, and Lubricating Oil Analysis programs. The team identified no concerns related to the boundaries, materials, environments, or aging management programs assigned for this system.
For the diesel engine generator system, the aging effects requiring management included cracking, loss of material, loss of preload, and reduction of heat transfer. The applicant credited the following aging management programs for managing the identified aging effects: Closed Cycle Cooling Water System, Fuel Oil Chemistry, Bolting Integrity, one-time inspection, External Surfaces Monitoring, Inspection of Internal Surfaces in
- 37 - Enclosure Miscellaneous Piping and Ducting Components, and Lubricating Oil Analysis programs. With the exception of the items below, the team identified no concerns related to the boundaries, materials, environments, or aging management programs assigned for this system.
The team identified that the applicant had incorrectly classified the material of a magnetic pump, which was used to keep positive pressure on the fuel injectors, as being made of polyvinyl chloride. The pump material was Ryton (a trade name for a specific type of thermoplastic). Ryton had much higher melting and operating temperature characteristics than polyvinyl chloride and was therefore more suitable for the intended
application. The applicant initiated Notification 50341911 to evaluate the classification of this material and determine whether to revise their license renewal application. Neither polyvinyl chloride nor Ryton had any known adverse affects by exposure to the fuel oil or the atmosphere air in which the pump operated. The GALL Report identified no aging management for polyvinyl chloride, Ryton or other thermoplastics. The team looked at the extent of condition and identified no additional examples of misclassification of polyvinyl chloride materials.
For the compressed air system, the aging effects requiring management included loss of material resulting from corrosion and loss of preload on closure bolting. The applicant credited the following aging management programs for managing the identified aging effects: Water Chemistry, Bolting Integrity, One-Time Inspection, Selective Leaching of
Materials, External Surfaces Monitoring, and Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components. With the exception of the items below, the team identified no concerns related to the boundaries, materials, environments, or aging management programs assigned for this system.
During a plant walk down, the team questioned whether the diesel generator starting air compressors should have copper or stainless steel unloader tubing since the team noted both materials installed. The applicant responded that either material could be used and demonstrated that mechanics look for the presence of corrosion during shop repairs. While responding to this question, the applicant determined that they had failed to
consider the material-environment combination for the copper tubing in their license renewal application. From a review of a revised license renewal application section, the team confirmed that, although the application had an error, no aging effects required managing for the copper-to-indoor air material environment combination.
The team identified two concerns after walking down accessible portions of the compressed air system. The first concern related to the presence of high-pressure flexible hoses and connections from local compressed air bottles to the atmospheric dump valves. The applicant had not included these hoses in any aging management program. The applicant initiated Notification 50336850 on this issue. The Strategic Teaming and Resource Sharing Center of Business initiated CCAP 2010-0143 noting this issue and other issues related to the compressed air system. The applicant stated
that they intend to establish a preventive maintenance task to replace the flex hoses so that they would be considered short-lived components.
The team also found that Regulator AIR-I-I-1231A was not aluminum as specified in the aging management program but was some type of copper alloy. The applicant initiated
- 38 - Enclosure Notification 50341879 to verify the material and provide the required information as part of the annual update of the license renewal application.
For these systems, the team concluded that the physical condition of the system and the results of tests and inspections of the various existing aging management programs
demonstrated that materials, environments, and aging effects on the selected systems had been appropriately identified and addressed, except as discussed above. Further, the team concluded that the applicant appropriately addressed the aging effects for these systems with the identified aging management programs, with the exceptions described above.
b.5 Significant Replacement Activities
The team reviewed information concerning significant replacement activities that placed the units in a better material condition prior to entering the period of extended operation:
- Replacing steam generators in both units (completed)
- Replacing reactor vessel heads in both units (completed)
- Repairs to the concrete at the intake structure (in progress)
- Replacing 4 kV cables (completed)
The replacement of these major items corrected many items addressed by aging management program and resulted in eliminating any residual aging effects.
In addition, the team determined that the applicant had initiated actions to develop a long term, detailed plan for incorporating activities required for license renewal into their daily current license basis activities.
c. Overall Conclusion
Overall based on the samples reviewed by the team, the inspection results supported a conclusion that there is reasonable assurance that actions have been identified and have been taken or will be taken to manage the effects of aging in the SSCs identified in your application and that the intended functions of these SSCs will be maintained in the period of extended operation.
40A6 Meetings, Including Exit
The team presented the inspection results to Mr. L. Sharp, Engineering Services Senior Director, and other members of the applicant's staff during an exit meeting conducted on
September 16, 2010. The applicant acknowledged the NRC inspection observations. The team returned all proprietary information reviewed during this inspection.
ATTACHMENT: SUPPLEMENTAL INFORMATION
A-1 Attachment Diablo Canyon License Renewal Documents Reviewed
KEY POINTS OF CONTACT
Applicant
J. Anastasio, Auxiliary Saltwater System Engineer L. Alves, Electrical Maintenance C. Beard, Metallurgist K. Braico, Licensing Engineer R. Davis, Licensing Engineer
K. Duke, Licensing Engineer D. Efron, Mechanical System Engineer J. Fleddermon, Strategic Projects Director M. France, Supervising Engineer H. Garcia, Seismically Induced Systems Interaction Program Engineer R. Gardner, Chemistry Supervisor D. Gibbons, Licensing Engineer
L. Goyette, Principle Mechanical Engineer T. Grebel, Project Manager J. Hill, Inservice Inspection Engineer G. Holtz, Containment Leak Rate Test Program Engineer T. Juarez, System Engineer
T. Lee, Civil Design Engineer A. Maple, Auxiliary Feedwater System Engineer D. Miklish, License Renewal Consulting Engineer K. Morris, Electrical Maintenance M. Munoz, Substation System Engineer
L. Price, Diesel Fuel System Engineer T. Smith, Pismo Substation Maintenance Superintendent L. Sharp, Engineering Services Senior Director P. Soenen, License Renewal Assistant Project Manger C. Sorensen, Inservice Inspection Program Engineer
M. Tan, Licensing Engineer E. Wessel, Plant Chemist S. Westcott, Director Engineering Services D. Wong, Supervising Civil Engineer I. Zakaria, Senior Electrical Engineer
Strategic Teaming and Resource Sharing Center of Business
S. Bowen, Electrical Lead G. Chen, Civil Lead T. Harris, Manager D. Kunsemiller, Project Manager
C. Myer, Project Manager A. Saunders, Mechanical Lead
A-2 Attachment
NRC S. Gardocki, Reactor Systems Engineer, Balance of Plant Branch, Office of Nuclear Reactor Regulation
