ML21022A408

License Amendment Request for Permanent Extension of Type a and Type C Leak Rate Test Frequencies

ML21022A408
Person / Time
Site:	Palo Verde
Issue date:	01/22/2021
From:	Rash B Arizona Public Service Co
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
102-08194-BJR/MDD
Download: ML21022A408 (225)

Text

10 CFR 50.90 BRUCE J. RASH Vice President Nuclear Engineering/Regulatory 102-08194-BJR/MDD Palo Verde January 22, 2021 Nuclear Generating Station P.O. Box 52034 Phoenix, AZ 85072 Mail Station 7602 U.S. Nuclear Regulatory Commission Tel 623.393.5102 ATTN: Document Control Desk Washington, DC 20555-0001

Subject:

Palo Verde Nuclear Generating Station Units 1, 2, and 3 Docket Nos. STN 50-528, 50-529, and 50-530 Renewed Operating License Number NPF-41, NPF-51, and NPF-74 License Amendment Request for Permanent Extension of Type A and Type C Leak Rate Test Frequencies Pursuant to Section 50.90, of Title 10 of the Code of Federal Regulations (10 CFR),

Arizona Public Service Company (APS) is submitting a request for an amendment to the Technical Specifications (TS) for Palo Verde Nuclear Generating Station (PVNGS) Units 1, 2, and 3, by incorporating the enclosed proposed change. Specifically, the proposed change is a request to revise TS 5.5.16, Containment Leakage Rate Testing Program, to allow the following:

•  Change the existing Type A integrated leakage rate test (ILRT) program test interval to 15 years in accordance with Nuclear Energy Institute (NEI) Topical Report (TR) NEI 94-01, Industry Guideline for Implementing Performance-Based Option of 10 CFR 50, Appendix J, Revision 3-A, and the limitations and conditions specified in NEI 94-01, Revision 2-A.

•  Adopt an extension of the containment isolation valve (CIV) leakage rate testing (Type C) frequency from the 60 months currently permitted by 10 CFR 50, Appendix J, Primary Reactor Containment Leakage Testing for Water-Cooled Power Reactors, Option B, to 75 months for Type C leakage rate testing of selected components, in accordance with NEI 94-01, Revision 3-A.

•  Adopt the use of American National Standards Institute/American Nuclear Society (ANSI/ANS) 56.8-2002, Containment System Leakage Testing Requirements.

•  Adopt a more conservative allowable test interval extension of nine months, for Type A, Type B and Type C leakage rate tests in accordance with NEI 94-01, Revision 3-A.

The proposed change to the TS contained herein, would revise PVNGS TS 5.5.16, by replacing the references to Regulatory Guide (RG) 1.163, Performance-Based Containment Leak-Test Program, with a reference to NEI 94-01, Revision 3-A, dated July 2012, and the limitations and conditions specified in NEI 94-01, Revision 2-A, dated October 2008, as the documents used by PVNGS to implement the performance-based leakage testing program in accordance with Option B of 10 CFR 50, Appendix J.

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102-08194-BJR/MDD ATTN: Document Control Desk U.S. Nuclear Regulatory Commission LAR for Permanent Extension of Type A and Type C Leak Rate Test Frequencies Page 2 This license amendment request (LAR) also proposes the following administrative changes to TS 5.5.16:

•  Delete the information regarding the performance of the next PVNGS Type A tests as these dates have already occurred and the associated Type A tests have been performed.

The enclosure provides a description and assessment of the proposed changes. contains the evaluation of risk significance of permanent ILRT extension for the proposed amendment. Attachment 2 of the enclosure provides the existing TS pages marked-up to show the proposed changes. Attachment 3 of the enclosure provides revised (clean) TS pages.

A pre-submittal meeting for permanent extension of Type A and Type C leak rate test frequencies was held between APS and the NRC staff on January 6, 2021. APS requests approval of the proposed license amendment by January 22, 2022, with the amendment being implemented within 90 days.

In accordance with the PVNGS Quality Assurance Program, the Plant Review Board has reviewed and approved the LAR. By copy of this letter, the LAR is being forwarded to the Arizona Department of Health Services - Bureau of Radiation Control in accordance with 10 CFR 50.91(b)(1).

No new commitments are being made to the NRC by this letter.

Should you need further information regarding this letter, please contact Matthew S.

Cox, Licensing Section Leader, at (623) 393-5753.

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

Executed on: January 22, 2021 (Date)

Sincerely, Digitally signed by Rash, Bruce Rash, Bruce (Z77439)

DN: cn=Rash, Bruce (Z77439)

(Z77439) Date: 2021.01.22 13:27:00

-07'00' BJR/MDD/mg

Enclosure:

Description and Assessment of Proposed License Amendment cc: S. A. Morris NRC Region IV Regional Administrator S. P. Lingam NRC NRR Project Manager for PVNGS C. A. Peabody NRC Senior Resident Inspector for PVNGS B. D. Goretzki Arizona Department of Health Services - Bureau of Radiation Control







ENCLOSURE Description and Assessment of Proposed License Amendment



Enclosure Description and Assessment of Proposed License Amendment



Description and Assessment of Proposed License Amendment

Subject:

License Amendment Request - Revise Technical Specification 5.5.16 for Permanent Extension of Type A and Type C Leak Rate Test Frequencies 1.0

SUMMARY

DESCRIPTION 2.0 DETAILED DESCRIPTION

4.0 REGULATORY ANALYSIS

4.1 APPLICABLE REGULATORY REQUIREMENTS/CRITERIA 4.2 PRECEDENT 4.3 NO SIGNIFICANT HAZARDS CONSIDERATION DETERMINATION

6.0 REFERENCES

ATTACHMENTS:

1. Evaluation of Risk Significance of Permanent ILRT Extension 2. Proposed Technical Specification Changes (Mark-Up) 3. Revised Technical Specification Pages 4. Results of Recent Containment Examinations 5. Results of Recent IWE Examinations 6. Results of Recent IWL Examinations i



Enclosure Evaluation of the Proposed Change



1.0

SUMMARY

DESCRIPTION In accordance with 10 CFR 50.90, of Title 10 of the Code of Federal Regulations (10 CFR),

Arizona Public Service Company (APS) requests an amendment to Renewed Facility Operating License Nos. NPF-41, NPF-51, and NPF-74 for Palo Verde Nuclear Generating Station (PVNGS)

Units 1, 2, and 3, respectively.

The proposed change revises Units 1, 2, and 3 Technical Specifications (TS) 5.5.16, Containment Leakage Rate Testing Program, to reflect the following:

•  Change the existing Type A integrated leakage rate test (ILRT) program test interval to 15 years in accordance with Nuclear Energy Institute (NEI) Topical Report (TR) NEI 94-01, Industry Guideline for Implementing Performance-Based Option of 10 CFR 50, Appendix J, Revision 3-A (Reference 2), and the limitations and conditions specified in NEI 94-01, Revision 2-A (Reference 8).

•  Adopt an extension of the containment isolation valve (CIV) leakage rate testing (Type C) frequency from the 60 months currently permitted by 10 CFR 50, Appendix J, Primary Reactor Containment Leakage Testing for Water-Cooled Power Reactors, Option B, to 75 months for Type C leakage rate testing of selected components, in accordance with NEI 94-01, Revision 3-A.

•  Adopt the use of American National Standards Institute/American Nuclear Society (ANSI/ANS) 56.8-2002, Containment System Leakage Testing Requirements (Reference 37).

•  Adopt a more conservative allowable test interval extension of nine months, for Type A, Type B and Type C leakage rate tests in accordance with NEI 94-01, Revision 3-A.

Specifically, the proposed change contained herein revises PVNGS TS 5.5.16, paragraph a.,

by replacing the references to Regulatory Guide (RG) 1.163, Performance-Based Containment Leak-Test Program, (Reference 1) with a reference to NEI 94-01, Revision 3-A, and the limitations and conditions specified in NEI 94-01, Revision 2-A, dated October 2008. These new documents will be used by PVNGS to implement the performance-based leakage testing program in accordance with Option B of 10 CFR 50, Appendix J, Primary Reactor Containment Leakage Testing for Water-Cooled Power Reactors.

This License Amendment Request (LAR) also proposes the following administrative change to TS 5.5.16, paragraph a.:

•  Delete the information regarding the performance of the next PVNGS Type A tests as these dates have already occurred and the associated Type A tests have been performed.

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Enclosure Evaluation of the Proposed Change



2.0 DETAILED DESCRIPTION PVNGS TS 5.5.16, Containment Leakage Rate Testing Program, paragraph a., currently states, in part:

a. A program shall be established to implement the leakage rate testing of the containment as required by 10 CFR 50.54(o) and 10 CFR 50, Appendix J, Option B, as modified by approved exemptions. This program shall be in accordance with the guidelines contained in Regulatory Guide 1.163, Performance-Based Containment Leak-Test Program, dated September 1995, as modified by the following exceptions:

1. The visual examination of containment concrete surfaces intended to fulfill the requirements of 10 CFR 50, Appendix J, Option B testing, will be performed in accordance with the requirements of and frequency specified by ASME Code Section XI, Subsection IWL, except where relief has been authorized by the NRC.

The containment concrete visual examination may be performed during either power operation, e.g., performed concurrently with other containment inspection-related activities such as tendon testing, or during a maintenance/refueling outage.

2. The visual examination of the steel liner plate inside containment intended to fulfill the requirements of 10 CFR 50, Appendix J, Option B testing, will be performed in accordance with the requirements of and frequency specified by ASME Code Section XI, Subsection IWE, except where relief has been authorized by the NRC.

3. The first Type A test performed after the Unit 1 November 1999 Type A test shall be prior to November 4, 2014.

4. The first Type A test performed after the Unit 2 November 2000 Type A test shall be prior to November 2, 2015.

5. The first Type A test performed after the Unit 3 April 2000 Type A test shall be prior to April 27, 2015.

The proposed changes to PVNGS TS 5.5.16, paragraph a. will replace the reference to RG 1.163 with a reference to NEI TR NEI 94-01, Revisions 2-A and 3-A.

Additionally, this LAR incorporates the following administrative change to TS 5.5.16.a.:

 Delete TS 5.5.16.a. exceptions 3, 4 and 5. These changes will have no impact on the PVNGS 10 CFR 50, Appendix J Testing Program requirements, as these dates have already occurred, and the associated Type A tests were performed. This Type A test information was previously approved by the Nuclear Regulatory Commission (NRC) in Amendment No. 176 for PVNGS Units 1, 2, and 3, and is no longer applicable since the specified test dates occur in the past.

The proposed change revises the PVNGS TS 5.5.16, paragraph a., to read as follows (with recommended changes using strike-out for deleted text and bold-type for added text for clarification purposes):

a. A program shall be established to implement the leakage rate testing of the containment as required by 10 CFR 50.54(o) and 10 CFR 50, Appendix J, Option B, as modified by approved exemptions. This program shall be in accordance with the 2

Enclosure Evaluation of the Proposed Change



guidelines contained in Regulatory Guide 1.163, Performance-Based Containment Leak-Test Program, dated September, 1995, Nuclear Energy Institute (NEI) Topical Report (TR) NEI 94-01, Industry Guideline for Implementing Performance-Based Option of 10 CFR 50, Appendix J, Revision 3-A, dated July 2012, and the conditions and limitations specified in NEI 94-01, Revision 2-A, dated October 2008, as modified by the following exceptions:

1. The visual examination of containment concrete surfaces intended to fulfill the requirements of 10 CFR 50, Appendix J, Option B testing, will be performed in accordance with the requirements of and frequency specified by ASME Code Section XI, Subsection IWL, except where relief has been authorized by the NRC.

The containment concrete visual examination may be performed during either power operation, e.g., performed concurrently with other containment inspection-related activities such as tendon testing, or during a maintenance/refueling outage.

2. The visual examination of the steel liner plate inside containment intended to fulfill the requirements of 10 CFR 50, Appendix J, Option B testing, will be performed in accordance with the requirements of and frequency specified by ASME Code Section XI, Subsection IWE, except where relief has been authorized by the NRC.

3. The first Type A test performed after the Unit 1 November 1999 Type A test shall be prior to November 4, 2014.

4. The first Type A test performed after the Unit 2 November 2000 Type A test shall be prior to November 2, 2015.

5. The first Type A test performed after the Unit 3 April 2000 Type A test shall be prior to April 27, 2015.

Therefore, the retyped ("clean") version of TS 5.5.16, paragraph a., will appear as follows:

a. A program shall be established to implement the leakage rate testing of the containment as required by 10 CFR 50.54(o) and 10 CFR 50, Appendix J, Option B, as modified by approved exemptions. This program shall be in accordance with the guidelines contained in Nuclear Energy Institute (NEI) Topical Report (TR) NEI 94-01, Industry Guideline for Implementing Performance-Based Option of 10 CFR 50, Appendix J, Revision 3-A, dated July 2012, and the conditions and limitations specified in NEI 94-01, Revision 2-A, dated October 2008, as modified by the following exceptions:

1. The visual examination of containment concrete surfaces intended to fulfill the requirements of 10 CFR 50, Appendix J, Option B testing, will be performed in accordance with the requirements of and frequency specified by ASME Code Section XI, Subsection IWL, except where relief has been authorized by the NRC.

The containment concrete visual examination may be performed during either power operation, e.g., performed concurrently with other containment inspection-related activities such as tendon testing, or during a maintenance/refueling outage.

2. The visual examination of the steel liner plate inside containment intended to fulfill the requirements of 10 CFR 50, Appendix J, Option B testing, will be performed in accordance with the requirements of and frequency specified by ASME Code Section XI, Subsection IWE, except where relief has been authorized by the NRC.

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Enclosure Evaluation of the Proposed Change



The marked-up TS pages 5.5-15 and 5.5-16 for PVNGS TS 5.5.16.a., showing these proposed changes, are provided in Attachment 2.

The clean retyped pages 5.5-15 and 5.5-16 for PVNGS TS 5.5.16.a. are provided in . contains the plant specific risk assessment conducted to support this proposed change. This risk assessment follows the guidelines of NRC RG 1.174, Revision 3 (Reference

3) and RG 1.200, Revision 2 (Reference 4). The risk assessment concludes that increasing the ILRT test frequency on a permanent basis to a one-in-fifteen-year frequency is considered to represent a small change in the PVNGS risk profile.

3.0 TECHNICAL EVALUATION

3.1 Primary Containment System 3.1.1 Description of Primary Containment System The PVNGS Units 1, 2, and 3 containments consist of three basic parts:

Flat base slab with a central cavity and an instrumentation tunnel

Right circular cylinder

Hemispherical dome Principal nominal dimensions of the containment are as follows:

Interior diameter 146 feet

Interior height (above filler slab) 206 feet 6 inches

Cylindrical wall thickness 4 feet 0 inch

Dome thickness 3 feet 6 inches at dome apex 4 feet 0 inch at wall springline

Basemat thickness 10 feet 6 inches

Liner plate thickness 1/4 inch

Internal free volume 2,600,000 cubic feet net The containment is constructed of reinforced concrete prestressed by post-tensioned tendons in the cylinder and the dome. The basemat is designed and constructed of conventionally reinforced concrete. Special reinforcing details are provided at discontinuities and at openings in the shell.

A welded steel liner attached to the inside face of the concrete limits the release of radioactivity from the containment. The base liner is installed on the top of the basemat and is covered by a 2-foot 9-inch-thick concrete slab. The containment building provides biological shielding during normal operation and following a loss-of-coolant accident (LOCA).

It also functions as a leak-tight barrier following an accident inside the containment.

Post-Tensioning System High strength wires are used with buttonhead anchorage techniques. There are 186 1/4-inch diameter wires per tendon. Each tendon assembly consists of wires together with end anchor heads and ring nuts. The tendons transfer load to the structure through shims and a bearing plate.

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Enclosure Evaluation of the Proposed Change



Tendons are installed in sheaths that form ducts through the concrete between anchorage points. Trumpets, which are enlarged ducts attached to the bearing plate, allow the wires to spread out at the anchorage to suit buttonhead spacing requirements. Further, trumpets facilitate field buttonheading of wires.

Tendon sheathing provides an enclosed space surrounding each tendon. A valved vent at the highest points of curvature permits release of entrapped air during greasing operations.

Drains are provided at the lowest points of curvature to remove accumulated water prior to installing tendons. After the greasing operation, the vents and drains are closed and sealed.

The prestressing tendons are protected against atmospheric corrosion during shipment and installation, and during the life of the containment. The sheathing filler material used for permanent corrosion protection is a modified, refined petroleum-base product. The material is pumped into the sheathing after stressing.

Prestressing of the cylindrical wall is achieved by a post-tensioning system consisting of both vertical inverted U-shaped and circumferential (hoop) tendons. Vertical tendons are anchored at the base slab and extend up and over the dome to form an inverted U-shape.

Three buttresses are equally spaced at 120° around the cylinder and extend over the dome, joining together at the crown. The hoop tendons are anchored at buttresses located at 240° apart. The successive hoop tendons are anchored at alternate buttresses so that two complete horizontal loops are achieved by three consecutive horizontal tendons.

Prestressing of the hemispherical dome is achieved by a two-way pattern of tendons, which are an extension of the continuous vertical tendons and are anchored at the base slab. They are arranged to produce two families of tendons mutually intersecting each other at 90° on the horizontal projected plane. Hoop tendons extend into the hemispherical region to provide a two-way pattern up to the 90° solid angle of the dome.

Liner Plate System Liner Plate and Anchors A welded steel liner plate covers the entire inside surface of the containment (excluding penetrations) to satisfy the leak tight criteria. The liner is typically 1/4-inch-thick and is thickened locally around penetration sleeves, large brackets, and attachments to the basemat and shell wall. The stability of the liner plate, including the thickened plate, is controlled by anchoring it to the concrete structure. The shell wall and dome liner plate system is also used as a form for construction.

Equipment and Personnel Penetration Assemblies A circular equipment hatch and two personnel airlock assemblies penetrate the concrete cylinder walls. Penetration assemblies consist of steel sleeves or nozzles, reinforcing plates, and anchors. They are anchored to the concrete walls and are welded to the steel liner.

Hatch and air lock doors are provided with double-gasketed flanges with provisions for leak testing the flange-gasket combinations.