General Letters DCL-10-057, "Response to NRC Request for Additional Information for the Diablo Canyon
License Renewal Application," dated June 3, 2010
DCL-10-067, "Response to License Renewal Application (LRA) Request for Additional Information and LRA Errata," dated June 18, 2010
DCL-10-073, "Response to NRC Request for Additional Information for the Diablo Canyon License Renewal Application," dated July 7, 2010
DCL-10-076, "Response to NRC Letter dated June 29, 2010, Request for Additional Information (Set 6) for the Diablo Canyon License Renewal Application," dated July 15, 2010
DCL-10-077, "Response to NRC Letter dated June 21, 2010, Request for Additional Information
(Set 5) for the Diablo Canyon License Renewal Application," dated July 19, 2010
DCL-10-091, "Response to NRC Letter dated June 18, 2010, Request for Additional Information (High Energy Piping) for the Diablo Canyon License Renewal Application," dated July 28, 2010
DCL-10-092, "Response to NRC Letter dated July 6, 2010, Request for Additional Information (Set 7) for the Diablo Canyon License Renewal Application," dated July 28, 2010
DCL-10-096, "Response to NRC Letter dated July 14, 2010, Request for Additional Information (Set 8) for the Diablo Canyon License Renewal Application," dated August 12, 2010
DCL-10-097, "Response to NRC Letter dated July 19, 2010, Request for Additional Information (Set 9) for the Diablo Canyon License Renewal Application," dated August 2, 2010
DCL-10-098, "Response to NRC Letter dated July 15, 2010, Request for Additional Information
(Set 10) for the Diablo Canyon License Renewal Application," dated August 12, 2010
DCL-10-100, "Response to NRC Letter dated July 20, 2010, Request for Additional Information (Set 11) for the Diablo Canyon License Renewal Application," dated August 17, 2010
DCL-10-101, "Response to NRC Letter dated July 20, 2010, Request for Additional Information (Set 12) for the Diablo Canyon License Renewal Application," dated August 17, 2010
DCL-10-104, "Response to NRC Letter dated July 20, 2010, Request for Additional Information (Set 13) for the Diablo Canyon License Renewal Application," dated August 17, 2010
A-3 Attachment DCL-10-105, "Response to NRC Letter dated July 22, 2010, Request for Additional Information (Set 15) for the Diablo Canyon License Renewal Application," dated August 18, 2010
DCL-10-107, "Response to NRC Letter dated July 22, 2010, Request for Additional Information (Set 14) for the Diablo Canyon License Renewal Application," dated August 18, 2010
DCL-10-113, "Response to NRC Letter dated August 3, 2010, Request for Additional Information (Set 16) for the Diablo Canyon License Renewal Application," dated August 30, 2010
DCL-10-116, "Response to NRC Letter dated August 9, 2010, Request for Additional Information (Set 18) for the Diablo Canyon License Renewal Application," dated September 7, 2010
DCL-10-134, "Response to NRC Letter dated September 28, 2010, Summary of Telephone Conference Call Held on September 2, 2010, Between the U.S. Nuclear Regulatory Commission and Pacific Gas and Electric Company Concerning Responses to Requests for
Additional Information Related to the Diablo Canyon Nuclear Power Plant, Units 1 and 2. License Renewal Application," dated October 27, 2010
License Renewal Documents (reviewed as needed by team members)
Operating Experience Action Request Summary Reports
Operating Experience Summary Reports
Operating Experience Industry Experience Summary Reports
License Renewal Component Lists
Diablo Canyon License Renewal Application, including Appendices A, "Final Safety Analysis Report Supplement," and B, "Aging Management Programs"
Procedures (reviewed as needed by team members)
AD1, "Administrative Controls Program," Revision 15
OM4, "Assessment of Industry Operating Experience," Revision 15
OM5, "Quality Assurance Program," Revision 5A
OM7, "Corrective Action Program," Revision 4
Miscellaneous
Audit Report Regarding the Diablo Canyon Nuclear Power Plant License Renewal Application (TAC NOS. ME2896 AND ME2897), dated August 11, 2010
Desktop Guide DG-6, "License Renewal Boundary Drawings," Revision 0
A-4 Attachment
LR-ISG-2007-02, "Changes to Generic Aging Lessons Learned (GALL) Report Aging Management Program (AMP) XI.E6, 'Electrical Cable Connections Not Subject To 10 CFR 50.49 Environmental Qualification Requirements'"
Nuclear Energy Institute 95-10, "Industry Guideline for Implementing the Requirements of 10 CFR Part 54 - The License Renewal Rule," Revision 6
NUREG-1801, "Generic Aging Lessons Learned (GALL) Report - Summary," Volume 1, Revision 1
NUREG-1801, "Generic Aging Lessons Learned (GALL) Report - Tabulation of Results," Volume 2, Revision 1
NUREG-1800, "Standard Review Plan for Review of License Renewal Applications for Nuclear Power Plants," Revision 1
Regulatory Guide 1.188, "Standard Format and Content for Applications to Renew Nuclear Power Plant Operating Licenses," Revision 1
Notifications
50335150 50335151 50335153 50335156 50335297 50335373
50335377 50335379 50335450 50335451 50341711 50341755
Topical Reports
TR-2DC, "Station Blackout (SBO) - License Renewal Feasibility Study Position Paper," Revision 2
TR-3DC, "Fire Protection - License Renewal Position Paper," Revision 1
TR-6DC, "Criterion (a)(2) - License Renewal Feasibility Study Position Paper," Revision 1
TR-7DC, "Electrical/I&C Plant Spaces Approach - License Renewal Feasibility Study Position Paper," Revision 1
TR-8DC, "Aging Effects Topical Report," Revision 2
Procedure TS1.DC1, "License Renewal Electrical Aging Management," Revision 0
TR-11DC, "Electrical Component Aging Evaluations - License Renewal Topical Report," Revision 0
TR-12DC, "Design Basis Events - License Renewal Feasibility Study Position Paper," Revision 1
TR-13DC, "Specifications and Standards - License Renewal Feasibility Study Position Paper," Revision 0
A-5 Attachment
Scoping
Control Room Pressurization System
Drawing 501418, "Turbine Building Area 'A' Plan Elevation 119'-0"," Revision 7
Drawing 511155, "Plan and Sections - Air Conditioning Control Room Pressurization Fan Arrangements Area 'A' Elevation 140'-0"," Revision 16
Photographs of control room pressurization system components on turbine deck
Drawings - Fuel Oil Pump Vaults and Structures
438037, "Foundation Details for Diesel Fuel Oil Storage Tanks," Revision 5
438165, "Emergency Diesel Generator Fuel Oil System," Revision 14
438166, "Diesel Fuel Pump Vaults," Revision 15
438172, "Yard General Utilities," Revision 21
463667, "Structural Modifications Diesel Fuel Pump Vaults," Revision 8
463987, "Exterior Concrete Tank Protection," Revision 25
465173, "Condensate Polishing System Discharge Piping & Transfer Sumps Turbine Building,"
Revision 10
508845, "Diesel Fuel Oil Transfer Pump Vaults," Revision 13
4016302, "Diesel Fuel Storage Tank 0-1 Installation & Miscellaneous Plan, Details & Sections,"
Revision 1
4016304, "Diesel Fuel Storage Tank 0-2 Miscellaneous Sections," Revision 1
4016309, "Diesel Fuel Storage Tank 0-2 Installation & Miscellaneous Plan, Details & Sections,"
Revision 1
4016311, "Diesel Fuel Storage Tank 0-2 Miscellaneous Sections," Revision 1
6015743-1-1, "250,000 Gallon Underground Fuel Storage Tank Construction Details," Revision 4
A-6 Attachment Drawings - Intake Structure
438076, "Cathodic Protection Details Intake Structure," Revision 9
498107, "Electrical Cathodic Protection System Auxiliary Saltwater Circulating Water Conduits
and Intake Structure," Revision 6
500696, "Cathodic Layout Intake Structure," Revision 8
500823, "Grounding Layout Intake Structure," Revision 7
501731, "Cathodic Protection Main Intake Structure & Screen Wash Pump Area," Revision 5
503103, "Cathodic Protection Main Intake Structure & Screen Wash Pump Area," Revision 4
Miscellaneous
NRC Audit Report Regarding the Diablo Canyon Nuclear Power Plant License Renewal Application - Scoping and Screening Methodology, dated July 16, 2010
Drawing 437677, "Schematic Diagram Oily Water Separator & Turbine Building Sump Pumps," Revision 18
Notification 50341848
Project Instruction PI-1, "Scoping and Screening of Systems, Structures, and Components for STARS License Renewal Projects," Revision 4
Report of Joint Strategic Teaming and Resource Sharing-Diablo Canyon Power Plant License Renewal Walk-down, dated March 5, 2010
Request for Additional Information Related to the Review of the Diablo Canyon Nuclear Power
Plant, Units 1 and 2, License Renewal Application - Scoping and Screening Methodology, dated May 24, 2010
Request for Additional Information Related to the Review of the Diablo Canyon Nuclear Power Plant, Units 1 and 2, License Renewal Application - Scoping and Screening and Aging
Management Review, dated July 15, 2010
Request for Additional Information Related to the Review of the Diablo Canyon Nuclear Power Plant, Units 1 and 2, License Renewal Application - Scoping and Screening, dated July 20, 2010
Request for Additional Information Related to the Review of the Diablo Canyon Nuclear Power
Plant, Units 1 and 2, License Renewal Application - Scoping and Screening and Aging Management Review, dated August 9, 2010
Set of License Renewal Drawings
A-7 Attachment Notifications
50313965 50341482 50341848
Service Cooling Water System
57718, "Equipment Location Plan at Elevation 85'-0" Turbine Building," Revision 37
57719, "Equipment Location Plan at Elevation 104'-0" Turbine Building," Revision 14
57720, "Equipment Location at Elevation 119'-0" Turbine Building," Revision 17
57721, "Equipment Location at Elevation 140'-0" Turbine Building," Revision 21
515562, "Fire Barriers, Zones and Fixed Suppression/Detection Turbine Building Elevation 85'-0"," Revision 16
515563, "Fire Barriers, Zones and Fixed Suppression/Detection Turbine Building Elevation 104'-0"," Revision 12
515564, "Fire Barriers, Zones and Fixed Suppression/Detection Turbine Building Elevation 119'-0"," Revision 12
515565, "Fire Barriers, Zones and Fixed Suppression/Detection Turbine Building Elevation 140'-0"," Revision 12
New Programs
B2.1.16 One-Time Inspection (XI.M32)
Aging Management Program Evaluation Report DCPP-AMP-B2.1.16, "One-Time Inspection - B2.1.16," Revision 3
One-Time Inspection Operating Experience White Paper, Revision 0
Miscellaneous
Notification 50341874
One-Time Inspection Sample Basis Document, Revision 0
Request for Additional Information B2.1.16-1 and applicant response
Request for Additional Information B2.1.16-2 and applicant response
Procedure TS1.ID12, "One-Time Inspection Program," Revision 0
A-8 Attachment B2.1.17 Selective Leaching of Materials (XI.M33)
Action Requests
A0350059 A0438773
Aging Management Program Evaluation Report DCPP-AMP-B2.1.17, "Selective Leaching of Materials - B2.1.17," Revision 3
Selective Leaching Operating Experience White Paper, Revision 5
Miscellaneous
Notifications 50123904 and 50341752
Procedure TS1.ID11, "Selective Leaching Degradation Program," Revision 0
Request for Additional Information B2.1.17-1 and applicant response
B2.1.18 Buried Piping and Tanks Inspection (XI.M34)
Action Requests
A0350059 A0431200 A0438773 A0442225 A0460974
Drawings 57723, "Auxiliary and Containment Buildings Plan at Elevation 73'-0"," Revision 16
57724, "Auxiliary and Containment Buildings Plan at Elevation 85'-0"," Revision 28
57729, "Auxiliary and Containment Buildings Section B-B," Revision 15
57730, "Auxiliary and Fuel Handling Buildings Section C-C," Revision 13
438164, "Auxiliary Saltwater Discharge Piping," Revision 7
438166, "Diesel Fuel Pump Vaults," Revision 15
508845, "Diesel Fuel Oil Transfer Pump Vaults," Revision 13
4005077, "Saltwater System Isometric Auxiliary Saltwater Outlet Piping," Revision 2
Aging Management Program Evaluation Report DCPP-AMP-B2.1.18, "Buried Piping and Tanks Inspection - B2.1.18," Revision 3
A-9 Attachment
Buried Piping and Tanks Program Operating Experience - White Paper, Revision 3
Miscellaneous
Cathodic Protection System - White Paper, Revision 0
Electric Power Research Institute Report 1016456, "Recommendations for an Effective Program to Control the Degradation of Buried Pipe," dated December 2008
Groundwater - White Paper, Revision 0
Life Cycle Management of Buried Pipe - Structural Integrity Report-03-010, dated February 2010
Nuclear Energy Institute 09-14, "Guideline for the Management of Buried Pipe Integrity," dated January 2010
NUREG/CR-6876, "Risk-Informed Assessment of Degraded Buried Piping Systems in Nuclear Power Plants," dated June 2005
Notifications
50286561 50297724
Procedures
MP E-72.1, "Cathodic Protection Monitoring System," Revision 7
MP E-72.2, "Monthly Cathodic Protection Monitoring System," Revision 10
PEP-72.1, "Annual Survey of ASW Cathodic Protection," Revision 0
TS5.ID3, "Buried Piping and Tanks Program," Revision 1
B2.1.20 External Surfaces Monitoring Program (XI.M36)
Aging Management Program Evaluation Report DCPP-AMP-B2.1.20, "External Surfaces Monitoring Program - B2.1.20," Revisions 1 and 2
External Surfaces Monitoring Operating Experience White Paper, Revision 6
Miscellaneous
Notification 50335453
Procedure TS5.ID1, "System Engineering Handbook," Revisions 14 and 15
A-10 Attachment
B2.1.24 Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental
Qualification Requirements (XI.E1)
Action Requests
A0476872 A0477291 A0477350 A0477593
Aging Management Program Evaluation Report DCPP-AMP- B2.1.24, "Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements," Revision 4
Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Operating Experience White Paper, Revision 1
Miscellaneous
1205-2000, "IEEE Guide for Assessing, Monitoring, and Mitigating Aging Effects on Class 1E Equipment Used in Nuclear Power Generating Stations"
Electric Power Research Institute Report 109619, "Guide for the Management of Adverse Localized Equipment Environments," dated June 1999
Electric Power Research Institute Report 1013475, "Plant Support Engineering: License Renewal Electrical Handbook - Revision 1 to EPRI Report 1003057," dated February 2007
Procedure TS1.DC1, "License Renewal Electrical Aging Management," Revision 0J
Topical Report TR-11DC, "Electrical Component Aging Evaluations - License Renewal Topical Report," Revision 0
B2.1.35 Electrical Connections Not Subject to 10 CFR 50.49 Environmental Qualification
Requirements (XI.E6)
Action Requests
A0472235 A0547811 A0563486
Aging Management Program Evaluation Report DCPP-AMP-B2.1.35, "Electrical Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements," Revision 3
Electrical Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Operating Experience White Paper, Revision 1
A-11 Attachment Miscellaneous
1205-2000, "IEEE Guide for Assessing, Monitoring, and Mitigating Aging Effects on Class 1E Equipment Used in Nuclear Power Generating Stations"
Electric Power Research Institute Report 109619, "Guide for the Management of Adverse Localized Equipment Environments," dated June 1999
Electric Power Research Institute Report 1013475, "Plant Support Engineering: License Renewal Electrical Handbook - Revision 1 to EPRI Report 1003057," dated February 2007
LR-ISG-2007-02, "Changes to Generic Aging Lessons Learned (GALL) Report Aging Management Program (AMP) XI.E6, 'Electrical Cable Connections Not Subject To 10 CFR 50.49 Environmental Qualification Requirements'"
Notification 50198804
Procedure TS1.DC1, "License Renewal Electrical Aging Management," Revision 0J
SAND 96-0344, "Aging Management Guideline for Commercial Nuclear Power Plants - Electrical Cable and Terminations," dated September 1996
Topical Report TR-11DC, "Electrical Component Aging Evaluations - License Renewal Topical Report," Revision 0
Existing Programs
B2.1.2 Water Chemistry
Action Requests
A0433758 A0455772 A0480067 A0646546 A0646547 A0648386
A0676632 A0730219 A0734403
Aging Management Program Evaluation Report DCPP-AMP-B2.1.2, "Water Chemistry,"
Revision 2
Water Chemistry Operating Experience White Paper, Revision 6
Miscellaneous
2005, 2007 and 2009 Chemistry and Radiochemistry Program Audits
Electric Power Research Institute 1014986, "Pressurized Water Reactor Primary Water Chemistry Guidelines," Volumes 1 and 2, Revision 6
A-12 Attachment Electric Power Research Institute 1016555, "Pressurized Water Reactor Secondary Water Chemistry Guidelines," Revision 7
Equipment Control Guideline 7.4, "Reactor Coolant Chemistry"