One of the two personnel air locks is for emergency access. Each personnel air lock has a door at each end and is an American Society of Mechanical Engineers (ASME) Code-stamped pressure vessel. A quick-acting equalizing valve connects the personnel air lock with the interior or exterior of the containment to equalize pressure in the two systems.

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Enclosure Evaluation of the Proposed Change



During plant operation, the two doors of each personnel air lock are interlocked to prevent both being opened simultaneously. Provision is made to bypass the interlock system during plant cold shutdown.

Process Pipe Penetration Assemblies Single barrier piping penetrations are provided for all piping passing through the containment walls. The closure for process piping to the liner plate is accomplished with a special flued head welded into the piping system and to the penetration sleeve, which is, in turn, welded to a reinforced section of the liner plate. In the case of piping carrying hot fluid, the pipe is insulated to prevent excessive concrete temperatures and to prevent excessive heat loss from the fluid. Closures to these penetration assemblies are provided by the piping systems that are served by the penetrations.

Electrical Penetration Assemblies Electrical penetration assemblies provide means for carrying one or more electric circuits through a single aperture (nozzle) in the containment pressure barrier while maintaining the integrity of the pressure barrier.

Medium voltage power penetrations are configured in the form of a tubular canister slightly shorter than the containment structure nozzle into which it will be installed. The penetration assemblies are installed in 24-inch diameter nozzles. The canister is used as a pressure chamber to monitor penetration leakage rate by pressurizing the interior space with nitrogen and measuring the leak rate with a pressure gauge. The medium voltage power penetration is flange-mounted to the outside containment wall with nuts, bolts, washers, and lock-washers. The aperture seal is formed between the header plate and the flange with two concentric Viton O-rings.

The low voltage power, control, and instrumentation penetrations are also flange-mounted to the outside containment wall in the manner described for the medium voltage power penetrations. Each penetration in this category has a stainless steel header plate at the outside containment end. Stainless steel feed-through subassemblies, containing electrical conductors, pass through the header plate and are secured and sealed with special stainless steel compression fittings. The interstices between the seals and feed-through subassemblies provide a pressure chamber, which is used to monitor the leakage rate. These penetrations are installed in 12- or 18-inch diameter nozzles.

Fuel Transfer Tube A fuel transfer tube penetration is provided for refueling. An inner pipe acts as the refueling tube with an outer pipe as the housing. The tube is fitted with a double-gasketed blind flange in the refueling canal and a standard gate valve in the spent fuel pool. This arrangement prevents leakage through the refueling tube. Outer sleeves permit the transfer tube to penetrate the refueling canal wall, the containment shell, and the exterior wall of the fuel handling building, while maintaining a pressure-tight boundary at each wall. The sleeves are anchored into each wall, respectively, and welded to each wall's liner plate. The housing is supported by the sleeves in the vertical and horizontal directions. Bellows at both the interior and exterior faces of the containment shell and of the fuel handling building permit thermal expansion of the transfer tube and of the housing. The same expansion bellows permit differential movement between structures.

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Enclosure Evaluation of the Proposed Change



Attachments and Brackets Attachments to the shell wall are brackets for support of the polar crane, electrical conduit and cable tray, spray piping, lighting and ventilation. The polar crane support brackets consist of built-up steel plate, the top flange penetrating the thickened liner plate, and are anchored in the concrete of the shell wall.

Attachments to the basemat include anchor bolts for columns that support floors and reinforcing steel for internal structures support. Attachment of the reinforcing steel is accomplished by B-series cadweld connectors welded to the top and bottom of the thickened liner plate.

Shell Discontinuities Significant discontinuities in the shell structure are at the wall-to-basemat connection, the buttresses, and the large penetration openings.

Wall-to-Basemat Connection The shell wall interface at the basemat is designed to accommodate axial forces, moments, and shears.

Buttresses Buttresses project out from the shell wall and dome surface to provide adequate space for hoop tendon anchorage and tendon stressing equipment. The anchorage surfaces of the buttress are normal to the tangent line of hoop tendons anchored.

Large Penetration Openings The concrete shell around the equipment hatch opening and around the penetrations for the main steam and feedwater pipes is thickened.

3.1.2 Containment Isolation System Containment isolation is mandatory in the event of certain design basis accidents. A containment isolation actuation signal (CIAS) automatically initiates closure of containment isolation valves.

Containment Isolation System design is based on the following criteria:

a) Two isolation valves are provided at each containment penetration: one inside the containment and one outside the containment.

b) Systems which are not required to operate, or which only operate intermittently during normal plant power operation, are isolated at the containment penetration in accordance with General Design Criteria 55 and 56.

c) All containment penetration lines, and their associated isolation valves are constructed to Safety Class 2, Seismic Category I standards.

d) The design temperature and pressure of the containment penetration lines, and their associated isolation valves meet or exceed containment design conditions.

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Enclosure Evaluation of the Proposed Change



e) Containment isolation is required to minimize the release of fission products [which is postulated to occur within the Reactor Coolant System (RCS) and the containment] to the environment following a LOCA. A CIAS is generated upon an indication that a LOCA has occurred to allow for automatic isolation of lines, which are normally open during normal plant operation, and do not function in mitigating the effects of the accident. In particular, this includes lines which are part of the RCS pressure boundary, and through which flow normally leaves the containment.

f) The Safety Injection System (SIS) and the Shutdown Cooling System (SCS) are considered to be extensions of the containment pressure boundary following an accident. The portions of the SIS and SCS, which are opened to the RCS or containment following an accident, are constructed to Safety Class 2, Seismic Category I requirements. In addition, the design temperature and pressure of the subject portions of the SIS and SCS exceed containment design conditions.

Outside the containment isolation boundary, isolation valves are provided between the portions of these systems handling RCS or containment sump fluid, and the environment. Double isolation is provided where active valves are used. Single isolation is allowable where passive valves (e.g., manual vent valves, manual drain valves, etc.) are used, since they are not subject to single failure criteria.

The following is a summary of Containment Isolation System (CIS) design features.

Incorporation of these features into the CIS results in a design where the design requirements for containment isolation barriers given above are met:

a) Containment isolation valves and interconnecting piping are designed and constructed to Safety Class 2 and Seismic Category I standards as defined in ANSI N18.2-1973 (Reference 27) and RG 1.29 (Reference 28), respectively.

b) Containment isolation valves and interconnecting piping are designed to withstand the effects of earthquakes.

c) Containment isolation valves and interconnecting piping are protected against missiles.

d) Containment isolation valves and interconnecting piping are protected against the effects of pipe whip and jet impingements.

e) The maximum allowable particle size entrained in water taken from the containment sump is limited. This ensures that the proper operation of engineered safety feature (ESF) systems and CIS valves will not be inhibited by debris introduced into the containment following a LOCA.

f) Containment isolation valves are designed to operate under normal environmental conditions and to fulfill their safety related function under post-accident environmental conditions.

g) Containment isolation valves and associated penetration piping are qualified to Section III of the ASME Code, as Class 2 components.

h) Maximum allowable actuation times are imposed on containment isolation valves consistent with their required safety function.

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Enclosure Evaluation of the Proposed Change



i) Valve operators and power sources are selected for containment isolation valves consistent with their required safety function.

j) Valve controls for containment isolation valves are designed to allow valve actuation in accordance with the actuation modes given in Updated Final Safety Analysis Report (UFSAR) Table 6.2.4-2, Containment Isolation System.

k) Means of detecting leakage from the systems associated with containment isolation valves are provided for the Shutdown Cooling System (SCS), Safety Injection System (SIS), and the Chemical and Volume Control System (CVCS).

Provisions for the detection of leakage in these systems allows the operator to determine when to isolate the affected system or train.

l) Provisions are made to allow the testing of containment isolation valves.

The containment pressure instrumentation is located outside the containment. The containment pressure instrumentation lines are extensions of the containment boundary.

These lines are critical to the functioning of the ESF systems. The design criteria for these lines are as follows:

a) Containment pressure instruments are located as close as practical to the containment and are installed using 3/8-inch stainless steel tubing.

b) All instrumentation provided is designed as a pressure-containing system.

c) One remote manually operated shutoff valve, meeting the requirements of RG 1.11 (Reference 26), is provided outside the containment.

The instrument line, up to the instrument process connection, is Seismic Category I and ASME Section III, Class 2, and the instrument is Seismic Category I. The equipment is located in an area protected against physical damage due to pipe whip or missiles.

3.2 Containment Overpressure on Emergency Core Cooling System (ECCS)

Performance For net positive suction head (NPSH) calculations, the minimum required refueling water tank (RWT) volume, less a specified volume of water diverted to the chemical volume and control system and water postulated to be held on wetted surfaces and delayed in containment, results in a minimum containment volume outside the reactor cavity corresponding to an approximate containment water level of 84.5 feet (4.5 feet above the containment floor).

The safety injection and containment spray pumps are located in the auxiliary building and are placed low enough below containment emergency sump elevation to assure the availability of the required NPSH.

Since the expected maximum pumped fluid temperature will exceed 212oF, NPSH for the safeguards pumps was calculated by assuming that the temperature of the pumped liquid is at saturation for the containment pressure, and that the vapor pressure is equal to the containment pressure. These assumptions ensure that no credit is taken for containment pressure.

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Enclosure Evaluation of the Proposed Change



3.3 Justification for the TS Change 3.3.1 Chronology of Testing Requirements of 10 CFR 50, Appendix J The testing requirements of 10 CFR 50, Appendix J, provide assurance that leakage from the containment, including systems and components that penetrate the containment, does not exceed the allowable leakage values specified in the TS. 10 CFR 50, Appendix J also ensures that periodic surveillances of reactor containment penetrations and isolation valves are performed so that proper maintenance and repairs are made during the service life of the containment and of the systems and components penetrating primary containment. The limitation on containment leakage provides assurance that the containment would perform its design function following an accident up to and including the plant design basis accident (DBA). Appendix J identifies three types of required tests:

1) Type A tests, intended to measure the primary containment overall integrated leakage rate;

2) Type B tests, intended to detect local leaks and to measure leakage across pressure-containing or leakage-limiting boundaries (other than valves) for primary containment penetrations, and;

3) Type C tests, intended to measure containment isolation valve (CIV) leakage rates.

Types B and C tests identify the vast majority of potential containment leakage paths. Type A tests identify the overall (integrated) containment leakage rate and serve to ensure continued leakage integrity of the containment structure by evaluating those structural parts of the containment not covered by Types B and C testing.

In 1995, 10 CFR 50, Appendix J, was amended to provide a performance-based Option B for the containment leakage testing requirements. Option B requires that test intervals for Type A, Type B, and Type C testing be determined by using a performance-based approach.

Performance-based test intervals are based on consideration of the operating history of the component and resulting risk from its failure. The use of the term "performance-based" in 10 CFR 50, Appendix J refers to both the performance history necessary to extend test intervals as well as to the criteria necessary to meet the requirements of Option B.

Also, in 1995, RG 1.163 (Reference 1) was issued. The RG endorsed NEI 94-01, Revision 0, (Reference 5) with certain modifications and additions. Option B, in concert with RG 1.163 and NEI 94-01, Revision 0, allows licensees with a satisfactory ILRT performance history (i.e., two consecutive, successful Type A tests) to reduce the test frequency for the containment Type A (ILRT) test from three tests in 10 years to one test in 10 years. This relaxation was based on an NRC risk assessment contained in NUREG-1493, (Reference 6) and Electric Power Research Institute (EPRI) TR-104285 (Reference 7), both of which showed that the risk increase associated with extending the ILRT surveillance interval was very small. In addition to the 10-year ILRT interval, provisions for extending the test interval an additional 15 months were considered in the establishment of the intervals allowed by RG 1.163 and NEI 94-01, but that this extension of interval "should be used only in cases where refueling schedules have been changed to accommodate other factors."

In 2008, NEI 94-01, Revision 2-A (Reference 8), was issued. This document describes an acceptable approach for implementing the optional performance-based requirements of Option B to 10 CFR 50, Appendix J, subject to the limitations and conditions noted in Section 10

Enclosure Evaluation of the Proposed Change



4.0 of the NRC safety evaluation (SE) report (SER) on NEI 94-01. NEI 94-01, Revision 2-A, includes provisions for extending Type A ILRT intervals to up to 15 years and incorporates the regulatory positions stated in RG 1.163 (Reference 1). The document also delineates a performance-based approach for determining Type A, Type B, and Type C containment leakage rate surveillance testing frequencies. Justification for extending test intervals is based on the performance history and risk insights.

In 2012, NEI 94-01, Revision 3-A (Reference 2), was issued. This document describes an acceptable approach for implementing the optional performance-based requirements of Option B to 10 CFR 50, Appendix J and includes provisions for extending Type A ILRT intervals to up to 15 years. NEI 94-01 has been endorsed by RG 1.163 and NRC SERs of June 25, 2008 (Reference 9), and June 8, 2012 (Reference 10), as an acceptable methodology for complying with the provisions of Option B in 10 CFR 50, Appendix J. The regulatory positions stated in RG 1.163, as modified by References 9 and 10, are incorporated in this document. It delineates a performance-based approach for determining Type A, Type B, and Type C containment leakage rate surveillance testing frequencies.

Justification for extending test intervals is based on the performance history and risk insights.

Extensions of Type B and Type C test intervals are allowed based upon completion of two consecutive periodic as-found tests where the results of each test are within a licensees allowable administrative limits. Intervals may be increased from 30 months up to a maximum of 120 months for Type B tests (except for containment airlocks) and up to a maximum of 75 months for Type C tests. If a licensee considers extended test intervals of greater than 60 months for Type B or Type C tested components, the review should include the additional considerations of as-found tests, schedule and review as described in NEI 94-01, Revision 3-A, Section 11.3.2.

The NRC has provided guidance concerning the use of test interval extensions in the deferral of ILRTs beyond the 15-year interval in NEI 94-01, Revision 2-A, NRC SER Section 3.1.1.2, which states, in part:

As noted above, Section 9.2.3, NEI TR 94-01, Revision 2, states, "Type A testing shall be performed during a period of reactor shutdown at a frequency of at least once per 15 years based on acceptable performance history." However, Section 9.1 states that the "required surveillance intervals for recommended Type A testing given in this section may be extended by up to 9 months to accommodate unforeseen emergent conditions but should not be used for routine scheduling and planning purposes." The NRC staff believes that extensions of the performance-based Type A test interval beyond the required 15 years should be infrequent and used only for compelling reasons. Therefore, if a licensee wants to use the provisions of Section 9.1 in TR NEI 94-01, Revision 2, the licensee will have to demonstrate to the NRC staff that an unforeseen emergent condition exists.

NEI 94-01, Revision 3-A, Section 10.1, Introduction, concerning the use of test interval extensions in the deferral of Type B and Type C Local Leakage Rate Tests (LLRTs), based on performance, states, in part:

Consistent with standard scheduling practices for Technical Specifications Required Surveillances, intervals of up to 120 months for the recommended surveillance frequency for Type B testing and up to 75 months for Type C testing given in this section may be extended by up to 25 percent of the test interval, not to exceed nine months.

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Enclosure Evaluation of the Proposed Change



Notes: For routine scheduling of tests at intervals over 60 months, refer to the additional requirements of Section 11.3.2.

Extensions of up to nine months (total maximum interval of 84 months for Type C tests) are permissible only for non-routine emergent conditions. This provision (nine-month extension) does not apply to valves that are restricted and/or limited to 30-month intervals in Section 10.2 (such as BWR MSIVs) or to valves held to the base interval (30 months) due to unsatisfactory LLRT performance.

The NRC has also provided the following concerning the extension of ILRT intervals to 15 years in NEI 94-01, Revision 3-A, NRC SER Section 4.0, Item 2:

The basis for acceptability of extending the ILRT interval out to once per 15 years was the enhanced and robust primary containment inspection program and the local leakage rate testing of penetrations. Most of the primary containment leakage experienced has been attributed to penetration leakage and penetrations are thought to be the most likely location of most containment leakage at any time 3.3.2 Current PVNGS Primary Containment Leakage Rate Testing Program Requirements 10 CFR Part 50, Appendix J was revised, effective October 26, 1995, to allow licensees to choose containment leakage testing under either Option A, Prescriptive Requirements, or Option B, Performance-Based Requirements. On February 23, 1996, the NRC approved Amendment Nos. 103, 92, and 75 to the facility operating licenses for PVNGS Units 1, 2, and 3, respectively (Reference 12). The amendments allowed the implementation of the recently approved Option B to 10 CFR Part 50, Appendix J. This new rule allowed for a performance-based option for determining the test frequency for containment leakage rate testing.

Option B states that specific existing exemptions to Option A are still applicable unless specifically revoked by the NRC. PVNGS currently has an approved exemption to 10 CFR Part 50, Appendix J, Option A. This exemption is from the requirements of Paragraph III.D.2(b)(ii) of Appendix J, the testing of containment air locks at times when containment integrity is not required. This exemption, which focuses on testing methodology aspects of Appendix J, is unaffected by the change to the Option B testing frequency requirements.

Currently, TS 5.5.16.a. requires that a program be established to comply with the containment leakage rate testing requirements of 10 CFR 50.54(o) and 10 CFR 50, Appendix J, Option B, as modified by approved exemptions. The program is required to be in accordance with the guidelines contained in RG 1.163. RG 1.163 endorses, with certain exceptions, NEI 94-01, Revision 0, as an acceptable method for complying with the provisions of Appendix J, Option B.

RG 1.163, Section C.1 states that licensees intending to comply with 10 CFR 50, Appendix J, Option B, should establish test intervals based upon the criteria in Section 11.0 of NEI 94-01, Revision 0 (Reference 5), rather than using test intervals specified in ANSI/ANS 56.8-1994.

NEI 94-01, Revision 0, Section 11.0, refers to Section 9, which states that Type A testing shall be performed during a period of reactor shutdown at a frequency of at least once-per-ten years based on acceptable performance history. Acceptable performance history is defined as completion of two consecutive periodic Type A tests where the calculated performance leakage was less than 1.0La (where La is the maximum allowable leakage rate at design pressure). Elapsed time between the first and last tests in a series of consecutive satisfactory tests used to determine performance shall be at least 24 months.