Strategic Primary Water Chemistry Plan, Revision 3
Strategic Secondary Water Chemistry Plan, Revision 7
Nonconformance Reports
N0002084 N0002129
Notifications
50043561 50076930 50233661
Procedures
CAP A-1, "Primary Sampling and Analysis Schedules," Revision 22
CAP A-2, "Secondary Sampling and Analysis Schedules," Revision 21
CAP A-3, "Technical Specifications Sampling Schedule," Revision16
CAP E-1,"Primary Systems Sampling," Revision 48
CAP E-6,"Secondary Systems Sampling," Revision 12
CY1, "Chemistry/Radiochemistry," Revision 2
CY1.DC1, "Analytical Data Processing Responsibilities," Revision 5
OP F-5:I, "Chemical Control Limits and Action Guidelines for the Primary Systems," Revision 38
OP F-5:II, "Chemical Control Limits and Action Guidelines for the Secondary Systems," Revision 37
Quality Performance Assessment Reports
Second Period 2008
Third Period 2008
First Period 2009
Second Period 2009
Third Period 2009
A-13 Attachment
First Period 2010
B2.1.4 Boric Acid Corrosion (XI.M10)
Action Requests
A0537774 A0686821 A0688061 A0691373 A0708660 A0713596
A0736999 A0738934 A0741811 A0741812 A0741814 A0741815
A0741816 A0741819 A0741820 A0741823 A0741824 A0741827
A0741846 A0741876 A0742001
Aging Management Program Evaluation Report DCPP-AMP-B2.1.4, "Boric Acid Corrosion," Revision 5
Boric Acid Corrosion Operating Experience White Paper, Revision 8
Miscellaneous
Assessment 032680010, "Boric Acid Corrosion Control Program (BACCP),"
dated September 30, 2003
Assessment 070540002, "Followup Assessment of Boric Acid Corrosion Control Program," dated February 23, 2007
Electric Power Research Institute 1000975, "Boric Acid Corrosion Guidebook," Revision 1
Generic Letter 88-05, "Boric Acid Corrosion of Carbon Steel Reactor Pressure Boundary Components in PWR plants," dated March 17, 1988
Letter DCL-88-143, Response to Generic Letter 88-05, "Boric Acid Corrosion of Carbon Steel Reactor Pressure Boundary Components in PWR [Pressurized Water Reactor] Plants," dated June 2, 1988
List of current Boric Acid Leaks
Trending Results for B2.1.4, "Boric Acid Corrosion"
Notifications
50036555 50037231 50041579 50042190 50042581 50086294
50231056 50262445 50265736 50282971 50289936
Procedures
AD4.ID2, "Plant Leakage Evaluation," Revision 10
A-14 Attachment AD7.ID11, "Fluid Leak Management Program," Revision 0
ER1.ID2, "Boric Acid Corrosion Control Program," Revision 4
NDE VT 2-1, "Visual Examination During Section XI System Pressure Test," Revision 1
STP R-8A, "Reactor Coolant System Leakage Test," Revision 5
STP R-8C, "Containment Walkdown for Evidence of Boric Acid Leakage," Revision 90
Work Orders
60004783 60006516 60007079 60007435 60014700 60026988 68006850
B2.1.6 Flow-Accelerated Corrosion (XI.M17)
Action Requests
A0067324 A0070764 A0083834 A0084101 A0084268 A0148323
Aging Management Program Evaluation Report DCPP-AMP-B2.1.6, "Flow-Accelerated Corrosion," Revision 2
Flow-Accelerated Corrosion Operating Experience White Paper, Revision 2
Miscellaneous
Generic Letter 89-08, "Erosion/Corrosion-Induced Pipe Wall Thinning," dated May 2, 1989
Letter DCL-87-217, "Response to NRC Bulletin No 87-01, Thinning of Pipe Walls," dated September 8, 1987
Letter DCL-89-192, "Response to Generic Letter 89-08, Erosion/Corrosion," dated July 19, 1989
NRC IE Bulletin 87-01, "Thinning of Pipe Walls in Nuclear Power Plants," dated July 9, 1987
Procedure TS1.NE1, "Flow-Accelerated Corrosion Monitoring Program," Revision 6
Self Assessment for Unit 2 Feedwater Piping Replacement, dated June 11, 2007
A-15 Attachment B2.1.9 Open-Cycle Cooling Water (XI.M20)
Action Requests
A0300684 A0324658 A0326711 A0333700 A0344037 A0381507
A0433036 A0446307 A0455471 A0516924 A0575609 A0585556 A0592354 A0607055 A0624997 A0625614
Inspections
Intake Bay Inspection Summaries, dated September 29, 2009, and October 1, 2009
STP M-235A, "ASW Piping Inspection, CCW Heat Exchanger," Unit 1, completed April 15, 2004
STP M-235A, "ASW Piping Inspection, CCW Heat Exchanger," Unit 2, completed November 3, 2004
STP M-235B, "ASW Piping Inspection at Vacuum Breaker Vault," Unit 1, completed April 15, 2004
STP M-235B, "ASW Piping Inspection at Vacuum Breaker Vault," Unit 2, completed November 3, 2004
STP M-235C, "ASW Piping Inspection at Intake Structure," Unit 1, completed April 15, 2004
STP M-235C, "ASW Piping Inspection at Intake Structure," Unit 2, completed November 3, 2004
Letters DCL 90-027, "Response to Generic Letter 89-13, 'Service Water System Problems Affecting Safety-Related Equipment,'" dated January 26, 1990
DCL 91-286, "Supplemental Response to Generic Letter 89-13, 'Service Water System Problems Affecting Safety-Related Equipment,'" dated November 25, 1991
DCL 94-037, "Auxiliary Saltwater System Operability," dated February 15, 1994
DCL 94-174, "Reply to Notice of Violation in NRC Enforcement Action 94-056 (NRC Inspection Report Nos. 50-275/94-08 and 50-323/94-08)," dated August 4, 1994
Aging Management Program Evaluation Report DCPP-AMP- DCPP-AMP-B2.1.9, "Open Cycle Cooling Water System," Revision 3
Open-Cycle Cooling Water Operating Experience White Paper, Revision 4
A-16 Attachment Miscellaneous
Auxiliary Saltwater System Health Reports, Units 1 and 2, 3
rd Quarter 2009 through
2 nd Quarter 2010
Component Cooling Water Heat Exchanger Test Summary
Design Criteria Memorandum S-17B, "Auxiliary Saltwater System," Appendix A, "ASW Bypass Modification and Criteria for ASW Bypass Buried Piping"
Electric Power Research Institute 1008282, "Life Cycle Management Sourcebook for Nuclear Plant Service Water Systems," dated March 2005
Equipment Control Guideline 17.2, "Auxiliary Saltwater Continuous Chlorination System"
NRC Inspection Report Nos. 50-275/93-36 and 50-323/93-36
Licensee Event Report 1-93-012-01, "Auxiliary Saltwater System Outside Design Basis Due to Fouling," dated March 8, 1994
Nonconformance Report N0001784
Report 420DC-05.8, "Remote Visual Inspection of the Diablo Canyon Power Plant, Unit 1, Auxiliary Saltwater Piping Train 1-1 and 1-2 during the 12
th Refueling Outage (May 2004)," dated February 2005
Notifications
50032659 50199694 50201326 50359698
Procedures
AR PK01-01, "Unit 1(2) ASW SYS HX Delta P/HDR Press," Revision 21A(11A)
BIO D-4, "Collection and Analysis of Macrofouling Samples from the Component Cooling Water Heat Exchangers," Revision 0B
BIO D-5, "Microfouling Sample Collections in Component Cooling Water Heat Exchangers," Revision 0A
CAP E-4, "Auxiliary Saltwater Sampling," Revision 16
OP F-5:III, "Chemistry Control Limits and Action Guidelines for the Plant Support Systems," Revision 21
MA1.ID20, "Testing and Inspections for Aux Saltwater System NRC Generic Letter 89-13 Compliance," Revisions 1 and 2
PEP C-17.13, "Coatings Surveillance Program for the Saltwater Systems," Revision 1
A-17 Attachment
PEP M-234, "CCW Heat Exchanger Performance Test," Revision 11
STP M-26, "ASW System Flow Monitoring," Revision 29
STP M-235A, "ASW Piping Inspection, CCW Heat Exchanger," Revision 2
STP M-235B, "ASW Piping Inspection at Vacuum Breaker Vault," Revision 2
STP M-235C, "ASW Piping Inspection at Intake Structure," Revision 3
TS1.ID4, "Saltwater Systems Aging Management Program," Revision 3
TS5.ID1, "System Engineering Program," Revision 15
Surveillances - Pump (STP M-26, "ASW Flow Monitoring")
R0308744 R0308673 R0310041 R0310104 R0311207 64108676
64018664 64021758 64022422 64036790 64039076 64039081 64042168
Surveillances - Valve
STP M-26A, "FCV-601, ASW Unit 1 and Unit 2 Cross-tie Dividing Valve, Flow Test," completed June 19, 2009
STP M-26A, "FCV-601, ASW Unit 1 and Unit 2 Cross-tie Dividing Valve, Flow Test,"
completed December 30, 2007
B2.1.10 Closed-Cycle Cooling Water (XI.M21)
Action Requests
A0340549 A0367029 A0367417 A0375650 A0593710 A0603631
A0618445 A0632396 A0634936 A0642574 A0645890 A0646546
A0646770 A0647160 A0651244 A0664173 A0669006 A0689273 A0720656
Aging Management Program Evaluation Report DCPP-AMP- DCPP-AMP-B2.1.10, "Closed-Cycle Cooling Water System," Revisions 3 and 4
Closed-Cycle Cooling Water System Operating Experience White Paper, Revision 7
A-18 Attachment Miscellaneous
Closed Cooling Water Chemistry Basis Document, Revision 0
Closed Cooling Water Chemistry Strategic Plan, Revision 2
Closed Cooling Water Chemistry Trends
Closed Cooling Water Heat Exchanger Inspections
Component Cooling Water System Health Reports, Units 1 and 2, 3
rd Quarter 2009 through
2 nd Quarter 2010
Electric Power Research Institute NP 6815-D, "Detection and Control of Microbiologically Influenced Corrosion"
Electric Power Research Institute TR-107396, "Closed Cooling Water Chemistry Guideline,"
Revision 0
Electric Power Research Institute 1007820, "Closed Cooling Water Chemistry Guideline," Revision 1
Final Report Closed Cooling System Water Treatment Consulting, dated February 6, 2004
Letter NF-PGE-08-79, "Revision 1 - Post Elevated Lithium Operation Measured Versus Predicted Oxide Results," dated September 4, 2008
NACE [National Association of Corrosion Engineers] International Publication 7G181, "Investigation of the Effects of Corrosion-Inhibiting Treatments on Mechanical Seals in Recirculating Hot Water Systems," dated March 1997
System Training Guide - Auxiliary Saltwater
System Training Guide - Component Cooling Water
Technical Report 11-0218-00-TR-001, "Biological Fouling of Closed Cooling Water Systems," Revision 0
Water Technology Article, "Controlling Corrosion in Closed-Loop Systems," Volume 23, Issue 1, January 2000
Nonconformance Reports
N0001892 N0002196
Notifications
50033674 50034249 50036855 50051359 50057695 50313433 50341717 50341936
A-19 Attachment
Procedures
CAP A-9, "Auxiliary Systems Sampling Schedule," Revision 30
CAP O-6, "Chemical Additions to Closed Cooling Water Systems," Revision 19
CY1, "Chemistry/Radiochemistry," Revision 2
CY1.DC1, "Analytical Data Processing Responsibilities," Revision 5
CY1.ID2, "Closed Cooling Water Chemistry Program," Revision 1
MA1.DC51, "Preventative Maintenance Program," Revision 11
MA1.ID20, "Testing and Inspections for Aux Saltwater System NRC Generic Letter 89-13 Compliance," Revision 1
MP M-51.14, "Generic Check Valve Inspection," Revision 14
OP F-5:III, "Chemistry Control Limits and Action Guidelines for the Plant Support Systems," Revision 21
PEP M-234, "CCW Heat Exchanger Performance Test," Revisions 11 and 12
STP M-9A, "Diesel Emergency Generator Routine Surveillance," Revision 79
STP M-21-ENG.1, "Diesel Engine Generator Inspection (Every Refueling Outage)," Revision 11
STP M-21-ENG.6, "Diesel Engine Generator Inspection (Every Sixth Refueling Outage)," Revision 1A
STP M-21-ENG.8, "Diesel Engine Generator Inspection (Every Eighth Refueling Outage)," Revision 2
TS5.ID1, "System Engineering Program," Revision 15
Surveillance Tests
STP M-9A, "Diesel Emergency Generator Routine Surveillance," completed for Diesel Generator 2-1 February 10, 2010
STP M-9A, "Diesel Emergency Generator Routine Surveillance," completed for Diesel Generator 2-3 February 19, 2010
STP P-CCW-11, "Routine Surveillance Test of Component Cooling Water Pump 1-1," completed September 9, 2009
A-20 Attachment STP P-CCW-11, "Routine Surveillance Test of Component Cooling Water Pump 1-1," completed February 18, 2010
STP P-CCW-12, "Routine Surveillance Test of Component Cooling Water Pump 1-2," completed July 28, 2009
STP P-CCW-12, "Routine Surveillance Test of Component Cooling Water Pump 1-2," completed October 20, 2009
STP P-CCW-13, "Routine Surveillance Test of Component Cooling Water Pump 1-3,"
completed May 29, 2009
STP P-CCW-13, "Routine Surveillance Test of Component Cooling Water Pump 1-3," completed August 21, 2009
STP P-CCW-21, "Routine Surveillance Test of Component Cooling Water Pump 2-1," completed November 27, 2009
STP P-CCW-21, "Routine Surveillance Test of Component Cooling Water Pump 2-1," completed February 19, 2010
STP P-CCW-22, "Routine Surveillance Test of Component Cooling Water Pump 2-2,"
completed September 24, 2009
STP P-CCW-22, "Routine Surveillance Test of Component Cooling Water Pump 2-2," completed December 18, 2009
STP P-CCW-23, "Routine Surveillance Test of Component Cooling Water Pump 2-3," completed November 13, 2009
STP P-CCW-23, "Routine Surveillance Test of Component Cooling Water Pump 2-3," completed February 1, 2010
Work Orders - Corrosion Coupons
R0226718 R0226719 R0252440 R0255373 R0277226 R0277230 64002671 64002672
Work Orders - Diesel Engine Generator Overhaul
R0132843 R0132895 R0140317 R0140318 R0147233
B2.1.13 Fire Water System (XI.M27)
Drawings 663071-23, "Firewater and Transfer Tank 24" Roof Manhole and 12" Roof Vent," Revision 4
663071-197, "Firewater and Transfer Tank 24" Shell Manhole," Revision 3
A-21 Attachment
663071-198, "Firewater and Transfer Tank 24" Shell Manhole," Revision 4
663071-254, "Firewater and Transfer Tank Top Angle Details," Revision 2
688803-47, "Firewater Transfer Tank Pipe Vault Slab," Sheet 47, Revision 1
Aging Management Program Evaluation Report DCPP-AMP-B2.1.13, "Fire Water System,"
Revision 3
Fire Water Operating Experience White Paper, Revision 9
Miscellaneous
Action Request A0673903
Equipment Control Guideline 18.1, "Fire Suppression Systems/Fire Suppression Water Systems," Revision 6
Equipment Control Guideline 18.2, "Fire Hose Stations," Revision 77
Numerous Fire Hose Tests
Groundwater White Paper, Revision 0
Life Cycle Management of Buried Pipe - Structural Integrity Report-03-010, dated February 2003
NFPA 25-2002, "Standard for the Inspection, Testing, and Maintenance of Water-Based Fire Protection Systems"
Topical Report TR-3DC, "Fire Protection - License Renewal Position Paper," Revision 1
Procedures
OM8, "Fire Protection Program," Revision 2B
STP M-63F, "Yard Loop Fire Water System Hydrant Flush," Revision 3
STP M-67C, "Monthly Hose Reel Station Inspection," Revision 20
STP M-71, "Fire Water System Flow Test," Revision 8
STP M-79, "Indoor Fire Hose Inspection," Revision 18
STP M-80A, "Outdoor Fire Hose Operability Test," Revision 15
A-22 Attachment STP M-80B, "Indoor Fire Hose Operability Test," Revision 17
STP M-80D, "Fire Hose Hydrostatic Testing," Revision 1
Work Orders
C0215236 R0214212
B2.1.14 Fuel Oil Chemistry (XI.M30)
Action Requests
A0434425 A0669239 A0681636
ASTM Standards
D4057-95, "Standard Practice for Manual Sampling of Petroleum and Petroleum Products"
D1796-97, "Standard Test Method for Water and Sediment in Fuel Oils by the Centrifuge Method (Laboratory Procedure)"
D2276-00, "Standard Test Method for Particulate Contamination in Aviation Fuel by Line
Sampling"
D2709-96, "Standard Test Method for Water and Sediment in Middle Distillate Fuels by Centrifuge"
D6217-98, "Standard Test Method for Particulate Contamination in Middle Distillate Fuels by Laboratory Filtration"
Aging Management Program Evaluation Report DCPP-AMP-B2.1.14, "Fuel Oil Chemistry," Revision 3
Fuel Oil Chemistry Operating Experience White Paper, Revision 7
Miscellaneous
2005, 2007, and 2009 Chemistry and Radiochemistry Program Audits
Nonconformance Report DCO-88-N058
Notification 50341844
Technical Specification Bases 3.8.3.3, Revisions 0 and 6
Technical Specification 5.5.13
A-23 Attachment Trending Results for Diesel Generator Fuel Oil Chemistry
Procedures
CAP C-54, "Water and Sediment," Revision 2
CAP C-71, "Total Particulate Contaminant of Fuel Oil," Revision 7
CAP Q-2, "Guidelines for Analytical Data Review," Revision 2
OP F-5:III, "Chemistry Control Limits and Action Guidelines for the Plant Support Systems," Revision 21
STP M-9A, "Diesel Engine Generator Routine Surveillance Test," Revision 83
STP M-10A, "Diesel Fuel Oil Storage Tank Inventory," Revision 18
STP M-91A, "Diesel Fuel Oil Storage Tanks Inspection and Cleaning," Revision 7
STP M-10B, "Diesel Fuel Oil Testing Program," Revision 19
STP M-10B1, "Emergency Diesel Fuel Oil Tank Analysis," Revision 10
STP M-10B2, "Diesel Generator Day Tanks Fuel Oil Analysis," Revision 5
STP M-10B3, "New Fuel Oil Shipment Analysis," Revision 9
B2.1.23 Lubricating Oil Analysis (XI.M39)
Aging Management Program Evaluation Report DCPP-AMP-B2.1.23, "Lubricating Oil Analysis,"
Revision 2
Lubricating Oil Analysis Operating Experience White Paper, Revision 4
Miscellaneous
Article by Mark Barnes. "Gas Chromatography: The Modern Analytical Tool 'Practicing Oil Analysis Magazine'," July 2002