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Adoption of the Option B performance-based containment leakage rate testing program altered the frequency of measuring primary containment leakage in Types A, B, and C tests but did not alter the basic method by which Appendix J leakage testing is performed. The test frequency is based on an evaluation of the "as found" leakage history to determine a frequency for leakage testing, which provides assurance that leakage limits will not be exceeded. The allowed frequency for Type A testing as documented in NEI 94-01 is based, in part, upon a generic evaluation documented in NUREG-1493. The evaluation documented in NUREG-1493 included a study of the dependence or reactor accident risks on containment leak tightness for differing containment types. NUREG-1493 concluded in Section 10.1.2 that reducing the frequency of Type A tests (ILRT) from the original three (3) tests per 10 years to one (1) test per 20 years was found to lead to an imperceptible increase in risk. The estimated increase in risk is very small because ILRTs identify only a few potential containment leakage paths that cannot be identified by Types B and C testing, and the leaks that have been found by Type A tests have been only marginally above existing requirements. Given the insensitivity of risk to containment leakage rate and the small fraction of leakage paths detected solely by Type A testing, NUREG-1493 concluded that increasing the interval between ILRTs is possible with minimal impact on public risk.

3.3.3 PVNGS 10 CFR 50, Appendix J, Option B Licensing History February 2, 1996 - License Amendment Nos. 103, 92, and 75 The NRC approved Amendment Nos. 103 (PVNGS Unit 1), 92 (PVNGS Unit 2), and 75 (PVNGS Unit 3), which allowed the implementation of Option B to 10 CFR Part 50, Appendix J. This allowed for the implementation of a performance-based option for determining the test frequency for containment leakage rate testing in accordance with RG 1.163 and ANSI/ANS 56.8-1994. (ML021710536) (Reference 12)

September 11, 1997 - License Amendment Nos. 113, 106, and 85 The NRC approved Amendment Nos. 113 (PVNGS Unit 1), 106 (PVNGS Unit 2), and 85 (PVNGS Unit 3), which changed TS 3/4.6.1.3.b and its associated Bases sections to reflect an increase in the peak containment internal pressure for the design basis LOCA from 49.5 pounds per square inch gauge (psig) to 52 psig. (ML021710675) (Reference 13)

September 29, 2003 - License Amendment No. 149 The NRC approved Amendment No. 149 for PVNGS Unit 2, which changed the operating license and TS to support replacement of the steam generators and subsequent operation at an increased maximum power level of 3990 Megawatts thermal (MWt), a 2.94 percent increase from the then current 3876 MWt. The amendment also revised TS 5.5.16, Containment Leakage Rate Testing Program, to increase the peak calculated containment internal pressure for the design basis LOCA (Pa) for Unit 2 from 52.0 psig to 58.0 psig.

(ML032720538) (Reference 14)

January 12, 2004 - License Amendment No. 151 The NRC approved Amendment No. 151 for PVNGS Units 1, 2, and 3, which revised TS Section 5.5.6, Pre-Stressed Concrete Containment Tendon Surveillance Program, for consistency with the requirements of 10 CFR 50.55a(g)(4) for components classified as Code Class CC.

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In addition, the amendment revised TS 5.5.16, Containment Leakage Rate Testing Program, to add exceptions to RG 1.163, Performance-Based Containment Leak-Testing Program.

These exceptions stated that the visual examination of containment concrete surfaces and the examination of the steel liner plate inside containment will be performed in accordance with the requirements and frequency of ASME Code Section XI, Subsections IWL and IWE.

(ML040850657 and ML040850314) (Reference 15)

November 16, 2005 - License Amendment No. 157 The NRC approved Amendment No. 157 for PVNGS Units 1 and 3, which changed the facility operating licenses and TS to support replacement of the steam generators and subsequent operation at an increased maximum power level of 3990 megawatts thermal (MWt), a 2.94 percent increase from the current 3876 MWt for PVNGS Unit 1 and PVNGS Unit 3. The amendment also revised TS 5.5.16, Containment Leakage Rate Testing Program, to increase the peak calculated containment internal pressure for the design basis LOCA (Pa) for Units 1 and 3 from 52.0 psig to 58.0 psig. (ML053130275) (Reference 16)

October 20, 2009 - License Amendment No. 176 The NRC approved Amendment No. 176 for PVNGS Units 1, 2, and 3, which modified TS 5.5.16, Containment Leakage Rate Testing Program, by adding exceptions to the provisions of NRC RG 1.163, Performance-Based Containment Leak-Test Program, that would allow the next containment integrated leak rate tests to be performed at 15-year intervals instead of the current 10-year intervals for PVNGS Units 1, 2, and 3. (ML092810317) (Reference 17)

June 18, 2012 - License Amendment No. 189 The NRC approved Amendment No. 189 for PVNGS Units 1, 2, and 3, which revised TS 3.3.1, Reactor Protective System (RPS) Instrumentation - Operating, TS 3.3.2, Reactor Protective System (RPS) Instrumentation - Shutdown, TS 3.3.5, Engineered Safety Features Actuation System (ESFAS) Instrumentation, TS 3.3.9, Control Room Essential Filtration Actuation Signal (CREFAS), TS 3.5.5, Refueling Water Tank (RWT), TS 3.7.11, Control Room Essential Filtration System (CREFS), TS 5.4, Procedures, and TS 5.5.16, Containment Leakage Rate Testing Program, to make administrative and editorial changes to clarify and align existing TS.

This amendment revised TS 5.5.16.b to remove historical data on the calculated containment internal pressures (Pa) for each of the PVNGS units and reflect that the current (Pa) for all three units is 58.0 psig. (ML120860092) (Reference 18) 3.3.4 Integrated Leakage Rate Testing (ILRT) History As noted previously, PVNGS TS 5.5.16 currently requires Types A, B, and C testing in accordance with RG 1.163, which endorses the methodology for complying with 10 CFR 50, Appendix J, Option B. Since the adoption of Option B, the performance leakage rates are calculated in accordance with NEI 94-01, Section 9.1.1 for Type A testing.

Table 3.3.4-1 lists the Past Periodic Type A ILRT results for PVNGS Units 1, 2, and 3.

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Table 3.3.4-1, Past Periodic Type A ILRT Results for PVNGS Units 1, 2, and 3 95% Upper Confidence Limit (UCL) Test Pressure (psig) Test Date (wt%/day)

Unit 1 0.0608 58.1 psig (Pa = 58 psig) November 2014 0.0544 52.7 psig (Pa = 52 psig)2 November 1999 0.0660 50.3 psig (Pa = 49.5 psig) February 1990 0.0664 49.7 psig (Pa = 49.2 psig) April 1986 0.0142 49.7 psig (Pa = 49.2 psig)1 December 1982 Unit 2 0.0492 58.3 psig (Pa = 58 psig) October 2015 0.0404 58.9 psig (Pa = 58 psig) October 2000 0.0310 50.3 psig (Pa = 49.5 psig) December 1991 0.0599 50.5 psig (Pa = 49.5 psig) May 1988 0.0092 50.0 psig (Pa = 49.2 psig)1 February 1985 Unit 3 0.0492 58.3 psig (Pa = 58 psig) April 2015 0.0490 52.8 psig (Pa = 52 psig)2 April 2000 0.0600 50.3 psig (Pa = 49.5 psig) May 1991 0.0521 49.7psig (Pa = 49.2 psig) September 1986 Note 1: Preoperational ILRT performed in conjunction with a structural integrity test (SIT) performed at 69 psig, 115% of containment design pressure of 60 psig.

Note 2: Per TS 5.5.16.b, the current Pa for the design basis loss of coolant accident is 58.0 psig for Units 1, 2, and 3, since all three units are past operating cycle 13.

As noted above, Units 1 and 3 were tested at 52 psig in November 1999, and April 2000, respectively, and Unit 2 was tested in October 2000, at 58.0 psig.

The NRC provided the following guidance on page 29, Section 4.2.1 of the Safety Evaluation letter entitled, Palo Verde Nuclear Generating Station, Units 1, 2, and 3 - Issuance of Amendments re: Replacement of Steam Generators and Uprated Power Operations and Associated Administrative Changes (TAC Nos. MC3777, MC3778, and MC3779), dated November 16, 2005, (ML053130275) (Reference 16), concerning the increase in Pa to 58 psig associated with power up-rate and replacement steam generators, and the need to perform ILRT testing at the higher pressure prior to restart:

An additional consideration is whether the increase in Pa, the calculated peak containment internal pressure related to the design-basis LOCA, from 52 psig to 58 psig would require new containment leakage rate tests at the higher pressure before plant restart. After reviewing the applicable regulations and guidance documents, the staff finds that there is no requirement for new tests at the higher pressure before the plant can restart. When the tests next come due, or the normal schedule, they will be performed at the new value of Pa. The staff considers the previous tests, performed at the old value of Pa, to remain valid and constitute an adequate indication of the leak-tightness of the containment, until new tests are performed on the normal schedule.

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Enclosure Evaluation of the Proposed Change



3.3.5 Performance Leakage Rate Determination The current ILRT test interval for PVNGS Units 1, 2, and 3 is ten years. Verification of this interval is presented in Table 3.3.5-1. The acceptance criteria used for this verification is contained in NEI 94-01, Revisions 2-A and 3-A, Section 5.0, Definitions, and is as follows:

The performance leakage rate is calculated as the sum of the Type A upper confidence limit (UCL) and as-left minimum pathway leakage rate (MNPLR) leakage rate for all Type B and Type C pathways that were in service, isolated, or not lined up in their test position (i.e., drained and vented to containment atmosphere) prior to performing the Type A test.

In addition, leakage pathways that were isolated during performance of the test because of excessive leakage must be factored into the performance determination. The performance criterion for Type A tests is a performance leak rate of less than 1.0La.

Table 3.3.5-1, PVNGS ILRT Test Results Verification of Current Extended ILRT Interval Test Upper 95% Level As Left Min Adjusted As ILRT Test Method/

Date Confidence Corrections Pathway Left Leak Acceptance Data Analysis Limit (Leakage Penalty for Rate Criteria Techniques (wt.%/day) Savings) Isolated (wt.%/day)

(Test (wt.%/day) Pathways Pressure) (wt.%/day)

Unit 1 Absolute /

November 0.0608 ANSI/ANS 0.0 0.0045 0.0653 0.075 2014 (58.1 psig) 56.8-1994 Mass Point Absolute /

November 0.0544 ANSI/ANS 0.0 0.00104 0.05544 0.075 1999 (52.7 psig) 56.8-1994 Mass Point Unit 2 Absolute /

October 0.0492 0.0 ANSI/ANS 0.0008 0.0501 0.075 2015 (58.3 psig) (0.0001) 56.8-1994 Mass Point Absolute /

October 0.0404 ANSI/ANS 0.0 0.0011 0.0415 0.075 2000 (58.9 psig) 56.8-1994 Mass Point Unit 3 Absolute /

0.0492 ANSI/ANS April 2015 0.0 0.001 0.0502 0.075 (58.3 psig) 56.8-1994 Mass Point Absolute /

0.0490 ANSI/ANS April 2000 0.0001 0.0022 0.0513 0.075 (52.8 psig) 56.8-1994 Mass Point 16

Enclosure Evaluation of the Proposed Change



3.4 Plant Specific Confirmatory Analysis 3.4.1 Methodology An analysis was performed to provide a risk assessment of permanently extending the currently allowed containment Type A ILRT from ten years to fifteen years. The extension would allow for substantial cost savings as the ILRT could be deferred for additional scheduled refueling outages for the PVNGS. The risk assessment follows the guidelines from:

 NEI 94-01, Revision 3-A (Reference 2),

 NEI, Interim Guidance for Performing Risk Impact Assessments in Support of One-Time Extensions for Containment Integrated Leakage Rate Test Surveillance Intervals, November 2001 (Reference 20),

 NRC regulatory guidance on the use of Probabilistic Risk Assessment (PRA) as stated in RG 1.200, Revision 2 (Reference 4), as applied to ILRT interval extensions,

 Risk insights in support of a request for a plants licensing basis as outlined in RG 1.174 (Reference 3),

 The methodology used for Calvert Cliffs to estimate the likelihood and risk implications of corrosion-induced leakage of steel liners going undetected during the extended test interval (Reference 32),

 The methodology used in EPRI Technical Report (TR)-1018243, Revision 2-A of EPRI 1009325 (Reference 11).

Details of the PVNGS Units 1, 2, and 3 risk assessment, providing an assessment of the risk associated with implementing a permanent extension of the PVNGS containment Type A ILRT interval from ten years to fifteen years, is contained in Attachment 1 of this submittal.

The NRC report on performance-based leak testing, NUREG-1493 (Reference 6), analyzed the effects of containment leakage on the health and safety of the public and the benefits realized from the containment leak rate testing. In that analysis, it was determined that for a representative pressurized water reactor (PWR) plant (i.e., Surry) containment isolation failures contribute less than 0.1% to the latent risks from reactor accidents. Consequently, it is desirable to show that extending the ILRT interval will not lead to a substantial increase in risk from containment isolation failures for PVNGS Units 1, 2, and 3.

NEI 94-01, Revision 3-A, supports using EPRI Report No. 1009325, Revision 2-A (EPRI TR-1018243), Risk Impact Assessment of Extended Integrated Leak Rate Testing Intervals (Reference 11), for performing risk impact assessments in support of ILRT extensions. The guidance provided in Appendix H of EPRI Report No. 1009325, Revision 2-A, for performing risk impact assessments in support of ILRT extensions builds on the EPRI Risk Assessment methodology, EPRI TR-104285. This methodology is followed to determine the appropriate risk information for use in evaluating the impact of the proposed ILRT changes.

In the Safety Evaluation (SE) issued by the NRC letter dated June 25, 2008 (Reference 9),

the NRC concluded that the methodology in EPRI TR-1009325, Revision 2 (Reference 11),

was acceptable for referencing by licensees proposing to amend their TS to permanently extend the ILRT surveillance interval to 15 years, subject to the limitations and conditions noted in Section 4.0 of the SE. Table 3.4.1-1 addresses each of the four (4) limitations and conditions from Section 4.2 of the SE for the use of EPRI 1009325, Revision 2.

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Enclosure Evaluation of the Proposed Change



Table 3.4.1-1, EPRI Report No. 1009325, Revision 2, Limitations and Conditions Limitation and Condition PVNGS Response (From Section 4.2 of SE)

1. The licensee submits documentation PVNGS PRA technical adequacy is indicating that the technical adequacy addressed in Section 3.4.2 of this LAR and of their PRA is consistent with the Attachment 1, Evaluation of Risk requirements of RG 1.200 relevant to Significance of Permanent ILRT Extension, the ILRT extension application. Appendix A, PRA Acceptability.

2.a The licensee submits documentation Since the ILRT does not impact core indicating that the estimated risk damage frequency (CDF), the relevant increase associated with permanently criterion is large early release frequency extending the ILRT surveillance (LERF). The increase in LERF resulting interval to 15 years is small, and from a change in the Type A ILRT test consistent with the clarification interval from 3 in 10 years to 1 in 15 years provided in Section 3.2.4.5 of this SE. is estimated as 1.77E-07/year using the EPRI guidance; this value increases negligibly if the risk impact of corrosion-induced leakage of the steel liners occurring and going undetected during the extended test interval is included. Total Internal Events and Internal Flood LERF (baseline and change in LERF due to the ILRT extension) is 9.83E-07/year.

Therefore, the estimated change in LERF is determined to be small using the acceptance guidelines of RG 1.174 (See Attachment 1, Section 7.0 of this submittal).

2.b Specifically, a small increase in The effect resulting from changing the population dose should be defined as Type A test frequency to 1-per-15 years, an increase in population dose of less measured as an increase to the total than or equal to either 1.0 person-rem integrated plant risk for those accident per year or 1% of the total population sequences influenced by Type A testing is dose, whichever is less restrictive. 0.12 person-rem/year. NEI 94-01 states that a small population dose is defined as an increase of 1.0 person-rem per year, or 1% of the total population dose, whichever is less restrictive for the risk impact assessment of the extended ILRT intervals. The results of this calculation meet these criteria. Moreover, the risk impact for the ILRT extension when compared to other severe accident risks is negligible. (See Attachment 1, Section 7.0 of this submittal.)

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Enclosure Evaluation of the Proposed Change



Table 3.4.1-1, EPRI Report No. 1009325, Revision 2, Limitations and Conditions Limitation and Condition PVNGS Response (From Section 4.2 of SE) 2.c In addition, a small increase in CCFP The increase in the conditional should be defined as a value containment failure probability (CCFP) marginally greater than that accepted from the 3 in 10-year interval to 1 in 15-in a previous one-time 15-year ILRT year interval is 0.881%. NEI 94-01 states extension requests. This would that increases in CCFP of 1.5% is require that the increase in CCFP be small. (See Attachment 1, Section 7.0 of less than or equal to 1.5 percentage this submittal.)

point.

3. The methodology in EPRI Report No. The representative containment leakage 1009325, Revision 2, is acceptable for Class 3b sequences is 100La based on except for the calculation of the the guidance provided in EPRI Report No.

increase in expected population dose 1009325, Revision 2-A (EPRI TR-(per year of reactor operation). In 1018243). (See Attachment 1, Section 4.0 order to make the methodology of this submittal.)

acceptable, the average leak rate accident case (accident case 3b) used by the licensees shall be 100 La instead of 35 La.

4. A licensee amendment request (LAR) PVNGS does not rely upon containment is required in instances where over-pressure for ECCS performance.

containment over-pressure is relied (Refer to Section 3.2 of this submittal.)

upon for ECCS performance.

3.4.2 Technical Adequacy of the Probabilistic Risk Assessment (PRA)

PRA Quality Statement for Permanent 15-Year ILRT Extension The PVNGS PRA has undergone numerous peer reviews and Fact and Observation (F&O) closure reviews. All finding level F&Os have been resolved and F&O closure reviews performed to document closure. There are no open finding level F&Os associated with the PRA. The PVNGS PRA is technically adequate to support this risk-informed application.

Internal Events and Internal Flood PRA The Internal Events PRA model was peer reviewed in July 1999 by the Combustion Engineering Owners Group (CEOG) prior to the issuance of RG 1.200 (Reference 21). As a result, a self-assessment of the Internal Events PRA model was conducted by APS in March 2011 in accordance with Appendix B of RG 1.200, Revision 2 (Reference 4), to address the PRA quality requirements not considered in the CEOG peer review.