ASTM D3524-90, "Standard Test Method for Diesel Fuel Diluent in Used Diesel Engine Oils by Gas Chromatography"
E.M. 6665, "Westinghouse Owners Group Reactor Coolant Pump Motor Bearing Oil Analysis Project Final Report," dated June 1995
Excerpt from EPRI Technical Report, "Terry Turbine Maintenance Guide, AFW Application"
A-24 Attachment Excerpt from EPRI Nuclear Maintenance Applications Center "Lubrication Guide," Revision 4 (Formerly 1003085)
MPR-1893, "ALCO 251 Diesel Engine Chemistry Guidelines," Revision 5
Procedures
MA1.DC51, "Preventive Maintenance Program," Revision 11
MA1.DC52, "Predictive Maintenance Program," Revision 6
TS1.ID15, "Lubricating Oil Analysis Program," Revision 0
Notifications
50036292 50041215
B2.1.26 Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements (XI.E3)
Action Requests
A0346247 A0476872 A0477350 A0477593 A0568168 A0571777 A0573248 A0623104
Drawings
57563, "Cable Tray and Conduit Layout Plan below Elevation 119'-0" Area A," Revision 35
57568, "Cable Tray and Conduit Layout Plan below Elev. 107'-0" Area A," Revision 59
57597, "Embedded Conduit Layout El 85'-0" Areas FW-GW," Revision 12
57658, "Conduit Layout Outdoors Area 1," Revision 12
57660, "Conduit Layout Outdoors Area 3," Revision 21
57682, "General Arrangement of Electrical Pull Boxes and Duct Runs," Revision 22
57683, "General Arrangement of Electrical Pull Boxes and Duct Runs," Revision 16
438113, "Civil Electrical Pull Box Details BPO 40, 41 & 42 thru 45," Revision 5
438168, "Electrical Pull Box Details," Revision 4
500606, "Conduit Layout Outdoors Area 1," Revision 10
500608, "Conduit Layout Outdoors Area 3," Revision 7
A-25 Attachment 500609, "Conduit Layout Outdoors Area 4," Revision 4
500614, "Electrical Pull Boxes & Duct Runs," Revision 16
500616, "Development of Pull Boxes," Revision 6
500635, "Cable Tray and Conduit Layout Plan below Elev. 119'-0" Area A," Revision 22
500669, "Electrical Cable Tray and Conduit Layout Plan Below El. 85'-0" Area H," Revision 32
500674, "Embedded Conduit Layout Elevation 85'-0" Areas H & K," Revision 5
500691, "Conduit and Lighting Layout Intake Structure Plan at EL. (+) 17.5'," Revision 18
500692, "Conduit and Lighting Layout Intake Structure - Plan at EL + 5-0'," Revision 12
500693, "Conduit and Lighting Schedule Intake Structure - Section A-A," Revision 11
500694, "Conduit and Lighting Schedule Intake Structure - Section B-B," Revision 15
500696, "Electrical Grounding Layout Intake Structure," Revision 8
500816, "Conduit and Lighting Layout Intake Structure - Plan at EL (+) 17.5'," Revision 24
500817, "Electrical Conduit and Lighting Layout Intake Structure - Plan Elev. +5' - 0"," Revision 17
500818, "Conduit and Lighting Layout Intake Structure Section A-A," Revision 16
500819, "Conduit and Lighting Layout Intake Structure Section B-B," Revision 19
500820, "Electrical Pull Boxes & Duct Runs," Revision 10
500822, "Conduit and Lighting Layout Intake Structure - Details," Revision 13
500823, "Grounding Layout Intake Structure," Revision 7
501458, "Conduit Lights Layout-Lighting Intake Structure Plan Below EL. (-) 2.1'," Revision 37
522196, "Civil Electrical Pull Box Layout Plan," Revision 6
Aging Management Program Evaluation Report DCPP-AMP-B2.1.26, "Inaccessible Medium
Voltage Cables Not Subject to 10 CFR 50.49 EQ Requirements," Revision 3
Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 EQ Requirements Operating Experience White Paper, Revision 1
A-26 Attachment XI.E3 - Pull Boxes Subject to Water Intrusion and Collection, dated January 30, 2010
Miscellaneous
4kV Cable Replacement List Units 1 and 2
1205-2000, "IEEE Guide for Assessing, Monitoring, and Mitigating Aging Effects on Class 1E Equipment Used in Nuclear Power Generating Stations"
Electric Power Research Institute Report TR-109619, "Guideline for the Management of
Adverse Localized Equipment Environments," dated June 1999
Electric Power Research Institute Report 1013475, "Plant Support Engineering: License Renewal Electrical Handbook - Revision 1 to EPRI Report 1003057," dated February 2007
Electric Power Research Institute Report 103854-P1-2, Project 9001-03, "Effects of Moisture on the Life of Power Plant Cables" dated August 1994
Letter DCL-07-053, "90-day Response to NRC Generic Letter 2007-01, 'Inaccessible or Underground Power Cable Failures that Disable Accident Mitigation Systems or Cause Plant Transients'," dated May 2, 2007
SAND 96-0344, "Aging Management Guideline for Commercial Nuclear Power Plants - Electrical Cable and Terminations," dated September 1996
System Health Report for Medium Voltage Cables for Unit 1 and Unit 2, September 2010
System Health Report for Low Voltage Cables for Unit 1 and Unit 2, September 2010
Topical Report TR-11DC, "Electrical Component Aging Evaluations - License Renewal Topical Report," Revision 0
Notifications
50200934 50270859 50313350
Procedures
AD7.DC8, "Work Control," Revision 28
AWP E-016, "Inspection Guide - Maintenance Rule & License Renewal Structural Monitoring Programs - Civil," Revision 4
TS1.DC1, "License Renewal Electrical Aging Management," Revision 0J
Work Orders
60000437 64020314 64057910 C0131754
A-27 Attachment B2.1.27 ASME Section XI, Subsection IWE
Action Requests
A0531657 A0532256 A0607396 A0695068
Information Notices
1986-99, "Degradation of Steel Containments," dated December 8, 1986
1988-82, "Torus Shells with Corrosion and Degraded Coatings in BWR Containments," dated October 14, 1988
1989-79, "Degraded Coatings and Corrosion of Steel Containment Vessels," dated December 1, 1989
1997-10, "Liner Plate Corrosion in Concrete Containments," dated March 13, 1997
1997-13, "Deficient Conditions Associated with Protective Coatings at Nuclear Power Plants," dated March 24, 1997
1997-29, "Containment Inspection Rule," dated May 30, 1997
2004-09, "Corrosion of Steel Containment and Containment Liner," dated April 27, 2004
2010-12, "Containment Liner Corrosion," dated June 18, 2010
Aging Management Program Evaluation Report DCPP-AMP-B2.1.27, "ASME Section XI, Subsection IWE," Revision 2
ASME Section XI, Subsection IWE Operating Experience White Paper, Revision 4
Miscellaneous
Configuration of Electrical Penetrations Drawing
Maintenance Modification Drawing MMD M000079-1, "Containment Equipment Hatch Bolting"
Dye Penetrant Test Report of Equipment Hatch Bolts
Nuclear Energy Institute 94-01, "Industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50, Appendix J," Revisions 0 and 2
Notifications
50201281 50210309 50273826 50275027
A-28 Attachment Procedures
AD5.ID2, "Inservice Inspection Program," Revision 8
ISI ADD SUCCESS, "Additional and Successive Inspections," Revision 5
ISI VT GEN-1, "General Visual Examination of the Containment Liner," Revision 1
NDE VT 3-L, "Visual Examination of the Containment Liner," Revision 1
Work Orders
C0172212 C0172243
B2.1.28 ASME Section XI, Subsection IWL (XI.S2)
Drawings 103512, "Unit 1 & 2 Containment Structure Typical Rebar Strain Gage," Revision 1
500001, "Area Location Plan," Revision 11
663075-654-1, "Liner and Surface Embedded Strain Gage Installation," dated January 2, 1971
663075-657-1, "Structural Rebar Strain Gauge Installation," dated March 4, 1971
Aging Management Program Evaluation Report DCPP-AMP-B2.1.28, "ASME Section XI, Subsection IWL," Revision 2
ASME Section XI, Subsection IWL Operating Experience White Paper, Revision 4
Miscellaneous
Final Safety Analysis Report Figure 3.8-10, "Containment Structure Typical Instrument Penetration"
Inspection of Unit 1 Reactor Cavity Sump, dated March 12, 2009
Inspection Inside Unit 2 Crane Rail, dated October 26, 2009
Inspection of Unit 2 Containment Embed Plate, dated December 21, 2009
Notification 50341635
Report 420DC-01.43, "Diablo Canyon Power Plant Examination of Structural Concrete for Unit 1 and 2 Containment Structures," dated September 6, 2001
A-29 Attachment Report 420DC-10.24, "Diablo Canyon Power Plant Inservice IWL Examination of Containment Concrete for Unit 1," dated September 3, 2010
Procedures
AD5.ID2, "Inservice Inspection Program," Revision 8
ISI ADD SUCCESS, "Additional and Successive Inspections," Revision 5