The Internal Events PRA quality (including the CEOG peer review and self-assessment results) has previously been reviewed by the NRC in requests to extend the Inverter Technical Specification Completion Time dated September 29, 2010 (Reference 35), and to implement TSTF-425, Relocate Surveillance Frequencies to Licensee Control - RITSTF Initiative 5b, dated December 15, 2011 (Reference 34). All PRA upgrades [as defined by the ASME PRA Standard RA-Sa-2009 (Reference 33)] implemented since conduct of the CEOG 19

Enclosure Evaluation of the Proposed Change



peer review in 1999 have been peer reviewed.

A focused-scope PRA peer review of the PVNGS internal flood PRA (IFPRA) to determine compliance with Addendum A of the ASME/ANS PRA Standard and RG 1.200, Revision 2, was performed in 2010.

Focused scope peer reviews of all F&Os that constituted an upgrade to the PRA were performed in 2017 (Reference 30), 2018 (Reference 41), and 2020 (Reference 29). All F&Os were reviewed and confirmed closed during concurrent F&O closure reviews performed in 2017 (Reference 30), 2018 (Reference 44), and 2020 (Reference 45).

Fire PRA A full-scope peer review to determine compliance with Addendum A of the ASME/ANS PRA Standard and RG 1.200, Revision 2, was performed on the PVNGS fire PRA by the Pressurized Water Reactors Owners Group (PWROG) in 2012. In 2014, after updating the PVNGS fire PRA to address selected F&Os identified in the full-scope fire PRA peer review, a focused-scope peer review was performed on the PVNGS fire PRA.

Focused scope peer reviews of all F&O resolutions that constituted an upgrade to the PRA were performed in 2017 (Reference 30), 2018 (Reference 41), and 2020 (Reference 29). All F&Os were reviewed and confirmed closed during concurrent F&O closure reviews performed in 2017 (Reference 30), 2018 (Reference 44), and 2020 (Reference 45).

Seismic PRA APS conducted a full scope Seismic PRA model peer review in February 2013, in accordance with the current endorsed standard ASME/ANS RA-Sa-2009 and NEI 12-13 (Reference 43),

including NRC comments on NEI 12-13. All finding F&Os were resolved.

Focused scope peer reviews of all F&O resolutions that constituted an upgrade to the PRA were performed in 2017 (Reference 30), 2018 (Reference 41), and 2020 (Reference 29). All F&Os were reviewed and confirmed closed during concurrent F&O closure reviews performed in 2017 (Reference 30), 2018 (Reference 44), and 2020 (Reference 45).

Other External Hazards PRA APS conducted a full scope External Hazards screening peer review in December 2011, in accordance with RG 1.200, Revision 2.

All F&Os were subsequently resolved and then were confirmed closed during an F&O closure review performed in 2018 (Reference 44).

Assessment of RG 1.200, Revision 3 The risk associated with implementing a permanent extension of the PVNGS containment Type A ILRT interval from ten years to fifteen years, is contained in Attachment 1 of this submittal, which applies RG 1.200, Revision 2 (Reference 4), to ILRT interval extensions.

APS conducted a review of the recent issuance of RG 1.200, Revision 3 (Reference 46), to determine if there were any impacts with implementing a permanent extension of the PVNGS containment Type A ILRT interval from ten years to fifteen years for this license amendment, due to the changes in RG 1.200 from Revision 2 to Revision 3. The review of RG 1.200 from Revision 2 to Revision 3 did not identify any impacts to the PRA model that is used for the 20

Enclosure Evaluation of the Proposed Change



plant specific risk assessment conducted to support this change. Therefore, it is appropriate to use the PVNGS PRA model used in Attachment 1, which applies RG 1.200, Revision 2 (Reference 4), to ILRT interval extensions, in support of this license amendment.

PRA Maintenance and Update The APS risk management process ensures that the applicable PRA models used in this application continue to reflect the as-built and as-operated plant for each of the PVNGS units.

The process delineates the responsibilities and guidelines for updating the PRA model, and includes criteria for both regularly scheduled and interim PRA model updates. The process includes provisions for monitoring potential areas affecting the PRA model (e.g., due to changes in the plant, errors or limitations identified in the model, industry operational experience) for assessing the risk impact of unincorporated changes, and for controlling the model and associated computer files. The process assesses the impact of these changes on the plant PRA model in a timely manner but no longer than once every two refueling outages.

3.4.3 Summary of Plant-Specific Risk Assessment Results The findings of the PVNGS Units 1, 2, and 3 Risk Assessment contained in Attachment 1 of this submittal confirm the general findings of previous studies that the risk impact associated with extending the ILRT interval from three in ten years to one in 15 years is small.

Based on the results from Attachment 1, Section 5.2, and the sensitivity calculations presented in Attachment 1, Section 5.3, the following conclusions regarding the assessment of the plant risk are associated with extending the Type A ILRT test frequency to 15 years:

 RG 1.174 (Reference 3), provides guidance for determining the risk impact of plant-specific changes to the licensing basis. RG 1.174, defines small changes in risk as resulting in increases of CDF greater than 1.0E-06/year and less than 1.0E-05/year and increases in LERF greater than 1.0E-07/year and less than 1.0E-06/yr. Since the ILRT does not impact CDF, the relevant criterion is LERF. The increase in LERF resulting from a change in the Type A ILRT test interval from 3 in 10 years to 1 in 15 years is estimated as 1.77E-07/year using the EPRI guidance; this value increases negligibly if the risk impact of corrosion-induced leakage of the steel liners occurring and going undetected during the extended test interval is included. Total Internal Events and Internal Flood LERF (baseline and change in LERF due to the ILRT extension) is 9.83E-07/year. Therefore, the estimated change in LERF is determined to be small using the acceptance guidelines of RG 1.174. The risk change resulting from a change in the Type A ILRT test interval from 3 in 10 years to 1 in 15 years bounds the 1 in 10 years to 1 in 15 years risk change. Considering the increase in LERF resulting from a change in the Type A ILRT test interval from 1 in 10 years to 1 in 15 years is estimated as 7.37E-08/year, the risk increase is very small using the acceptance guidelines of RG 1.174.

 When external event risk is included, the increase in LERF resulting from a change in the Type A ILRT test interval from 3 in 10 years to 1 in 15 years is estimated as 4.91E-07/year using the EPRI guidance, and total LERF is 8.23E-06/year. As such, the estimated change in LERF is determined to be small using the acceptance guidelines of RG 1.174. The risk change resulting from a change in the Type A ILRT test interval from 3 in 10 years to 1 in 15 years bounds the 1 in 10 years to 1 in 15 years risk change. When external event risk is included, the increase in LERF resulting from a change in the Type A ILRT test interval from 1 in 10 years to 1 in 15 years is 21

Enclosure Evaluation of the Proposed Change



estimated as 2.05E-07/year, and the total LERF is 7.94E-06 /year. Therefore, the risk increase is small using the acceptance guidelines of RG 1.174.

 The effect resulting from changing the Type A test frequency to 1-per-15 years, measured as an increase to the total integrated plant risk for those accident sequences influenced by Type A testing is 0.12 person-rem/year. NEI 94-01 states that a small population dose is defined as an increase of 1.0 person-rem per year, or 1% of the total population dose, whichever is less restrictive for the risk impact assessment of the extended ILRT intervals. The results of this calculation meet these criteria. Moreover, the risk impact for the ILRT extension when compared to other severe accident risks is negligible.

 The increase in the conditional containment failure probability from the 3 in 10-year interval to 1 in 15-year interval is 0.881%. NEI 94-01 states that increases in CCFP of 1.5% is small. Therefore, this increase is judged to be small.

Therefore, increasing the ILRT interval to 15 years is considered to be small since it represents a small change to the PVNGS risk profile.

3.4.4 Previous Assessments The NRC, in NUREG-1493 (Reference 6), has previously concluded that:

 Reducing the frequency of Type A tests (ILRTs) from 3 per 10 years to 1 per 20 years was found to lead to an imperceptible increase in risk. The estimated increase in risk is very small because ILRTs identify only a few potential containment leakage paths that cannot be identified by Type B or Type C testing, and the leaks that have been found by Type A tests have been only marginally above existing requirements.

 Given the insensitivity of risk to containment leakage rate and the small fraction of leakage paths detected solely by Type A testing, increasing the interval between integrated leakage-rate tests is possible with minimal impact on public risk. The impact of relaxing the ILRT frequency beyond 1 in 20 years has not been evaluated.

Beyond testing the performance of containment penetrations, ILRTs also test integrity of the containment structure.

The conclusions for PVNGS confirm these general conclusions on a plant-specific basis considering the severe accidents evaluated for PVNGS, the PVNGS containment failure modes, and the local population surrounding PVNGS.

3.4.5 RG 1.174 Defense in Depth Evaluation RG 1.174, Revision 3 (Reference 3), describes an approach that is acceptable for developing risk-informed applications for a licensing basis change that considers engineering issues and applies risk insights. One of the considerations included in RG 1.174 is Defense in Depth.

Defense in Depth is a safety philosophy that employs successive compensatory measures to prevent accidents or mitigate damage if a malfunction, accident, or naturally caused event occurs at a nuclear facility. The following seven considerations, as presented in RG 1.174, Revision 3, Section C.2.1.1.2, Considerations for Evaluating the Impact of the Proposed Licensing Basis Change on Defense in Depth, will serve to evaluate the proposed licensing basis change for overall impact on Defense in Depth for PVNGS.

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1. Preserve a reasonable balance among the layers of defense.

A reasonable balance of the layers of defense (i.e., minimizing challenges to the plant, preventing any events from progressing to core damage, containing the radioactive source term, and emergency preparedness) helps to ensure an apportionment of the plants capabilities between limiting disturbances to the plant and mitigating their consequences. The term reasonable balance is not meant to imply an equal apportionment of capabilities. The NRC recognizes that aspects of a plants design or operation might cause one or more of the layers of defense to be adversely affected.

For these situations, the balance between the other layers of defense becomes especially important when evaluating the impact of the proposed licensing basis change and its effect on defense in depth.

Response

Several layers of defense are in place to ensure the PVNGS containment structure(s);

penetrations, isolation valves and mechanical seal systems; continue(s) to perform their intended safety function. The purpose of the proposed change is to extend the testing frequencies of the Type A Integrated Leakage Rate Test (ILRT) from 10 years to 15 years and Type C Local Leakage Rate Tests (LLRTs) for selected components from 60-months to 75-months.

As shown in NUREG-1493, Performance-Based Containment Leak-Test Program (Reference 6), increasing the test frequency of ILRTs up to a 20-year test interval was found to lead to an imperceptible increase in risk. The estimated increase in risk is very small because ILRTs identify only a few potential containment leakage paths that cannot be identified by Type B or Type C testing. The study also concluded that extending the frequency of Type B tests is possible with no adverse impact on risk as identified leakage through Type B mechanical penetrations are both infrequent and small. Finally, the study concluded that Types B and C tests could identify the vast majority (greater than 95 percent) of all potential leakage paths.

Several programmatic factors can also be cited as layers of defense ensuring the continued safety function of the PVNGS containment pressure boundary. NEI 94-01, Revisions 2-A and 3-A, require sites adopting the 15-year extended ILRT interval perform visual examinations of the accessible interior and exterior surfaces of the containment structure for structural degradation that may affect the containment leak-tight integrity at the frequency prescribed by the guidance or, if approved through a TS amendment, at the frequencies prescribed by ASME Section XI, which is the case for PVNGS Units 1, 2, and 3. Additionally, several measures are put in place to ensure integrity of the Types B and C tested components. NEI 94-01 limits large containment penetrations such as airlocks, purge and vent valves, boiling water reactor (BWR) main steam and feedwater isolation valves, to a maximum 30-month testing interval. For those valves that meet the performance standards defined in NEI 94-01, Revision 3-A, and are selected for test intervals greater than 60 months, a leakage understatement penalty is added to the MNPLR prior to the frequency being extended beyond 60-months. Finally, identification of adverse trends in the overall Types B and C leakage rate summations and available margin between the Type B and Type C leakage rate summation and its regulatory limit are required by NEI 94-01, Revision 3-A, to be shown in the PVNGS post-outage report(s). Therefore, the proposed change does not challenge or limit the layers of defense available to assess the ability of the PVNGS containment structure to perform its safety function.

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PRA Response:

The use of the risk metrics of LERF, population dose, and conditional containment failure probability collectively ensures the balance between prevention of core damage, prevention of containment failure, and consequence mitigation is preserved.

The change in LERF is small with respect to internal events and small when including external events per RG 1.174, and the change in population dose and CCFP are small as defined in this analysis and consistent with NEI 94-01, Revision 3-A.

2. Preserve adequate capability of design features without an overreliance on programmatic activities as compensatory measures.

Nuclear power plant licensees implement a number of programmatic activities, including programs for quality assurance, testing and inspection, maintenance, control of transient combustible material, foreign material exclusion, containment cleanliness, and training. In some cases, activities that are part of these programs are used as compensatory measures; that is, they are measures taken to compensate for some reduced functionality, availability, reliability, redundancy, or other feature of the plants design to ensure safety functions (e.g., reactor vessel inspections that provide assurance that reactor vessel failure is unlikely). NUREG-2122, Glossary of Risk-Related Terms in Support of Risk-Informed Decision Making, (Reference 19), defines safety function as those functions needed to shut down the reactor, remove the residual heat, and contain any radioactive material release.

A proposed licensing basis change might involve or require compensatory measures.

Examples include hardware (e.g., skid-mounted temporary power supplies); human actions (e.g., manual system actuation); or some combination of these measures.

Such compensatory measures are often associated with temporary plant configurations. The preferred approach for accomplishing safety functions is through engineered systems. Therefore, when the proposed licensing basis change necessitates reliance on programmatic activities as compensatory measures, the licensee should justify that this reliance is not excessive (i.e., not overly reliant). The intent of this consideration is not to preclude the use of such programs as compensatory measures but to ensure that the use of such measures does not significantly reduce the capability of the design features (e.g., hardware).

Response

The purpose of the proposed change is to extend the testing frequencies of the Type A ILRT from 10 years to 15 years and select Type C LLRTs from 60 months to 75 months. Several programmatic factors were defined in the response to Question 1 above, which are required when adopting NEI 94-01, Revisions 2-A and 3-A. These factors are conservative in nature and are designed to generate corrective actions if the required testing or inspections are deemed unsatisfactory well in advance to ensure the continued safety function of the containment is maintained. The programmatic factors are designed to provide differing ways to test and/or examine the containment pressure boundary in a manner that verifies the PVNGS containment pressure boundary will perform its intended safety function. Since the proposed change does not alter the configuration of the PVNGS containment pressure boundary, continued performance of the tests and inspections associated with NEI 94-01 will only serve to ensure the continued safety function of the containment without affecting any margin of safety.

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PRA Response:

The adequacy of the design feature (the containment boundary subject to Type A testing) is preserved as evidenced by the overall small change in risk associated with the Type A test frequency change.

3. Preserve system redundancy, independence, and diversity commensurate with the expected frequency and consequences of challenges to the system, including consideration of uncertainty.

As stated in RG 1.174, Revision 3, Section C.2.1.1.1, Background, the defense-in-depth philosophy has traditionally been applied in plant design and operation to provide multiple means to accomplish safety functions. System redundancy, independence, and diversity result in high availability and reliability of the function and also help ensure that system functions are not reliant on any single feature of the design. Redundancy provides for duplicate equipment that enables the failure or unavailability of at least one set of equipment to be tolerated without loss of function.

Independence of equipment implies that the redundant equipment is separate such that it does not rely on the same supports to function. This independence can sometimes be achieved by the use of physical separation or physical protection.

Diversity is accomplished by having equipment that performs the same function rely on different attributes such as different principles of operation, different physical variables, different conditions of operation, or production by different manufacturers which helps reduce common-cause failure (CCF).

A proposed change might reduce the redundancy, independence, or diversity of systems. The intent of this consideration is to ensure that the ability to provide the system function is commensurate with the risk of scenarios that could be mitigated by that function. The consideration of uncertainty, including the uncertainty inherent in the PRA, implies that the use of redundancy, independence, or diversity provides high reliability and availability and also results in the ability to tolerate failures or unanticipated events.

Response

The proposed change to extend the testing frequencies of the Type A ILRT from 10 years to 15 years and select Type C LLRTs from 60 months to 75 months does not reduce the redundancy, independence or diversity of systems. As shown in NUREG-1493, increasing the test frequency of ILRTs up to a 20-year test interval was found to lead to an imperceptible increase in risk. The estimated increase in risk is very small because ILRTs identify only a few potential containment leakage paths that cannot be identified by Type B or Type C testing. The study also concluded that extending the frequency of Type B tests is possible with no adverse impact on risk as identified leakage through Type B mechanical penetrations are both infrequent and small.

Additionally, the study concluded that Type B and C tests could identify the vast majority (greater than 95 percent) of all potential leakage paths.

Despite the change in test interval, containment isolation diversity remains unaffected and will continue to provide the inherent isolation, as designed. In addition, NEI 94-01, Revisions 2-A and 3-A, Section 11.3.2, requires a schedule of tests be developed, for components on a test interval greater than 60 months, such that unanticipated random failures and unexpected common-mode failures are avoided. This is typically accomplished by implementing test intervals at approximately evenly distributed intervals. Therefore, the proposed change preserves system redundancy, independence, and diversity and ensures a high reliability and availability of the 25

Enclosure Evaluation of the Proposed Change



containment structure to perform its safety function in the event of unanticipated events.

PRA Response:

The redundancy, independence, and diversity of the containment subject to the Type A test is preserved, commensurate with the expected frequency and consequences of challenges to the system, as evidenced by the overall small change in risk associated with the Type A test frequency change.

4. Preserve adequate defense against potential common-cause failures (CCFs).

An important aspect of ensuring defense in depth is to guard against CCF. Multiple components may fail to function because of a single specific cause or event that could simultaneously affect several components important to risk. The cause or event may include an installation or construction deficiency, accidental human action, extreme external environment, or an unintended cascading effect from any other operation or failure within the plant. CCFs can also result from poor design, manufacturing, or maintenance practices. Defenses can prevent the occurrence of failures from the causes and events that could allow simultaneous multiple component failures.

Another aspect of guarding against CCF is to ensure that an existing defense put in place to minimize the impact of CCF is not significantly reduced; however, a reduction in one defense can be compensated for by adding another.

Response

As part of the proposed change, PVNGS will be required to adopt the performance-based testing standards outlined in NEI 94-01, Revisions 2-A and 3-A, along with ANSI/ANS 56.8-2002. NEI 94-01, Revisions 2-A and 3-A, Section 11.3.2, requires a schedule of tests be developed, for components on test intervals greater than 60 months, such that unanticipated random failures and unexpected common-mode failures are avoided. This is typically accomplished by implementing test intervals at approximately evenly distributed intervals. In addition, components considered to be risk-significant from a PRA standpoint are required to be limited to a testing interval less than the maximum allowable limit of 75 months. For those components that have demonstrated satisfactory performance and have had their testing limits extended, administrative testing limits are assigned on a component-by-component basis and are used to identify potential valve or penetration degradation. Administrative limits are established at a value low enough to identify and should allow early correction in advance of total valve failure. Should a component exceed its administrative limit during testing, NEI 94-01, Revisions 2-A and 3-A, require cause determinations be performed designed to reinforce achieving acceptable performance. The cause determination is designed to identify and address common-mode failure mechanisms through appropriate corrective actions. The proposed change also imposes a requirement to address margin management (i.e., margin between the current containment leakage rate and its pre-established limit). As a result, adoption of the performance-based testing standards proposed by this change ensures adequate barriers exist to preclude failure of the containment pressure boundary due to common-mode failures and therefore continues to guard against CCF.

PRA Response:

Adequate defense against CCFs is preserved. The Type A test detects problems in the containment which may or may not be the result of a CCF; such a CCF may affect failure of another portion of containment (i.e., local penetrations) due to the same phenomena. Adequate defense against CCFs is preserved via the continued 26

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performance of the Type B and C tests and the performance of inspections. The change to the Type A test, which bounds the risk associated with containment failure modes including those involving CCFs, does not degrade adequate defense as evidenced by the overall small change in risk associated with the Type A test frequency change.

5. Maintain multiple fission product barriers.

Fission product barriers include the physical barriers themselves (e.g., the fuel cladding, reactor coolant system pressure boundary, and containment) and any equipment relied on to protect the barriers (e.g., containment spray). In general, these barriers are designed to perform independently so that a complete failure of one barrier does not disable the next subsequent barrier. For example, one barrier, the containment, is designed to withstand a double-ended guillotine break of the largest pipe in the reactor coolant system, another barrier.

A plants licensing basis might contain events that, by their very nature, challenge multiple barriers simultaneously. Examples include interfacing-system loss-of-coolant (ISLOCA) accidents, steam generator tube rupture (SGTR), or crediting containment accident pressure. Therefore, complete independence of barriers, while a goal, might not be achievable for all possible scenarios.

Response

The purpose of the proposed change is to extend the testing frequencies of the Type A ILRT from 10 years to 15 years and select Type C LLRTs from 60 months to 75 months. As part of the proposed change, PVNGS will be required to adopt the performance-based testing standards outlined in NEI 94-01, Revisions 2-A and 3-A, along with ANSI/ANS 56.8-2002. The overall containment leakage rate calculations associated with the testing standards contain inherent conservatisms through the use of margin. Plant TS require the overall primary containment leakage rate to be less than or equal to 1.0 La. NEI 94-01 requires the as-found Type A test leakage rate must be less than the acceptance criterion of 1.0 La given in the plant TS. Prior to entering a mode where containment integrity is required, the as-left Type A leakage rate shall not exceed 0.75 La. The as-found and as-left values are as determined by the appropriate testing methodology specifically described in ANSI/ANS 56.8-2002.

Additionally, the combined leakage rate for all Type B and Type C tested penetrations shall be less than or equal to 0.6 La, determined on a maximum pathway basis from the as-left LLRT results prior to entering a mode where containment integrity is required. This regulatory approach results in a 25% and 40% margin, respectively, to the 1.0 La requirements. For those local leak rate tested components that have demonstrated satisfactory performance and have had their testing limits extended, administrative testing limits are assigned on a component by component basis and are used to identify potential valve or penetration degradation. Administrative limits are established at a value low enough to identify and allow early correction in advance of total valve failure. Should a component exceed its administrative limit during testing, NEI 94-01, Revisions 2-A and 3-A, require cause determinations be performed designed to reinforce achieving acceptable performance. The cause determination is designed to identify and address common-mode failure mechanisms through appropriate corrective actions. Therefore, the proposed change adopts requirements with inherent conservatisms to ensure the margin to safety limit is maintained, thereby, preserving the containment fission product barrier.

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PRA Response:

Multiple Fission Product barriers are maintained. The portion of the containment affected by the Type A test extension is still maintained as an independent fission product barrier, albeit with an overall small change in the reliability of the barrier.

6. Preserve sufficient defense against human errors.

Human errors include the failure of operators to correctly and promptly perform the actions necessary to operate the plant or respond to off-normal conditions and accidents, errors committed during test and maintenance, and incorrect actions by other plant staff. Human errors can result in the degradation or failure of a system to perform its function, thereby significantly reducing the effectiveness of one of the layers of defense or one of the fission product barriers. The plant design and operation include defenses to prevent the occurrence of such errors and events. These defenses generally involve the use of procedures, training, and human engineering; however, other considerations (e.g., communication protocols) might also be important.

Response

Sufficient defense against human errors is preserved. Errors committed during testing and maintenance may be reduced by the less frequent performance of the Type A, Type B and Type C tests (less opportunity for errors to occur).

PRA Response:

Sufficient defense against human errors is preserved. The probability of a human error to operate the plant, or to respond to off-normal conditions and accidents is not significantly affected by the change to the Type A testing frequency. Errors committed during testing and maintenance may be reduced by the less frequent performance of the Type A test (less opportunity for errors to occur).

7. Continue to meet the intent of the plants design criteria.

For plants licensed under 10 CFR Part 50 or 10 CFR Part 52, the plants design criteria are set forth in the current licensing basis of the plant. The plants design criteria define minimum requirements that achieve aspects of the defense-in-depth philosophy; as a consequence, even a compromise of the intent of those design criteria can directly result in a significant reduction in the effectiveness of one or more of the layers of defense. When evaluating the effect of the proposed licensing basis change, the licensee should demonstrate that it continues to meet the intent of the plants design criteria.

PRA Response:

The purpose of the proposed change is to extend the testing frequencies of the Type A ILRT from 10 years to 15 years and select Type C LLRTs from 60-months to 75-months. The proposed extensions do not involve either a physical change to the plant or a change in the manner in which the plant is operated or controlled. As part of the proposed change, PVNGS will be required to adopt the performance-based testing standards outlined in NEI 94-01, Revisions 2-A and 3-A, along with ANSI/ANS 56.8-2002. The leakage limits imposed by plant TS remain unchanged when adopting the performance-based testing standards outlined in NEI 94-01, Revision 3-A, and ANSI/ANS 56.8-2002. Plant design limits imposed by the Updated Final Safety Analysis Report (UFSAR) also remain unchanged as a result of the proposed change.

Therefore, the proposed change continues to meet the intent of the plants design criteria to ensure the integrity of the PVNGS containment pressure boundary.

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PRA Response:

The intent of the plants design criteria continues to be met. The extension of the Type A test does not change the configuration of the plant or the way the plant is operated.

==

Conclusion:==

The responses to the seven Defense in Depth questions above conclude that the existing Defense in Depth has not been diminished; rather, in some instances has been increased.

Therefore, the proposed change does not comprise a reduction in safety.

3.5 Non-Risk Based Assessment Consistent with the defense-in-depth philosophy discussed in RG 1.174, PVNGS has assessed other non-risk-based considerations relevant to the proposed amendment. PVNGS has multiple inspection and testing programs that ensure the containment structure continues to remain capable of meeting its design functions and is designed to identify any degrading conditions that might affect that capability. These programs are discussed below.

3.5.1 PVNGS Coatings Program The Coatings Program defines the criteria to ensure coating systems are properly applied and maintained, so the coatings can perform their intended function, and defines the different categories of coatings activities.

Definitions

 Design Basis Accident (DBA) Qualified Coatings Coating systems that are exposed to hypothesized accident conditions that would be present in the Containment structure. The analysis considers the effects of radiation, temperature increase, flooding, pressure increases, and other conditions. The test curve for temperature and pressure must envelope the PVNGS Loss of Cooling Accident (LOCA) curve for temperature and pressure in order for the coatings to be DBA Qualified for PVNGS.

 DBA Unqualified Coatings Coating applications that deviate from the original "DBA Qualified Coatings" tested configurations (for example, surface preparation), and coating applications that have not been tested and accepted as a qualified system, or lacks adequate quality documentation to support its use as a qualified system.

 Safety Related Coatings Coatings applied inside or outside of Containment, the detachment of which could adversely affect the safety function of a safety-related structure, system, or component.

 Service Level I Coating Service Level I coatings are used in areas inside the Reactor Containment where the coating failure could adversely affect the operation of post-accident fluid systems and thereby impair safe shutdown.

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Quality Standards Coatings work performed at PVNGS is performed per the PVNGS Quality Assurance Program.

 Coatings work performed on structures and components for Containment shall be classified as Quality (Q)-Class. Material used for this type of application shall also be Q-Class and DBA qualified for PVNGS.

Procedure, Containment Coatings Condition Assessment, provides requirements and criteria for performance monitoring of Containment Building interior coating systems.

Critical Attributes Quality Assurance measures shall be in place while performing coatings work. Quality Assurance is achieved by monitoring the "Critical Attributes" of coating activity. Critical attributes associated with coatings shall be verified as part of the application process.

Verification of the listed critical attributes combined with the appropriate level of training and qualification for the applicator shall be used to achieve successful and quality coatings applications.

Approved Materials Materials procured for safety-related applications for Containment shall meet the criteria of 10 CFR 50, Domestic Licensing of Production and Utilization Facilities, Appendix B, Quality Assurance Criteria for Nuclear Power Plants and Fuel Reprocessing Plants, and Quality Assurance Program Description (QAPD), Section 4.0, Regulatory Commitment requirements for coating applications. These materials shall be a DBA qualified coating system per PVNGS requirements.

DBA Qualified Coating Systems are single or multiple coatings applied per the tested configuration that complies with the following standards for application documentation requirements:

 ANSI N101.2, Protective Coatings (Paints) for Light Water Nuclear Reactor Containment Facilities, or ASTM D3911, Standard Test Method for Evaluating Coatings Used in Light-Water Nuclear Power Plants at Simulated Design Basis Accident (DBA)

Conditions

 ASTM D4082, Standard Test Methods for Effects of Gamma Radiation on Coatings for Use in Nuclear Power Plants

 ASTM D5139, Standard Specification for Sample Preparation for Qualification Testing of Coatings to be Used in Nuclear Power Plants

 ANSI N101.4, Quality Assurance Programs for Protective Coatings Applied to Nuclear Facilities, or ASTM D3843, Standard Practice for Quality Assurance for Protective Coatings Applied to Nuclear Facilities, (R 2008) 30

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Inspection/Verifications Inspections are an integral part of any coating application project. Inspections are intended to preclude any failure to the coating system. The degree of inspection will vary based on the service environment of the coating.

The Coatings Planner and/or Engineering may choose to impose higher Inspection and Verifications based on the conditions of the work.

The PVNGS Coatings Program shall specify and verify control measures to ensure that inspections and verifications are adequate to achieve the required quality.

The Verification process typically involves a minimum of two individuals, the applicator, and the verifier or an independent inspector. Coating applications that require verifications shall be performed by a qualified applicator and verified by an individual of equivalent qualifications.

Independent inspectors shall be qualified per one of the following:

 A certified coatings inspection program

 QAPD, Section 2.2.6, Personnel Training and Qualifications

 QAPD, Section 2.2.7, NQA-1 Commitment/Exceptions Performance Monitoring Coatings systems that have been in service in Safety Related areas shall be monitored to determine if degradation to coatings is present. Currently there are several programs to assure that monitoring and corrective actions are in place.

 Inservice Inspections

 Containment Coatings Condition Assessment Containment building interior coating system assessments shall be performed in accordance with the Containment Coatings Condition Assessment procedure every operating cycle.

Coatings applications for Containment are required to meet the DBA Qualified Coating Systems specified for PVNGS. DBA Qualified Coating applications that deviate from these requirements are considered DBA Unqualified Coatings.

Unqualified/Degraded Coatings in Containment The PVNGS Coatings Program requires the amount of degraded and unqualified coatings within containment to be maintained against a margin of 0.15ft3.

The results of the most recent coatings inspections for PVNGS Units 1, 2, and 3 are as follows:

Unit 1, including the Unit 1 Spring of 2019 refueling outage (1R21) , the current amount of degraded and unqualified coatings reported in the Unqualified Coatings Log is 0.0085 ft3.

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Unit 2, including the Unit 2 Spring of 2020 refueling outage (2R22), the current amount of degraded and unqualified coatings reported in the Unqualified Coatings Log is 0.05186 ft3.

Unit 3, including the Unit 3 Fall of 2019 refueling outage (3R21), the current amount of degraded and unqualified coatings reported in the Unqualified Coatings Log is 0.0291 ft3.

3.5.2 PVNGS Examination Program for Subsection IWE This examination program:

 Supports the implementation of the containment inservice examinations required by ASME Section XI, Subsection IWE (Reference 38) as modified and supplemented by the requirements in 10 CFR 50.55a(b)(2)(ix);

 Is generated and controlled in accordance with the requirements of the ASME Section XI Inservice Inspection (ISI) program;

 Contains a detailed description of the incorporation of Subsection IWE into the ISI Program for PVNGS Units 1, 2, and 3; and,

 Conforms to the requirements of 10 CFR 50.55a(b)(2), PVNGS TS, and the PVNGS UFSAR.

The Design Code edition and addenda are the ASME Section III, Division 1, 1974 Edition and Addenda through Winter 1974, as referenced in the UFSAR, Section 3.8.1.2.2, Codes and Standard Specifications.

Code Applicability For the 2nd 10-Year Interval, the 2001 Edition through 2003 Addenda of Subsection IWE was referenced as the Code to utilize for preparation of this program.

For the 3rd 10-Year Interval, this examination program complies with the ASME Section XI, 2007 Edition with the 2008 Addenda and the 2013 Edition, Subsection IWE as modified and supplemented by the requirements in 10 CFR 50.55a(b).

This program shall be updated for each inspection interval to conform with the requirements of the latest edition and addenda of the ASME Section XI Code referenced in paragraph (b) of 10 CFR 50.55a.

If a Code required examination is identified to be impractical during the course of an examination and the Code required percentages are not met, a request for relief shall be prepared and submitted in agreement with the ASME Section XI Inservice Inspection program, but no later than 12 months after expiration of the Interval. There are no requests for relief identified.

Scope This Examination Program includes all applicable nondestructive examinations (NDE) required by ASME Section XI, Subsection IWE, as modified and supplemented by 10 CFR 50.55a, as identified below:

 Examination of metal containments and the liners of concrete containments.

 Special examinations to satisfy other commitments or concerns that are based on operating experiences (e.g., USNRC Circulars, Information Notices, Bulletins, 32

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Combustion Engineering Bulletins, INPO Reports, etc.). These examinations are scheduled throughout this program and reference the applicable notification documents, when applicable. No special examinations are currently identified.

Inspection Intervals The 2nd 10-Year Examination Program was prepared in accordance with Program B of IWE-2412. The 3rd 10-Year Examination Program was prepared in accordance with IWE-2411.

The 2nd, 3rd and 4th 10-Year Intervals and corresponding inspection periods are defined in Table 3.5.2-1.

Table 3.5.2-1, PVNGS IWE Examination Program Inspection Intervals Unit 1 Unit 2 Unit 3 Second Inspection 07/18/08 to 03/18/07 to 01/11/08 to Interval 07/17/18 03/17/17 01/10/18 Period One 07/18/08 to 03/18/07 to 01/11/08 to 11/17/11 07/17/10 05/10/11 Period Two 11/18/11 to 07/18/10 to 05/11/11 to 03/17/15 11/17/13 09/10/14 Period Three 03/18/15 to 11/18/13 to 09/11/14 to 07/17/18 03/17/17 01/10/18 Third Inspection 07/18/18 to 03/18/17 to 01/11/18 to Interval 07/17/28 03/17/27 01/10/28 Period One1 07/18/18 to 03/18/17 to 01/11/18 to 07/17/21 03/17/20 01/10/21 Period Two 07/18/21 to 03/18/20 to 01/11/21 to 07/17/25 03/17/24 01/10/25 Period Three 07/18/25 to 03/18/24 to 01/11/25 to 07/17/28 03/17/27 01/10/28 Fourth Inspection 07/18/28 to 03/18/27 to 01/11/28 to Interval2 07/17/38 03/17/37 01/10/38 Period One 07/18/28 to 03/18/27 to 01/11/28 to 07/17/31 03/17/30 01/10/31 Period Two 07/18/31 to 03/18/30 to 01/11/31 to 07/17/35 03/17/34 01/10/35 Period Three 07/18/35 to 03/18/34 to 01/11/35 to 07/17/38 03/17/37 01/10/38 Note 1: The intervals/periods may change to allow for extended outage durations per IWA-2400 of ASME Section XI.

Note 2: The schedule for the 4th 10-year interval is proposed as the 4th interval plan has yet to be developed.

Examination Categories The examination categories of ASME Section XI were utilized to develop this program. The Subprogram summary tables are contained in Tables 3.5.2-2 and 3.5.2-3 and are organized by examination categories applicable to PVNGS. For each examination category, these tables 33

Enclosure Evaluation of the Proposed Change



identify the identification, description, nondestructive examination method, total number of items, required examination amount for each inspection period, and running percentage.

Examination The examinations performed during the first period of the first inspection interval shall serve the same purpose as the preservice examinations (PSE).

All items that are scheduled for examination shall be examined to the extent practical. In addition, any Code limitations that are noted during the examinations shall be documented in the summary reports that are prepared after each outage. And, if relief is required from any of these examinations, a Request for Relief shall be submitted in a timely manner in agreement with the ASME Section XI Inservice Inspection program.