NDE VT 3C-1, "VT-3C Visual Examination of the Containment Concrete Shell," Revision 1
B2.1.29 ASME Section XI, Subsection IWF
Action Requests
A0429454 A0430828 A0575046 A0609877 A0609880
Inspections
B7.70 - Class 1 bolts
SI-1669-8III WIC-55 weld
SI-119-8III WIC-45C & -45E welds
55S-2R - CCW surge tank braces
Hanger 75-1V
Hanger 75-4V
Hanger 75-5R
Hanger 5-25R
Hanger 5-23R
Hanger 5-24R
Aging Management Program Evaluation Report DCPP-AMP-B2.1.29, "ASME Section XI,
Subsection IWF," Revision 4
ASME Section XI, Subsection IWF Operating Experience White Paper, Revision 4
A-30 Attachment Miscellaneous
Letter DCL-09-046, "Inservice Inspection Report for Unit 1 Fifteenth Refueling Outage," dated June 22, 2009
Procedures
AD5.ID2, "Inservice Inspection Program," Revision 8
ISI ADD SUCCESS, "Additional and Successive Inspections," Revision 5
ISI DATA, "Dispositioning of Recorded NDE Examination Data," Revision 4
ISI SCHED, "ISI Program Interval Three Examinations," Revision 3
MA1.ID13, "ASME Section XI Repair/Replacement Program and Implementation," Revision 13
NDE VT 3-1, "Visual Examination of Component and Piping Supports," Revision 1
B2.1.30 10 CFR Part 50, Appendix J (XI.S4)
Action Requests
A0492725 A0530700 A0556053 A0574159 A0574579 A0574763
A0603732 A0624602 A0650418 A0683314 A0718996 A0720865
Aging Management Program Evaluation Report DCPP-AMP-B2.1.30, "10 CFR Part 50, Appendix J," Revision 2
10 CFR 50, Appendix J Operating Experience White Paper, Revision 4
Miscellaneous
Assessment 2008-29, "Appendix J Program Review," dated August 29, 2008
Nuclear Energy Institute 94-01, "Industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50, Appendix J," Revisions 0 and 2
Technical Specification 5.5.16, "Containment Leak Rate Testing Program"
Test STP V-668, "Penetrations 68 and 69 Containment Isolation Valve Leak Testing," completed October 2009
Unit 1 Integrated Leak Rate Test Report for the test completed in March 2009
A-31 Attachment Notifications
50241125 50341877
Procedures
AD13.DC5, "Containment Leakage Rate Testing Program," Revision 8
STP M-7, "Integrated Leakage Rate Test (ILRT) Type A," Revision 24
STP M-7E, "Containment Penetration Valve Lineup for the Integrated Leak Rate Test (ILRT)," Revision 5
B2.1.31 Masonry Wall (XI.S5)
Drawings
515213, "Unit 1 - Safety Related Masonry Walls, Turbine Building, Elevation 85'-0", 107'-0", 119'-0", 140'-0"," Revision 6
515214, "Unit 2 - Safety Related Masonry Walls, Turbine Building, Elevation 85'-0", 107'-0", 119'-0", 140'-0"," Revision 6
515215, "Unit 1 & 2 - Safety Related Masonry Walls, Turbine Building, Elevation 85'-0", 100'-0", 115'-0", 140'-0"154'-0"," Revision 7
Aging Management Program Evaluation Report DCPP-AMP-B2.1.31, "Masonry Wall Program," Revision 2
Masonry Wall Operating Experience White Paper, Revision 4
Miscellaneous
DCM T-31, "Safety Related Masonry Walls," Revision 6
Information Notice 87-67, "Lessons Learned from Regional Inspections of Licensee Actions in Response to IE Bulletin 80-11"
Letter DCL-91-026, "Masonry Wall Re-evaluation Program," dated February 12, 1991
Letter DCL-810722, "Evaluation of Adequacy of Safety-Related Masonry Walls," dated July 22, 1981
Procedures
AWP E-016, "Inspection Guidelines For the Maintenance Rule Monitoring Program - Civil Implementation," Revision 4
A-32 Attachment
MA1.ID17, "Maintenance Rule Monitoring Program," Revision 21
MA1.NE1, "Maintenance Rule Monitoring Program - Civil Implementation," Revision 3
B2.1.32 Structures Monitoring (XI.S6)
Drawings 57718, "Equipment Location Plan at Elevation 85'-0" Turbine Building," Revision 37
57719, "Equipment Location Plan at Elevation 104'-0" Turbine Building," Revision 14
57720, "Equipment Location at Elevation 119'-0" Turbine Building," Revision 17
57721, "Equipment Location at Elevation 140'-0" Turbine Building," Revision 21
57722, "Auxiliary and Containment Buildings Plan at Elevations 60'-0" and 64'-0"," Revision 15
57723, "Auxiliary and Containment Buildings Plan at Elevation 73'-0"," Revision 16
57724, "Auxiliary and Containment Buildings Plan at Elevation 85'-0"," Revision 28
57725, "Auxiliary, Containment, and Fuel Handling Buildings Plan at Elevations 91'-0" and 100'-0"," Revision 29
57726, "Auxiliary, Containment, and Fuel Handling Buildings Plan at Elevation 115'-0","
Revision 26
57727, "Auxiliary, Containment, and Fuel Handling Buildings Plan at Elevation 140'-0"," Revision 32
57729, "Auxiliary and Containment Buildings Section B-B," Revision 15
57730, "Auxiliary and Fuel Handling Buildings Section C-C," Revision 13
57731, "Containment, Turbine, and Fuel Handling Buildings Section D-D," Revision 11
438457, "Concrete Reinforcing - Plan at El. 115'-0" - Auxiliary Building Areas J, GE, and GW," Revision 9
438458, "Concrete Reinforcing - Plan at El. 115'-0" - Auxiliary Building Areas H and K," Revision 7
500001, "Area Location Plan," Revision 11
500002, "Area A - Plans at Elevations 85'-0" & 107'-0"," Revision 15
500003, "Area A - Miscellaneous Sections & Details," Revision 14
A-33 Attachment
500936, "Piping and Mechanical Areas J & L Plan at El. 115'-0"," Revision 9
500938, "Piping and Mechanical Areas J & L Sections J and 4," Revision 10
500964, "Equipment Location Plan at Elevation 85'-0" - Turbine Building," Revision 31
500965, "Equipment Location Plan at Elevation 104'-0" - Turbine Building," Revision 13
500966, "Equipment Location Plan at Elevation 119'-0" - Turbine Building," Revision 14
500967, "Equipment Location Plan at Elevation 140'-0" - Turbine Building," Revision 16
500968, "Equipment Location Plan at Elevations 60'-4", 63'-6" & and 73'-0" - Containment Building," Change 50
500969, "Equipment Location Plan Section A-A - Containment Building," Revision 10
500971, "Containment & Fuel Handling Buildings Plan at Elevations 85'-0", 91'-0", and 100'-0"," Revision 30
500977, "Containment Building Plan at Elevations 115' and 140'," Revision 20
Drawings - Tanks
438034, "Design Class I Tanks Concrete Foundations (Sheet 1 of 2)," Revision 7
438038, "Requirements for Water Storage Tanks," Revision 8
443008, "Requirements for Water Storage Tanks," Revision 4
443014, "Location Nozzle Schedule and Vault Details for Water Storage Tanks," Revision 11
463987, "Exterior Concrete Tank Protection Concrete Foundations (Sheet 1)," Revision 25
508916, "Unit 1 - Outdoor Storage Tanks Piping Modification - Plan & Sections," Revision 6
508918, "Unit 2 - Outdoor Storage Tanks Piping Modification - Plan & Sections," Revision 4
Aging Management Program Evaluation Report DCPP-AMP-B2.1.32, "Structures Monitoring Program," Revision 3
XI.S6 Structures Monitoring Program Operating Experience White Paper, Revision 0
A-34 Attachment Miscellaneous
Electric Power Research Institute 1015078, "Plant Support Engineering: Aging Effects for Structures and Structural Components [Structural Tools]," dated December 2007
Notification 50203127
Procedures
AWP E-016, "Inspection Guidelines For the Maintenance Rule Monitoring Program - Civil
Implementation," Revision 4
MA1.ID17, "Maintenance Rule Monitoring Program," Revision 21
MA1.NE1, "Maintenance Rule Monitoring Program - Civil Implementation," Revision 3
STP M-7W, "Containment Structural Integrity Inspection," Revision 4
B2.1.33 Regulatory Guide 1.127, Inspection of Water-Control Structures Associated with
Nuclear Power Plants (XI.S7)
Drawings 59459, "Concrete Outline Plan at Top Deck Area Intake Structure," Revision 41
59460, "Concrete Outline Plan at Top Deck Area Intake Structure," Revision 35
59461, "Concrete Outline Plan at Pump Deck Area Intake Structure," Revision 39
59462, "Concrete Outline Plan at Pump Deck Area 2 Intake Structure," Revision 35
59463, "Concrete Outline Plan at Invert Area 1 Intake Structure," Revision 11
59464, "Concrete Outline Plan at Invert Area 2 Intake Structure," Revision 12
Final Safety Analysis Report - Figures
3.8-75, "Intake Structure Transverse Section A"
3.8-76, "Intake Structure Transverse Section B"
3.8-77, "Intake Structure Transverse Section C"
3.8-78, "Intake Structure Wave Scale Model Plan-Invert Unit 1 NTS"
3.8-79, "Intake Structure Wave Scale Model Transverse Section D"