All examiners shall be qualified in accordance with the requirements of ASME Section XI, 2001 Edition through 2003 Addenda as modified by 10 CFR 50.55a(b)(2)(ix)(F). All examinations shall be performed in accordance with approved NDE procedures.

As required and modified by 10 CFR 50.55a (b)(2)(ix)(G), the general visual required by Table IWE 2500-1, Item E1.11, shall be performed once each period.

Accessibility The General Visual Examination required by Examination Category E-A, Item No. E1.11, shall be performed on those accessible surface areas that are visually accessible by line of sight with adequate lighting from permanent vantage points with or without the use of telescopes, binoculars, or other similar equipment.

Disassembly of plant systems, structures, or components to allow visual access for the purpose of the General Visual Examination required by Examination Category E-A, Item No.

E1.11 is not required. Those areas are defined as inaccessible.

Examination Methods The following examination methods are utilized to perform Inservice Inspections, along with the actual NDE technique:

 Visual -

General Visual (PVNGS requires a VT-3 Certification to perform these examinations)

VT-1 VT-3

 VOL - Volumetric

 UT - Ultrasonic The above NDE shall be performed using specific methods and procedures that are identified in ASME Section XI as modified by 10 CFR 50.55a, or alternative examinations that are demonstrated to be equivalent or superior to those identified.

As allowed by 10 CFR 50.55a (b)(2)(ix)(B), when performing remotely the visual examinations required by Subsection IWE, the maximum direct examination distance specified in Table IWA-2211-1 may be extended and the minimum illumination requirements specified in Table IWA-2211-1 may be decreased provided that the conditions or indications 34

Enclosure Evaluation of the Proposed Change



for which the visual examination is performed can be detected at the chosen distance and illumination.

As required by IWE-3510, the visual examination acceptance criteria is defined in the PVNGS procedure, Visual Examination of Metal Containment Building Surfaces.

Evaluation and Repair The evaluation of all examination results shall be performed in accordance with ASME Section XI, Articles IWA-3000 and IWE-3000. In addition, all applicable repairs and replacements shall be performed in accordance with ASME Section XI Article IWA-4000. Pressure tests shall be performed on welded and mechanical joint repairs or replacements, in accordance with IWA-4000 and IWE-5000. Both the evaluations and repair or replacement shall be performed in accordance with the 2013 Edition of ASME Section XI.

Acceptability of Inaccessible Areas As required for metal containment (MC) examinations by 10 CFR 50.55a(b)(2)(ix)(A), for Class MC applications, an evaluation of the acceptability of inaccessible areas shall be completed whenever conditions exist in accessible areas that could indicate the presence of or result in degradation to such inaccessible areas. For each inaccessible area identified, the following information shall be provided in the ISI Summary Report as required by IWA-6000:

 A description of the type and estimated extent of degradation, and the conditions that led to the degradation;

 An evaluation of each area, and the result of the evaluation, and;

 A description of necessary corrective actions.

Additional Examinations Supplemental examinations, when required shall be in accordance with IWE-3000.

Augmented Examinations The Augmented Examination Areas/Locations Index shall provide a list of areas/locations that are designated as augmented in accordance with the requirements of IWE-1240 and IWE-2420.

Currently, the following Augmented Examination Areas have been identified.

NUMBER DESCRIPTION 1MWCEU60 & 61 E4.11 Owner elected VT1 examination for corrosion or pitting inside penetrations.

2MWCEU60 & 61 E4.11 Owner elected VT1 examination for corrosion or pitting inside penetrations.

3MWCEU60 & 61 E4.11 Owner elected VT1 examination for corrosion or pitting inside penetrations.

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Limitations and Modifications Ensure that each revision to this program manual is reviewed for impact to the PVNGS Aging Management Program Evaluation Report, ASME Section XI Inservice Inspection, Sections IWE-B2.1.27 NUREG 1801 Program XI.S1.

Relief Requests There are no requests for relief identified.

Code Case ASME Section XI Code Case acceptability shall be based on RG 1.147. There are no Code Cases identified for use.

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Table 3.5.2-2, PVNGS Third Interval Examination Summary ASME Zone- Identification Description NDE Total Examination Inspection Running Remarks and Item Component or Line No. or Method Items Amount Period  % Relief Requests No. System Serial No.

Examination Category E-A:

Containment Surfaces E1.10 Containment Vessel Pressure Retaining Boundary E1.11 201, 202, 203, Accessible Containment General 1 100% One 100%

204, 205 & 206 Surface Areas Vessel 100% Two 100%

100% Three 100%

E1.12 202 Wetted Containment VT-3 1 0 One 0 Surfaces of Vessel 0 Two 0 Submerged 100% Three 100%

Areas E1.20 BWR Vent Not applicable Containment N/A N/A N/A N/A N/A N/A to PVNGS System to PWRs Vessel Accessible Surface Areas E1.30 Moisture Accessible Leak Chase General 1 100% Three 100% Owner Elected Barriers portions of the test risers, examinations.

leak chase couplings, channel and plugs system inside containment 37

Enclosure Evaluation of the Proposed Change



Table 3.5.2-2, PVNGS Third Interval Examination Summary ASME Zone- Identification Description NDE Total Examination Inspection Running Remarks and Item Component or Line No. or Method Items Amount Period  % Relief Requests No. System Serial No.

Examination Category E-C:

Containment Surfaces Requiring Augmented Examination E4.10 Containment Surface Areas E4.11 201, 202, 203, Visible metal Liner Plate VT-1 0 100% of area* One 100% *Owner Elected 204, 205 & 206 surfaces, 100% of area* Two 100% examinations; 100% of area* Three 100% see Augmented Examinations above.

E4.12 Surface Area Surface area Liner Plate Ultrasonic 0 100% of area** One 100% **There are no Grid, grid Thickness 100% of area** Two 100% areas currently Minimum Wall 100% of area** Three 100% identified, Thickness subject to Item Location E4.12.

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Table 3.5.2-3, PVNGS Third Interval Examination Summary ASME Zone- Identification Description NDE Total Examination Inspection Running Remarks and Item Component or Line No. or Method Items Amount Period  % Relief No. System Serial No. Requests Examination Category E-G:

Pressure Retaining Bolting E8.10 CBD-6, 7, 10, Bolts, studs, Penetrations VT-1 96 0% of area* One 0 *Examine 11, 13, and 14 nuts, locations 0% of area* Two 0 whenever bushings, 100% of area* Three 100% disassembled washers, and threads in base metal, and flange ligaments 39

Enclosure Evaluation of the Proposed Change



3.5.3 PVNGS Examination Program for Subsection IWL This examination program plan:

 Is issued to support the second (2nd) interval implementation of the containment inservice examinations required by ASME Section XI, Subsection IWL (Reference 39) as modified and supplemented by the requirements in 10 CFR 50.55a(b)(2)(viii);

 Is generated and controlled in accordance with the ASME Section XI Inservice Inspection procedure;

 Contains a detailed description of the incorporation of Subsection IWL into the concrete containment (CC) exterior surfaces Inservice Inspection (ISI) Program for PVNGS Units 1, 2, and 3, and,

 Conforms to the requirements of 10 CFR 50.55a(b)(2), PVNGS TS, and the PVNGS UFSAR.

There are no examination exceptions documented in this examination program plan.

The ISI of the containment tendon post-tensioning system shall be performed per the unit specific Tendon Integrity surveillance test. The criteria and details described in Subsection IWL are incorporated into the Tendon Integrity surveillance test. The unit specific surveillance test conforms to the requirements of 10 CFR 50.55a (b)(2), PVNGS TS, and the PVNGS UFSAR.

This IWL Inservice Inspection Program and the Tendon Integrity surveillance test complies with the ASME Section XI, 2007 Edition with the 2008 Addenda, Subsection IWL as modified and supplemented by the requirements in 10 CFR 50.55a(b)(2)(viii).

General This program establishes the ISI program plan and schedule for the ten-year examination interval of the PVNGS Units 1, 2, and 3 concrete containment. This program plan identifies the Class CC items that are subject to inspection, as set forth in the 2007 Edition with the 2008 Addenda of ASME Section XI, within the limitations and modifications required by 10 CFR 50.55a.

Where an examination required by Section XI has been determined to be impractical, the basis for this determination has been documented and approved by the NRC as a request for relief as permitted in 10 CRF 50.55a(g)(5)(iii), (iv), (6)(i).

Additional examinations that have been included in the program, if any, due to further regulatory requirements, self-imposed licensee requirements, or industry recommendations, are introduced and discussed below.

Responsibilities APS, as Owner, has overall responsibility for the conduct of the ISI program to assure compliance with the ASME Section XI Code, including Sub-article IWA-1400, entitled "Owners Responsibilities." The Inservice Inspection Section Leader has the responsibility for the concrete containment program plan, including preparation, revisions, implementation, scheduling, examinations, surveillance test, repairs, and replacements.

The Civil Design Section Leader has the responsibility for the evaluation of conditions identified as unacceptable (Tier 3 Conditions).

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Program Scope, Exceptions, and Exclusions The scope of this program is limited to that portion of the ISI program that addresses ASME Class CC components, including all associated areas and items as required by ASME Section XI and the additional requirements. This examination program includes all applicable examinations required by Subsection IWL of the ASME Section XI Code, as modified and supplemented by 10 CFR 50.55a, as identified below:

 Examination of the accessible concrete containment exterior surfaces, buttress, exterior penetrations, personnel and equipment hatches, and tendon grease caps.

NOTE: Examination of the tendon post-tensioning system shall be performed per the unit specific Tendon Integrity surveillance test. All applicable criteria, details, and requirements described in Subsection IWL of the ASME Section XI Code, and as modified and supplemented by 10 CFR 50.55a are incorporated into the unit specific Tendon Integrity surveillance test.

 Expedited examination of the concrete containment.

 Special examinations to satisfy other commitments or concerns that are based on operating experiences (e.g., USNRC Circulars, INs, Bulletins, Combustion Engineering Bulletins, INPO Reports, etc.). These examinations are scheduled throughout this program and reference the applicable notification documents, when applicable. No special examinations are currently identified.

Applicable ASME Code Edition and Addenda Pursuant to 10 CFR 50.55a(b)(2) and 10 CFR 50.55a(b)(2)(viii), the requirements applicable to the inspection of the concrete containment are based on the rules set forth in the 2007 Edition of ASME Section XI with the 2008 Addenda for Subsections IWA and IWL as modified and clarified by 10 CFR50.55a(b)(2)(viii)(E).

Applicable ASME Section XI Code Cases ASME Section XI Code Cases either clarify the intent of the Code or provide alternatives to Section XI Code requirements. The NRC approves the usage and/or takes exceptions to specific Code Cases in RG 1.147, Inservice Inspection Code Case Acceptability, ASME Section XI, Division 1 (Reference 22). The applications of Code Cases are further governed by Section XI, IWA-2440. Code Cases that are not authorized for use in RG 1.147 are not implemented unless specifically approved by the NRC in the form of a Relief Request.

No ASME Section XI Code Cases have been incorporated into the Program.

Applicable ASME Section XI Code Interpretations No ASME Section XI Code Interpretations have been incorporated into the Program.

Additional Examination Requirements Additional examinations have not been included in the program.

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Exemptions, Examination Categories, and Item Numbers The exemptions as permitted in ASME Section XI, Subsection IWL-1220, were applied to the inservice inspection boundaries discussed above and thus the exempt containment items are not included in the program plan tables or drawings. The areas and items identified on the program drawings indicate those items that are subject to examination. The examination categories identified in Section XI, Table IWL-2500-1, specifically indicate the items (parts) that are "required" to be examined by type, location, percentage, etc., each with a unique examination category item number. Items not requiring examination per the examination categories, due to type, location, percentage, etc., are "excluded" from examination. Examination areas and items that are scheduled for examination represents those items that have been selected for examination as required by Section XI.

Inspection Interval

1. For concrete examinations, during the previous (first) ten-year inspection interval, relief from the inservice inspection schedule described in the 1992 Edition and Addenda of Section XI, Subsection IWL-2410(a), had been authorized via Relief Request RR-L3. A Baseline Examination and a subsequent examination (5-years after the Baseline Examination) had been performed.

During this second ten-year inspection interval, PVNGS shall perform an inspection of the accessible concrete containment exterior surfaces and buttress per the requirements described in the 2007 Edition with the 2008 Addenda of ASME,Section XI, Subsection IWL-2410. The inspection period for Subsection IWL is a five-year period in which the inspections will be performed during plant normal operating conditions. The first inspection (Baseline Examination) of concrete containment exterior surfaces was completed on September 4, 2001. The date of the first examination (Baseline Examination) of concrete shall be used to determine the schedule date of all subsequent examinations within the 5-year examination periods of this (second) 10-year interval.

Examinations of the accessible concrete containment exterior surfaces and buttress shall be performed per the following schedules:

Unit 1

 Prior to September 9, 2001 (Baseline Examination, completed September 4, 2001)

 Between September 4, 2005 and September 4, 2007, 5th year Examination (completed March 29, 2007)

 Between September 4, 2010 and September 4, 2012, 10th year Examination (completed August 17, 2012)

 Between September 4, 2015 and September 4, 2017, 15th year Examination (completed September 1, 2017)

 Between September 4, 2020 and September 4, 2022, 20th year Examination 42

Enclosure Evaluation of the Proposed Change



Unit 2

 Prior to September 9, 2001 (Baseline Examination, completed September 6, 2001)

 Between September 6, 2010 and September 6, 2012, 10th year Examination (completed September 5, 2012)

 Between September 6, 2015 and September 6, 2017, 15th year Examination (completed August 31, 2017)

 Between September 6, 2020 and September 6, 2022, 20th year Examination Unit 3

 Prior to September 9, 2001 (Baseline Examination, completed September 7, 2001)

 Between September 7, 2010 and September 7, 2012, 10th year Examination (completed September 5, 2012)

 Between September 7, 2015 and September 7, 2017, 15th year Examination (completed August 31, 2017)

 Between September 7, 2020 and September 7, 2022, 20th year Examination

2. PVNGS is in compliance with the conditions described in IWL-2421(a). At PVNGS, the three concrete containments utilize the same pre-stressing system and are identical in design. The post-tensioning operation for each subsequent containment was completed within 2 years of each other. All three concrete containment structures are similarly exposed to and protected from the outside.

For Unit 1 (the containment structure with the first Structural Integrity Test, SIT), all examinations required by IWL-2500 shall be performed at 1, 3, 10 years and every 10 years thereafter. Only the examinations required by IWL-2524 and IWL-2525 need be performed at 5 and 15 years and every 10 years thereafter. Examinations on the containment post-tension system shall be performed per the following schedule:

 Physical and Visual Examination - Between December 25, 2011 and December 25, 2013, 30th year surveillance test (SIT + 30 years) (completed April 8, 2013)

 Visual Examination Only - Between December 25, 2016 and December 25, 2018, 35th year surveillance test (SIT + 30 years) (completed September 13, 2017)

 Physical and Visual Examination - Between December 25, 2021 and December 25, 2023, 40th year surveillance test (SIT + 40 years)

For Unit 2 (the containment structure with the second Structural Integrity Test, SIT),

all examinations required by IWL-2500 shall be performed at 1, 5, 15 years and every 10 years thereafter. Only the examinations required by IWL-2524 and IWL-2525 need be performed at 3 and 10 years and every 10 years thereafter.

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Examinations of the containment post-tensioning system shall be performed per the following schedule:

 Visual Examination Only - Between February 8, 2014 and February 8, 2016, 30th year surveillance test (SIT + 30 years) (completed April 14, 2015)

 Physical and Visual Examination - Between February 8, 2019 and February 8, 2021, 35th year surveillance test (SIT + 35 years)

 Visual Examination Only - Between February 8, 2024 and February 8, 2026, 40th year surveillance test (SIT + 40 years)

For Unit 3 (the containment structure with the third Structural Integrity Test, SIT),

all examinations required by IWL-2500 shall be performed at 1, 5, 15 years and every 10 years thereafter. Only the examinations required by IWL-2524 and IWL-2525 need be performed at 3 and 10 years and every 10 years thereafter.

Examinations of the containment post-tensioning system shall be performed per the following schedule:

 Physical and Visual Examination - Between September 16, 2010 and September 16, 2012, 25th year surveillance test (SIT + 25 years) (completed August 30, 2012)

 Visual Examination Only - Between September 16, 2015 and September 16, 2017, 30th year surveillance test (SIT + 30 years) (completed October 25, 2016)

 Physical and Visual Examination Only - Between September 16, 2020 and September 16, 2022, 35th year surveillance test (SIT + 35 years)

 Visual Examination Only - Between September 16, 2025 and September 16, 2027, 40th year surveillance test (SIT + 40 years)

3. PVNGS Units 1, 2, and 3 Inspection Intervals and Examination Dates are also described in Tables 3.5.3-1, 3.5.3-2 and 3.5.3-3.

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Table 3.5.3-1, PVNGS Unit 1 IWL Inspection Intervals and Examination Dates Inspection Inspection Period Tendon Integrity Examination Dates Containment Exterior Concrete Surface Interval (See Note 1) Examination Dates First 5-yr Period th 20 -year Exam.

ONE (1) Baseline Exam.: Prior to Sept 9, 2001 Sept. 9, 2001 Between Dec. 25, 2001 and Dec. 25, 2003 (Examination Completed: Sept. 4, 2001) thru Sept. 8, 2006 (Examination Completed: See Note 2)

Sept. 9, 2001 through Second 5-yr Period 25th-year Exam. 5th-year Exam.

July 31, 2011 Sept. 9, 2006 Between Dec. 25, 2006 and Dec. 25, 2008 Between Sept. 4, 2005 and Sept. 4, 2007 thru July 31, 2011 (Examination Completed: Dec. 16, 2008) (Examination Completed: Mar. 29, 2007)

First 5-yr Period 30th-year Exam. (Physical & Visual) 10th-year Exam.

TWO (2) Aug. 1, 2011 Between Dec. 25, 2011 and Dec. 25, 2013 Between Sept. 4, 2010 and Sept. 4, 2012 thru July 31, 2016 (Examination Completed: Apr. 8, 2013) (Examination Completed: Aug. 17, 2012)

Aug. 1, 2011 through Second 5-yr Period 35th-year Exam. (Visual Only) 15th-year Exam.

July 31, 2021 Aug. 1, 2016 Between Dec. 25, 2016 and Dec. 25, 2018 Between Sept. 4, 2015 and Sept. 4, 2017 thru July 31, 2021 (Examination Completed: Sept. 13, 2017) (Examination Completed: Sept. 1, 2017)

First 5-yr Period THREE (3) Aug. 1, 2021 40th-year Exam. (Physical & Visual) 20th-year Exam.

Between Dec. 25, 2021 and Dec. 25, 2023 Between Sept. 4, 2020 and Sept. 4, 2022 thru July 31, 2026 Aug. 1, 2021 through Second 5-yr Period 45th-year Examination (Visual Only) 25th-year Exam.

July 31, 2031 Aug. 1, 2026 Between Dec. 25, 2026 and Dec. 25, 2028 Between Sept. 4, 2025 and Sept. 4, 2027 thru July 31, 2031 45

Enclosure Evaluation of the Proposed Change



Table 3.5.3-1, PVNGS Unit 1 IWL Inspection Intervals and Examination Dates Inspection Inspection Period Tendon Integrity Examination Dates Containment Exterior Concrete Surface Interval (See Note 1) Examination Dates First 5-yr Period Four (4) Aug. 1, 2031 50th-year Exam. (Physical & Visual) 30th-year Exam.

Between Dec. 25, 2031 and Dec. 25, 2033 Between Sept. 4, 2030 and Sept. 4, 2032 thru July 31, 2036 Aug. 1, 2031 through Second 5-yr Period 55th-year Exam. (Visual Only) 35th-year Exam.

July 31, 2041 Aug. 1, 2036 Between Dec. 25, 2036 and Dec. 25, 2038 Between Sept. 4, 2035 and Sept. 4, 2037 thru July 31, 2041 First 5-yr Period Five (5) 60th-year Exam. (Physical & Visual) 40th-year Exam.

Aug. 1, 2041 Between Dec. 25, 2041 and Dec. 25, 2043 Between Sept. 4, 2040 and Sept. 4, 2042 thru July 31, 2046 Aug. 1, 2041 through Second 5-yr Period Aug. 1, 2046 65th-year Exam. (Visual Only) 45th-year Exam.

July 31, 2051 Between Dec. 25, 2046 and Dec. 25, 2048 Between Sept. 4, 2045 and Sept. 4, 2047 thru July 31, 2051 1. For Tendon Integrity examinations, the Structural Integrity Test (SIT) date (December 25, 1982) is used as the base date to establish the five (5) year frequency of examinations.

2. Relief from the performance of the 20th-year examination was granted by the NRC via Relief Request RR-L4 (April 14, 2000).

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Table 3.5.3-2, PVNGS Unit 2 IWL Inspection Intervals and Examination Dates Inspection Inspection Period Tendon Integrity Examination Dates Containment Exterior Concrete Surface Interval (See Note 1) Examination Dates First 5-yr Period th 20 -year Exam.

ONE (1) Sept. 9, 2001 Baseline Exam.: Prior to Sept 9, 2001 Between Feb. 8, 2004 and Feb. 8, 2006 thru Sept. 8, 2006 (Examination Completed: Sept. 6, 2001)

(Examination Completed: Jan. 26, 2006)

Sept. 9, 2001 through Second 5-yr Period 25th-year Exam. 5th-year Exam.

July 31, 2011 Sept. 9, 2006 Between Feb. 8, 2009 and Feb. 8, 2011 Between Sept. 6, 2005 and Sept. 6, 2007 thru July 31, 2011 (Examination Completed: Feb. 3, 2010) (Examination Completed: See Note 2)

First 5-yr Period 30th-year Exam. (Visual Only) 10th-year Exam.

TWO (2) Aug. 1, 2011 Between Feb. 8, 2014 and Feb. 8, 2016 Between Sept. 6, 2010 and Sept. 6, 2012 thru July 31, 2016 (Examination Completed: Apr. 14, 2015) (Examination Completed: Sept. 05, 2012)

Aug. 1, 2011 through Second 5-yr Period 15th-year Exam.

Aug. 1, 2016 35th-year Exam. (Physical & Visual)

July 31, 2021 Between Sept. 6, 2015 and Sept. 6, 2017 Between Feb. 8, 2019 and Feb. 8, 2021 thru July 31, 2021 (Examination Completed: August 31, 2017)

First 5-yr Period THREE (3) Aug. 1, 2021 40th-year Exam. (Visual Only) 20th-year Exam.

Between Feb. 8, 2024 and Feb. 8, 2026 Between Sept. 6, 2020 and Sept. 6, 2022 thru July 31, 2026 Aug. 1, 2021 through Second 5-yr Period 45th-year Exam. (Physical & Visual) 25th-year Exam.

July 31, 2031 Aug. 1, 2026 Between Feb. 8, 2029 and Feb. 8, 2031 Between Sept. 6, 2025 and Sept. 6, 2027 thru July 31, 2031 47

Enclosure Evaluation of the Proposed Change



Table 3.5.3-2, PVNGS Unit 2 IWL Inspection Intervals and Examination Dates Inspection Inspection Period Tendon Integrity Examination Dates Containment Exterior Concrete Surface Interval (See Note 1) Examination Dates First 5-yr Period FOUR (4) Aug. 1, 2031 50th-year Exam. (Visual Only) 30th-year Exam.

thru July 31, 2036 Between Feb. 8, 2034 and Feb. 8, 2036 Between Sept. 6, 2030 and Sept. 6, 2032 Aug. 1, 2031 Second 5-yr Period through 55th-year Exam. (Physical & Visual) 35th-year Exam.

Aug. 1, 2036 July 31, 2041 Between Feb. 8, 2039 and Feb. 8, 2041 Between Sept. 6, 2035 and Sept. 6, 2037 thru July 31, 2041 First 5-yr Period FIVE (5) 60th-year Exam. (Visual Only) 40th-year Exam.

Aug. 1, 2041 Between Feb. 8, 2044 and Feb. 8, 2046 Between Sept. 6, 2040 and Sept. 6, 2042 thru July 31, 2046 Aug. 1, 2041 through Second 5-yr Period Aug. 1, 2046 65th-year Exam. (Physical & Visual) 45th-year Exam.

July 31, 2051 Between Feb. 8, 2049 and Feb. 8, 2051 Between Sept. 6, 2045 and Sept. 6, 2047 thru July 31, 2051 1. For Tendon Integrity examinations, the Structural Integrity Test (SIT) date (February 8, 1985) is used as the base date to establish the five (5) year frequency of examinations.

2. Relief from the performance of the 5th-year examination was granted by the NRC via Relief Request RR-L3 (April 14, 2000).

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Enclosure Evaluation of the Proposed Change



Table 3.5.3-3, PVNGS Unit 3 IWL Inspection Intervals and Examination Dates Inspection Inspection Period Tendon Integrity Examination Dates Containment Exterior Concrete Surface Interval (See Note 1) Examination Dates First 5-yr Period th 15 -year Exam.

ONE (1) Sept. 9, 2001 Baseline Exam.: Prior to Sept 9, 2001 Between Sept. 16, 2000 and Sept. 16, 2002 thru Sept. 08, 2006 (Examination Completed: Sept. 7, 2001)

(Examination Completed: Sept. 13, 2002)

Sept. 9, 2001 through Second 5-yr Period 20th-year Exam. 5th-year Exam.

July 31, 2011 Sept. 9, 2006 Between Sept. 16, 2005 and Sept. 16, 2007 Between Sept. 7, 2005 and Sept. 7, 2007 thru July 31, 2011 (Examination Completed: See Note 3) (Examination Completed: See Note 2)

First 5-yr Period 25th-year Exam. (Physical & Visual) 10th-year Exam.

TWO (2) Aug. 1, 2011 Between Sept. 16, 2010 and Sept. 16, 2012 Between Sept. 7, 2010 and Sept. 7, 2012 thru July 31, 2016 (Examination Completed: Aug. 30, 2012) (Examination Completed: Sept. 5, 2012)

Aug. 1, 2011 Second 5-yr Period 30th-year Exam. (Visual Only) 15th-year Exam.

through July 31, 2021 Aug. 1, 2016 thru Between Sept. 16, 2015 and Sept. 16, 2017 Between Sept. 7, 2015 and Sept. 7, 2017 July 31, 2021 (Examination Completed: Oct. 25, 2016) (Examination Completed: August 31, 2017)

First 5-yr Period THREE (3) 35th-year Exam. (Physical & Visual) 20th-year Exam.

Aug. 1, 2021 thru Between Sept. 16, 2020 and Sept. 16, 2022 Between Sept. 7, 2020 and Sept. 7, 2022 July 31, 2026 Aug. 1, 2021 Second 5-yr Period through 40th-year Exam. (Visual Only) 25th-year Exam.

July 31, 2031 Aug. 1, 2026 Between Sept. 16, 2025 and Sept. 16, 2027 Between Sept. 7, 2025 and Sept. 7, 2027 thru July 31, 2031 49

Enclosure Evaluation of the Proposed Change



Table 3.5.3-3, PVNGS Unit 3 IWL Inspection Intervals and Examination Dates Inspection Inspection Period Tendon Integrity Examination Dates Containment Exterior Concrete Surface Interval (See Note 1) Examination Dates First 5-yr Period FOUR (4) 45th-year Exam. (Physical & Visual) 30th-year Exam.

Aug. 1, 2031 Between Sept. 16, 2030 and Sept. 16, 2032 Between Sept. 7, 2030 and Sept. 7, 2032 thru July 31, 2036 Aug. 1, 2031 Second 5-yr Period through 50th-year Exam. (Visual Only) 35th-year Exam.

Aug. 1, 2036 July 31, 2041 Between Sept. 16, 2035 and Sept. 16, 2037 Between Sept. 7, 2035 and Sept. 7, 2037 thru July 31, 2041 First 5-yr Period FIVE (5) 55th-year Exam. (Physical & Visual) 40th-year Exam.

Aug. 1, 2041 Between Sept. 16, 2040 and Sept. 16, 2042 Between Sept. 7, 2040 and Sept. 7, 2042 thru July 31, 2046 Aug. 1, 2041 Second 5-yr Period through 60th-year Exam. (Visual Only) 45th-year Exam.

July 31, 2051 Aug. 1, 2046 Between Sept. 16, 2045 and Sept. 16, 2047 Between Sept. 7, 2045 and Sept. 7, 2047 thru July 31, 2051 1. For Tendon Integrity examinations, the Structural Integrity Test (SIT) date (Sept. 16, 1986) is used as the base date to establish the five (5)-year frequency of examinations.

2. Relief from the performance of the 5th-year examination was granted by the NRC via Relief Request RR-L3 (April 14, 2000).

3. Relief from the performance of the 20th-year examination was granted by the NRC via Relief Request RR-L4 (April 14, 2000).

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Personnel Qualification and Certification Personnel performing Section XI nondestructive examinations are qualified and certified in accordance with ANSI/ASNT CP-189 (1991) as required by IWA-2300 and amended by the requirements of Section XI, Division 1. Personnel performing general or detailed visual examinations shall be qualified by satisfying the requirements described in IWL-2320 and approved by the Responsible Engineer (Registered Professional Engineer). Implementation and control of the qualification and certification activities are within the jurisdiction of the Engineering Inspections group or Program Engineering Department.

Relief Request Alternatives or deviations from Section XI Code requirements are permitted in 10CFR50.55a(a)(3), but only if the NRC has previously approved them. Such alternatives are documented in the form of a Relief Request, which provides a description, basis, and proposed alternative for the request. The approved Relief Request is listed below.

Relief Request 66 dated November 5, 2020 (Reference 36)

Description:

Pursuant to 10 CFR 50.55a(z)(2), APS hereby requests NRC approval of Relief Request 66 regarding the interval between containment tendon inspections as specified per Paragraph IWL-2420 of the ASME BPV Code,Section XI, Subsection IWL, Reference 1. Relief is requested on the basis that compliance with the Code specified inspection interval during the COVID-19 pandemic would result in hardship without a compensating increase in the level of quality and safety. Due to the hardship caused by potential spread of COVID-19 to PVNGS personnel and the surrounding community as well as the travel restrictions and quarantine requirements affecting outside contractors. APS is proposing a one-time, one-year extension of the Containment Post-Tensioning System Inspection period to allow time to safely and effectively accomplish the inspection.

The duration of the proposed alternative would extend from the current February 8, 2021 deadline for performing the Unit 2, 35th year IWL Containment Post-Tensioning System Inspection until February 8, 2022.

Approval:

By teleconference call on November 19, 2020, the NRC authorized the use of the proposed alternative at PVNGS, Unit 2, to extend from the current February 8, 2021, deadline for performing the Unit 2, 35th year IWL Containment Post-Tensioning System Inspection until February 8, 2022.

All other requirements in ASME Code,Section XI for which relief was not specifically requested and approved in this relief request remain applicable, including third-party review by the Authorized Nuclear Inservice Inspector. (Reference 40)

Program Implementation The Inservice Inspections Engineering Section Leader has the responsibility to identify the program examinations that are to be performed during each five-year inspection 51

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period, including the prerequisites. Inservice Inspections Engineering also has the responsibility for directing and performing all examination related activities. These activities are controlled and include planning, scheduling, coordinating, procedure development, providing personnel and equipment, performing examinations, tracking, evaluating indications, reporting, etc. Examinations are generally performed during normal plant operations. APS personnel, APS agents, or their contractors will perform examinations.

Alternative, Successive, and Additional Examinations Alternative examination methods, if necessary, will be substituted for the methods specified in the program in accordance with Section XI, Paragraph IWA-2240.

Successive examinations for areas and items includes repeating the sequence of examinations from previous five-year periods to the extent practical, in accordance with IWA-2110(a)(1)(i) and reexamining any items in the next period(s) in accordance with IWA-2110(a)(1)(i), which exhibit conditions that are evaluated and found to be acceptable for continued service.

ASME Section XI Exemptions and Requirements ASME Section XI, Subsection IWA ASME Section XI, Subsection IWA, General Requirements, includes the rules and requirements that are applicable to all subsections of Section XI, including IWL.

Subsection IWA addresses general requirements such as component classification, Owner's responsibilities, duties of the Inspector, examination methods, qualifications of NDE personnel, inspection plans, schedules, Code Cases, repair, replacements, records, and reports.

ASME Section XI, Subsection IWL ASME Section XI, Subsection IWL, Requirements for Class CC Concrete Components of Light-Water Cooled Plants, includes the requirements that are applicable to all such reinforced concrete and post-tensioning systems for pre-service inspection, inservice inspection, repair, and replacement activities. The component exemptions and examination category requirements are summarized below.

IWL-1220 Exemptions The following items are exempt from the examination requirements of IWL-2000:

(a) Tendon end anchorages that are inaccessible, subject to the requirements of IWL-2521.1 (b) Portions of the concrete surface that are covered by the liner, foundation material, or backfill, or are otherwise obstructed by adjacent structures, components, parts, or appurtenances IWL-2500 Examination Requirements Tables 3.5.3-4 and 3.5.3-5 lists the items for examination category L-A and L-B of IWL-2500, respectively.

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Table 3.5.3-4, Subsection IWL, Examination Category L-A, Concrete Examination Requirements Item No. Items Required to be Examined Method L1.11 All accessible concrete surfaces and coated areas VT-3C Every 5 Years L1.12 All accessible concrete surfaces and coated areas VT-1C determined to be suspect areas detected during the Every 5 Years L1.11 inspection item and VT-3C examinations (e.g., cracks, wear, corrosion)

Table 3.5.3-5, Subsection IWL, Examination Category L-B, Unbonded Post-Tensioning System Inspection Requirements Item No. Items Required to be Tested or Examined Method L2.10 Prestressing tendon lift-off force test IWL-2522 (all inspection sample tendons) Every 5 Years L2.20 Wire or strand examination and tension test IWL-2523.2 (one sample tendon of each type) Every 5 Years L2.30 Anchorage hardware and surrounding concrete VT-1and VT-1C examinations Every 5 Years (all inspection sample tendons)

L2.40 Corrosion protection medium examination and IWL-2525.2(a) analysis IWL-2526 (all inspection sample tendons) Every 5 Years L2.50 Free water analysis IWL-2524.2 (all inspection sample tendons) IWL-2525.2(b)

Every 5 Years Code of Federal Regulations 10 CFR 50.55a Requirements ASME Section XI, Subsection IWL The following paragraphs in 10 CFR 50.55a modify or clarify the implementation requirements of Section XI, Subsection IWL, and are summarized in Table 3.5.3-6.

Unless noted, the 10 CFR 50.55a paragraph references are to the July 19, 2011 amendment to 10 CFR 50.55a.

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Table 3.5.3-6, 10 CFR 50.55a Requirements 10 CFR 50.55a Paragraphs IWL Modifications and Clarifications 10 CFR 50.55a(b)(2)(viii)(E) The Licensee shall evaluate the acceptability of inaccessible areas when conditions exist in accessible areas that could indicate the presence of, or result in, degradation to such inaccessible areas. For each inaccessible area identified the licensee shall provide the following in the ISI Summary Report per IWA-6000:

(1) Description of type, estimated extent and cause of degradation; (2) Evaluation and results of each area; (3) Description of necessary corrective actions.

10 CFR 50.55a(g)(4)(v)(C) Concrete containment pressure retaining components and their integral attachments, and the post-tensioning systems of concrete containments must meet the inservice inspections, repair, and replacement requirements applicable to components, which are classified as ASME Code class CC.

10 CFR 50.55a(g)(6)(ii)(B) Licensees do not have to submit the program to the NRC for approval.

Additional Examination Requirements No additional examination requirements have been incorporated into the program.

Owners Activity Reports and Repair/Replacement Records APS will prepare records of the examinations, tests, replacements, and repairs in accordance with IWA-6210(b). The ISI Summary Report shall include the information required by 10 CFR 50.55a(b)(2)(viii)(E). An Engineering Evaluation Report shall be prepared when necessary as required by IWL-3300. The Owners Report for Repairs and Replacements, Form NIS-2, will be prepared as necessary in accordance with IWA-6230 and submitted in accordance with IWA-6240.