3.8-80, "Pipeway Structure Layout"
A-35 Attachment License Renewal
Aging Management Program Evaluation Report DCPP-AMP-B2.1.33, "Regulatory Guide 1.127, 'Inspection of Water-Control Structures Associated with Nuclear Power Plants'," Revision 3
XI.S6 Structures Monitoring Program Operating Experience White Paper, Revision 0
Procedures
AWP E-016, "Inspection Guidelines For the Maintenance Rule Monitoring Program - Civil
Implementation," Revision 4
MA1.ID17, "Maintenance Rule Monitoring Program," Revision 21
MA1.NE1, "Maintenance Rule Monitoring Program - Civil Implementation," Revision 3
PEP C-17.14, "Concrete Surveillance Program for the Saltwater Systems," Revision 2
B2.1.36 Metal-Enclosed Bus (XI.E4)
Action Request
A0431246 A0431402 A0432093 A0433203 A0452196 A0452867
A0494268 A0516816 A0531296 A0554164 A0555908 A0574023
A0574949 A0574969 A0575531 A0604165 A0607134
Drawings 57483, "General Arrangement Outdoors 230 kV and 500 kV Switchyards," Revision 5
437530, "Single Line Meter & Relay Diagram 12 kV Start-up System," Revision 36
437531, "Single Line Meter & Relay Diagram 12 kV System," Revision 16
437532, "Single Line Meter & Relay Diagram 4160 V System," Revision 27
437533, "Single Line Meter & Relay Diagram 4160 V System," Revision 36
441227, "Single Line Meter & Relay Diagram 12 kV System Bus Sections D & E," Revision 21
441228, "Single Line Meter & Relay Diagram 4160 V System Bus Sections D & E," Revision 16
441229, "Single Line Meter & Relay Diagram 4160 V System Bus Section F," Revision 16
441230, "Single Line Meter & Relay Diagram 4160 V System Bus Sections G & H," Revision 23
500804, "Arrangement Standby Start-Up Transformers," Revision 19
500805, "Arrangement Standby Start-Up Transformers," Revision 14
A-36 Attachment
502110, "Single Line Diagram 500/230/25/12/4.16kV Systems," Revision 15
663339, "Electrical Installation Details for Indoor and Outdoor Bus Duct," Sheet 15, Revision 6
663362, "Electrical Installation Details for Indoor and Outdoor Bus Duct," Sheet 7, Revision 4
System Health Reports (2010)
3 rd Quarter 4 kV Bus - Units 1 and 2
3 rd Quarter 12 kV Bus - Units 1 and 2
3 rd Quarter 230 kV Bus - Units 1 and 2
3 rd Quarter 500 kV Bus - Units 1 and 2
3 rd Quarter Main Generator - Units 1 and 2
Aging Management Program Evaluation Report DCPP-AMP-B2.1.36, "Aging Management
Program for Metal Enclosed Bus," Revision 3
Metal-Enclosed Bus Operating Experience White Paper, Revision 2
Miscellaneous
1205-2000, "IEEE Guide for Assessing, Monitoring, and Mitigating Aging Effects on Class 1E Equipment Used in Nuclear Power Generating Stations"
Electric Power Research Institute Report 109619, "Guide for the Management of Adverse
Localized Equipment Environments," dated June 1999
Electric Power Research Institute Report 1013475, "Plant Support Engineering: License Renewal Electrical Handbook - Revision 1 to EPRI Report 1003057," dated February 2007
Metal Enclosed Bus Fault History
Notification 50333175
SAND 96-0344, "Aging Management Guideline for Commercial Nuclear Power Plants - Electrical Cable and Terminations," dated September 1996
Topical Report TR-2DC "Station Blackout (SBO) License Renewal Feasibility Study position Paper," Revision 2
A-37 Attachment Procedures
MP E-61.9A, "Isolated Phase Bus and Motor Operated Disconnect Maintenance," Revision 17
MP E-63.3C, "Maintenance of 4 and 12 kV Switchgear," Revision 22
MP E-63.3D, "4 & 12 kV Switchgear Bus Connection Resistance Test," Revision 2
MP E-101A, "Infrared Thermography Inspections," Revision 6
TS1.DC1, "License Renewal Electrical Aging Management," Revision 0J
B2.1.38 Transmission Conductor, Connections, Insulators and Switchyard Bus and Connections
Action Requests
A0413241 A0413242 A0568625 A0689901 A0694826 A0660739
Drawings 57486, "Arrangement of 500 kV Switch, Bus, & Circuit Breakers Structure," Revision 11
57487, "Arrangement of 500 kV Switch, Bus, & Circuit Breaker Structures," Revision 13
57483, "General Arrangement Outdoors 230 kV and 500 kV Switchyards," Revision 5
435897, "Arrangement of 230 kV Switch, Bus, & Circuit Breaker Structures, Sections E-E, X-X, Y-Y, Paddle Switch Cabinets," Revision 3
Aging Management Program Evaluation Report DCPP-AMP-PSSwyd, "Transmission Conductor, Connections, Insulators and Switchyard Bus and Connections," Revision 1
Operating Experience White Paper 500 & 230 kV Transmission Lines and Switchyards, dated April 6, 2010
Miscellaneous
NRC Safety Evaluation of Diablo Canyon Station Blackout Analyses (TAC Nos. M68537 and M68538), dated January 29, 1992
NRC Supplemental Safety Evaluation of PG&E Response to Station Blackout Rule (10 CFR
50.63) for Diablo Canyon (TAC NOS. M68537 and M68538), dated May 29, 1992
Topical Report TR-11DC, "Electrical Component Aging Evaluations - License Renewal Topical Report," Revision 0
A-38 Attachment Work Order 64039005
Notifications
50035101 50041476 50341482 50341749
Procedures
AD7.ID6, "Nuclear Generation/Supplemental Personnel Interface," Revision 7
OP J-2:V, "Backfeeding the Unit From the 500kV System," Revisions 13 and 14
TS1.DC1, "License Renewal Electrical Aging Management," Revision 0J
Substation Maintenance and Construction Manual Instructions
"General Information," Revision 7
"Master Table of Contents Substation Inspections," Revision 7
"Substation Inspections," Revision 7
"Arrestors, Bushings, and Insulators," Revision 7
"Infrared Inspections," Revision 7
System Reviews
Auxiliary Feedwater (03B), Diesel Generator (21) and Compressed Air (25)
Drawings - Auxiliary Feedwater
049058, "Component Material Identification," Sheet 3, Revision 2
102003, "Feedwater System," Sheet 4, Revision 75
106703, "Feedwater System OVID," Sheet 3, Revision 71
DC663056, "Finned Cooling Coil," Sheet 78, Revision 1
DC663314, "Cross Section Drawing 8" Double R/L Valve," Sheet 113, Revision 7
LR-DCPP-03-106703-02, "License Renewal Boundary Drawing," Revision 2
LR-DCPP-03-106703-03, "License Renewal Boundary Drawing," Revision 2
LR-DCPP-03-106703-04, "License Renewal Boundary Drawing," Revision 1
A-39 Attachment Drawings - Compressed Air
Selected license renewal boundary drawings for this system
Drawings - Diesel Generator
LR-DCPP-21-106721-02, "Diesel Fuel Oil System," Revision 0
LR-DCPP-21-106721-03, "Starting Air and Dryer System for Diesel Engine 1-1," Revision 0
LR-DCPP-21-106721-04, "Turbo Charger Air Assist and Dryer System for Diesel Engine 1-1," Revision 0
LR-DCPP-21-106721-05, "Engine Fuel Oil System Diesel Engine 1-1," Revision 0
LR-DCPP-21-106721-06, "Jacket Water Cooling System Diesel Engine 1-1," Revision 0
LR-DCPP-21-106721-07, "Combustion Air and Exhaust System for Diesel Engine 1-1," Revision 0
LR-DCPP-21-106721-08, "Starting Air and Dryer System for Diesel Engine 1-2," Revision 0
LR-DCPP-21-106721-09, "Turbo Charger Air Assist and Dryer System for Diesel Engine 1-2," Revision 0
LR-DCPP-21-106721-10, "Engine Fuel Oil System Diesel Engine 1-2," Revision 0
LR-DCPP-21-106721-11, "Jacket Water Cooling System Diesel Engine 1-2," Revision 0
LR-DCPP-21-106721-12, "Combustion Air and Exhaust System for Diesel Engine 1-2," Revision 0
License Renewal System and Structure Scoping Report (DCPP-SCO-)
03B, "Auxiliary Feedwater," Revision 3
21, "Diesel Generator System," Revision 5
License Renewal Component Summary Screening Report (DCPP-SCR-)
03B, "Auxiliary Feedwater," Revision 6
21, "Diesel Generator System," Revision 4
25, "Compressed Air System," Revision 3
A-40 Attachment License Renewal Aging Evaluation Report (DCPP-AER-)
03B, "Auxiliary Feedwater," Revision 4
21, "Diesel Generator System," Revision 5
25, "Compressed Air System," Revision 3
Miscellaneous
Center of Business Corrective Action Program CCAP 2010-0143, "NRC Inspection Identified Corrections to Request for Additional Information Responses and License Renewal Application"
Compressor Tubing Photographs
License Renewal Application Table 3.3.2-14, "Auxiliary Systems - Summary of Aging Management Evaluation - Diesel Generator System"
Project Change Tracking Form PCTF-DC174
Procedure MP M-21.2, "Diesel Engine Generator Air Compressor (Quincy Model QR-25) Maintenance," Revision 13
Notifications
50336850 50341879 50341911