Acceptance Criteria - Concrete Acceptance criteria for concrete are divided into three tiers. Examination results that meet Tier 1 criteria are acceptable without further examination or evaluation. Those that do not meet Tier 1 criteria must be reviewed by the Responsible Engineer. The Responsible Engineer should examine any area of the containment surface that exhibits conditions not meeting Tier 1 criteria and may accept such conditions without formal evaluation if these meet Tier 2 criteria. Conditions that do not meet Tier 2 criteria are subject to Tier 3 requirements and this evaluation must be documented by the Responsible Engineer in the Engineering Evaluation.

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Tier 1 Acceptance Criteria The following are recommendations. Examination results are acceptable without further evaluation if the findings meeting the following criteria:

a) No evidence of chemical attack, abrasion or erosion sufficient to expose coarse aggregate.

b) No evidence of water flowing from, or on the surface of, the concrete.

c) No evidence of scaling and/or disintegration sufficient to expose coarse aggregate.

d) No popouts or voids greater than 0.50 inch in depth and 1.00 inch in diameter.

e) No spalls greater than 0.50 inch in depth and 4.00 inch in any other dimension.

f) No passive cracks greater than 0.025 inch in width, measured below any surface widening.

g) No evidence of efflorescence, exudation and/or incrustation.

h) No evidence of discoloration indicative of corrosion of embedded steel.

i) No exposure of reinforcing steel.

j) No cracking, blistering and/or peeling of coatings.

Tier 2 Acceptance Criteria The Responsible Engineer may accept (without formal evaluation), after examining the affected location or item, conditions up to the following criteria. The acceptance of any condition exceeding the following criteria shall be documented by the Responsible Engineer in an Engineering Evaluation.

a) Chemical attack, abrasion and/or erosion sufficient to expose coarse aggregate if:

1) There is no exposure of reinforcing or other embedded steel originally covered by concrete.

2) The source of the chemical attack, abrasion or erosion is identified, and it can be verified that the source was either:

 Active only during plant construction.

 An isolated past event.

 Eliminated through corrective action completed prior to the start of the current examination.

b) Scaling and/or Disintegration sufficient to expose coarse aggregate if:

1) There is no exposure of reinforcing or other embedded steel originally covered by concrete.

2) The condition that caused the scaling/disintegration is identified and it can be verified that the condition was either:

 Active only during plant construction.

 An isolated past event.

 Eliminated through corrective action completed prior to current examination.

c) No popouts and/or voids greater than 1.00 inch in depth and 2.00 inch in diameter.

d) No spalls greater than 1.00 inch in depth and 8.00 inch in any other dimension.

e) No passive cracks greater than 0.04 inch in maximum width, measured below any surface widening.

f) Discoloration indicative of corrosion of embedded steel if:

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1) Corrosion of embedded items is limited to steel surfaces that are exposed by design (e.g., exposed surface of an embedded attachment plate).

2) Either of the following conditions is satisfied when other items exhibit corrosion:

 The source of the corrosion is verified to be no longer active (e.g., exposure to weather prior to completion of the containment building) and corrosion is limited to tightly adhering rust.

 Corrosion, if ongoing and/or major, is identified through the appropriate plant notification procedure, as a condition that is potentially adverse to the quality of another plant item (i.e., a plant item other than the concrete containment).

g) Exposure of reinforcing steel if:

1) Exposure is the result of installation tolerances (i.e., steel was initially provided with insufficient cover).

2) There is no evidence that the amount of steel surface exposed is increasing with time.

3) There is no evidence of active (ongoing) corrosion on the steel surface.

h) Cracking, blistering and/or peeling of coatings if this is due to misapplication of the coating and not to cracking of and/or exudation from the underlying concrete.

Tier 3 Acceptance Criteria The Responsible Engineer is to perform and document in an Engineering Evaluation any condition that does not satisfy Tier 1/Tier 2 acceptance criteria.

The Engineering Evaluation should address the following:

a) The need for additional examination (to include NDE, coatings removal, or concrete removal) to further define the nature and extent of the condition.

b) The cause (or probable cause) of the condition and whether the cause (and consequent damage/degradation) is ongoing or terminated.

c) The need for measures to eliminate/correct the cause, if applicable.

d) The acceptability of the integrity of the containment in the as-found condition.

e) The need for repairs.

f) Augmented (more frequent) future examinations if required to provide assurance that the observed condition remains stable and acceptable.

g) The need for examination of inaccessible areas that may be subject to the same conditions that caused degradation in accessible areas.

Acceptance by Evaluation The Responsible Engineer may accept the condition based on an Engineering Evaluation that shows that the current and expected on-going integrity of the structure satisfies the minimum requirements established by the design. Alternatively, acceptance may be deferred pending more extensive examination or made contingent on one or more of the following:

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a) Completion of satisfactory repairs.

b) Elimination of the mechanisms causing damage/degradation.

c) Stability of the documented condition as established by augmented (more frequent) examinations.

The Responsible Engineer shall evaluate the acceptability of inaccessible areas when conditions exist in accessible areas that could indicate the presence of or result in degradation to such inaccessible areas. For each inaccessible area identified, the licensee shall provide the following in the ISI Summary Report required by IWA-6000:

a) A description of the type and estimated extent of degradation, and the conditions that led to the degradation.

b) An evaluation of each area, and the result of the evaluation.

c) A description of necessary corrective actions. [10 CFR 50.55a(b)(2)(viii)(E)]

The Responsible Engineer shall make recommendations following an evaluation of indications. The recommendations may include but are not limited to "Use-As-Is",

Rework of Cosmetic Condition, Repair/ Replacement, Analytical Evaluation, Additional Examinations, Modifications, Design/Drawing Changes, or other corrective measures deemed appropriate for the condition being evaluated.

Acceptance by Repair If the examination identifies conditions that warrant repair or replacement, the Responsible Engineer shall include the extent, method, and completion date for the repair or replacement in the Engineering Evaluation Report.

Pressure Test Acceptance Criteria If the surface examinations cannot satisfy the requirements specified by the Responsible Engineer in the examination procedure, the area shall be examined to the extent necessary to establish requirements for corrective action. If further repairs are required, they shall be conducted in accordance with IWL-4000 and pressure testing shall be repeated in accordance with IWL-5200, prior to returning the containment to service. [IWL-5260]

Engineering Evaluation Report Items with examination results that do not meet the acceptance standards for concrete examination shall be evaluated by the Owner. The Owner shall be responsible for preparation of an Engineering Evaluation Report stating the following:

a) The cause of the condition that does not meet the acceptance standards.

b) The applicability of the condition to any other plants at the same site.

c) The acceptability of the concrete containment without repair of the item.

d) Whether or not repair/replacement activity is required and, if required the extent, method, and completion date (or scheduled completion date) for the repair/replacement activity.

e) Extent, nature, and frequency of additional examinations.

f) Trend of prestress loss on tendons such that the tendon force would be less than the minimum design prestress requirement before the next inspection interval.

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Acceptance Criteria - Post-Tensioning Tendons Examination requirements for Unbonded Post-Tensioning Systems are defined in the ASME Boiler and Pressure Vessel Code,Section XI, IWL-3220, and 10 CFR 50.55a, and summarized below.

Acceptance by Examination Tendon Prestress Force Tendon prestressing forces are acceptable if:

a) The average of all measured tendon forces for each type of tendon is equal to or greater than the minimum required prestress specified at the anchorage for that type of tendon.

b) The measured force in each individual tendon is not less than 95% of the predicted force unless the following conditions are satisfied:

(1) The measured force in not more than one tendon is between 90% and 95% of the predicted force.

(2) The measured forces in two tendons located adjacent to the tendon in (1) above are not less than 95% of the predicted force.

(3) The measured forces in all the remaining sample tendons are not less than 95% of the predicted force. [IWL-3221.1]

Wire Physical Examination Tendon wire samples are acceptable if:

a) Samples are free of physical damage.

b) Sample ultimate tensile strength and elongation are not less than minimum specified values. [IWL-3221.2]

Tendon Anchorage Areas Tendon Anchorage Areas are acceptable if:

a) There is no evidence of active corrosion.

b) There is no evidence of cracking in any of the metal components.

c) Broken or unseated wires and detached buttonheads were documented and accepted during a preservice examination or during a previous inservice examination.

d) Cracks in the concrete adjacent to the bearing plates do not exceed 0.01 inch in width. [IWL-3221.3]

Corrosion Protection Medium Contamination The corrosion protection medium (grease) is acceptable when the reserve alkalinity, water content, and soluble ion concentrations of all samples are within the limits specified in ASME Section XI, Subsection IWL-2525, Table IWL-2525-1. [IWL-3221.4]

Corrosion Protection Medium Leakage If any of the following conditions occur, they must be evaluated as required by IWL-3300:

a) The sampled sheathing filler grease contains chemically combined water exceeding 10% by weight or the presence of free water.

b) The absolute difference between the amount of grease removed and the amount replaced exceeds 10% of the tendon net volume.

c) Grease leakage is detected during general visual examination of the containment surface.

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Acceptance by Evaluation Items with examination results that do not meet the acceptance standards shall be evaluated by the Owner and the disposition of that evaluation stated in an Engineering Evaluation. [IWL-3222]

Acceptance by Repair or Replacement Repairs or replacements to reestablish acceptability of the condition of an item shall be completed as required by an Engineering Evaluation. Acceptable completion and examination of the repair or replacement shall constitute acceptance of the item.

[IWL-3223]

Engineering Evaluation Report Items with examination results that do not meet the acceptance standards shall be evaluated by the Owner and reported in an Engineering Evaluation Report stating the following:

a) The cause for the condition that does not meet the acceptance standards.

b) The acceptability of the concrete containment without repair of the item.

c) The applicability of the condition to any other plants at the same site.

d) Whether or not repair or replacement is required and, if required, the extent, method, and completion date for the repair or replacement.

e) Extent, nature, and frequency of additional examinations. [IWL-3310]

3.5.4 Supplemental Inspection Requirements Supplemental Inspections will not be required. Inspections of the interior and exterior containment concrete surfaces and the steel liner shall be performed in accordance with TS 5.5.16, exceptions 1 and 2 as follows:

1. The visual examination of containment concrete surfaces intended to fulfill the requirements of 10 CFR 50, Appendix J, Option B testing, will be performed in accordance with the requirements of and frequency specified by ASME Code Section XI, Subsection IWL, except where relief has been authorized by the NRC. The containment concrete visual examination may be performed during either power operation, e.g.,

performed concurrently with other containment inspection-related activities such as tendon testing, or during a maintenance/refueling outage. (Reference 15)

2. The visual examination of the steel liner plate inside containment intended to fulfill the requirements of 10 CFR 50, Appendix J, Option B testing, will be performed in accordance with the requirements of and frequency specified by ASME Code Section XI, Subsection IWE, except where relief has been authorized by the NRC. (Reference 15)

The examination and testing of the post-tensioning system will continue to be performed every five years in accordance with the schedule in TS 5.5.6, Pre-Stressed Concrete Containment Tendon Surveillance Program, and do not necessarily coincide with either the containment concrete examination or the steel liner examination.

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3.5.5 Results of Recent Containment Examinations Containment Coating Assessments The PVNGS Containment Coatings Condition Assessment is conducted in a refueling outage in accordance with PVNGS Procedure, Containment Coatings Condition Assessment. Coated systems, structures and components within the Reactor Containments are examined, and, when localized areas of coating defects are found, those areas are evaluated and scheduled for touch-up, repair, or replacement as necessary. The periodic Containment Condition Assessments, and the resultant repair/replacement activities, assure that the amount of Service Level 1 Coatings which may be susceptible to detachment from the substrate during a Design Basis Accident (DBA) event is minimized. of the enclosure provides an assessment of the PVNGS Unit 2 Containment Coatings in 2R22, Unit 3 Containment Coatings in 3R21, and Unit 1 Containment Coatings in 1R21.

Results of Recent IWE Examinations The results of recent IWE examinations are identified in Attachment 5 of the enclosure, Tables 3.5.5-1 and 3.5.5-2 (PVNGS Unit 2), Tables 3.5.5-3 and 3.5.5-4 (PVNGS Unit 3) and Tables 3.5.5-5 and 3.5.5-6 (PVNGS Unit 1).

Results of Recent IWL Concrete Examinations The number of exams performed during IWL concrete inspections is substantial. Only those inspections requiring reviews will be identified in Attachment 6 of the enclosure, Table 3.5.5-7 (PVNGS Unit 1), Table 3.5.5-8 (PVNGS Unit 2), and Table 3.5.5-9 (PVNGS Unit 3).

Results of Recent IWL Tendon Examinations Unit 1 35th-year Exam (Visual Only), Examination Completed: September 13, 2017 The following tendons were inspected during the Unit 1 35th-year visual examination:

 V21

 V75

 V83

 H21-013

 H32-030

 H32-040

 H21-044 Shop End Only - Added to scope to address leaking grease cap.

All examinations were performed Satisfactory with no unexpected conditions, no abnormal conditions and no identified degradation. All inservice grease samples were within specifications (1). No free water was identified.

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Unit 2 30th-year Exam (Visual Only), Examination Completed: April 14, 2015

 V29

 V54

 V75

 H13-043 shop end was inaccessible. The field end was inspected and an alternate tendon H32-043 was inspected.

 H21-001

 H32-030

 H32-043 All examinations were performed Satisfactory with no unexpected conditions, no abnormal conditions and no identified degradation. All inservice grease samples were within specifications (1). No free water was identified.

Unit 3 30th-year Exam (Visual Only), Examination Completed: October 25, 2016

 V16

 V31

 V50

 H13-027

 H13-036

 H32-011(2)

All examinations were performed Satisfactory with no unexpected conditions, no abnormal conditions and no identified degradation except for tendon H32-011 as discussed below. All inservice grease samples were within specifications (1). No free water was identified.

Note: (1) Tendon Grease Acceptance Criteria While reviewing procedure, Tendon Integrity, an error was identified in the acceptance criteria for tendon grease. The acceptance criteria for reserve alkalinity of the in-service grease was listed as having a maximum allowable limit of 0-50% of the installed value. This acceptance criterion, however, is not aligned with ASME Section XI, 2007 Edition and 2008 Addenda, Article IWL- 2525.2, Sample Analysis (Table IWL-2525-1, Corrosion Protection Medium Analysis). Specifically, the Code states that the base number shall be at least 50% of the as-installed value. PVNGS is committed to this edition and addenda of ASME Section XI per Program Manuals. Further review of past procedures revealed that this requirement for the grease testing has existed since at least 1992 when procedure, Tendon Integrity, Revision 1, was issued.

Regardless of which acceptance criteria is used, PVNGS does not currently have documentation of the reserve alkalinity of the original in-service grease installed values. This presents a problem because one cannot compare future readings to original install values. It is expected that PVNGS did capture these original installed values, but this cannot be confirmed. Engineering will need to perform extensive research to attempt to find copies of this data, if it exists.

Operability Evaluation and Conclusion PVNGS implements a Pre-Stressed Concrete Containment Tendon Surveillance Program to ensure containment structural integrity. The purpose of the 61

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surveillance test is to implement the ASME Section XI, Subsection IWL. There are several required tests in subsection IWL. The one test applicable to this is IWL 2525, Examination of Corrosion Protection Medium and Free Water.

Under this section Table IWL-2525-1, Corrosion Protection Medium Analysis, specifies the acceptance limits of a grease sample removed from the required tendons. There are five characteristics being tested: water content, water soluble chlorides, water soluble nitrates, water soluble sulfides, and reserve alkalinity. The acceptance criteria for all characteristic are known except for the reserve alkalinity limit.

The acceptance limit for the reserve alkalinity is described in Table IWL-2525-1, note 3. The applicable portion of note 3 states: The base number shall be at least 50% of the as-installed value . This requirement cannot be verified through the performance of the surveillance test since the As-installed value is not available and so the 50% limit cannot be determined. With no acceptance criteria available it is not possible to determine if the last performance of the surveillance test passed or failed the criteria for reserve alkalinity.

Without the knowledge of the acceptance criteria for reserve alkalinity this portion of the required test is indeterminate. Article IWL-3000, Acceptance Standards, step IWL-3221.4, Corrosion Protection Medium, states that the reserve alkalinity shall meet the acceptance criteria specified in Table IWL-2525-1. The next step, IWL-3222, Acceptance by Evaluation, states; Items with examination results that do not meet the acceptance standards of IWL-3221 shall be evaluated as required by IWL-3300. The specific section that outlines the evaluation is in section IWL-3310, Evaluation Report.

The evaluation required by section IWL-3310 was performed under an Engineering Evaluation. To determine if the grease is performing its intended function to minimize or prevent corrosion from damaging the tendons, other portions of Reference 1 testing results were used. The evaluation determined that the following criteria are within their required acceptance limits:

 The remaining tendon grease chemical properties

 The visual examination of the anchorage assembles (anchor head, buttonheads, and bearing plate)

 If applicable, tendon lift-off forces and elongation values

 Existing inservice trending data One of the final conclusions of the Engineering Evaluation is; The in-service tendon grease chemical analysis is considered acceptable.

Conclusion With completion of the Engineering Evaluation, the absence of an initial reserve alkalinity value to use for determining the acceptance criteria has been evaluated. The evaluation completed the requirement to demonstrate that all three, unit containment buildings meet ASME Section XI, Subsection IWL requirements. Since the ASME Code requirements are met, there is a reasonable expectation for operability of the containment structures and their tendons.

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Note: (2) Small Void Found Below Bearing Plate for Tendon H32-011 On February 11, 2016 while performing a visual exam of the Unit 3 containment concrete surrounding the bearing plate on tendon H32-011, a void was found. It appears this area was previously repaired with a grout patch, which has begun to degrade. At its deepest point the void was measured to be 2 in. deep.

The condition report (CR) identifies a nonstructural void around a tendon plate for tendon H32-011. This void appears to have been patched in the past. The area in question is the transition area between concrete and the tendon bearing plate. The deepest point of the void is 2 3/4 in. deep and 1 3/4 in.

across. There are no significant cracks in the base concrete in this transition area and no exposed rebar, tendons or indication of any corrosion of any metal imbedded in the concrete. The containment remains operable because an ILRT was completed successfully April 2015, which pressurized containment and measured total leak rate. Containment remains Operable. Requested an engineering work request (EWR) for civil engineering to support the nonstructural nature of this void. This condition is not immediately reportable in accordance with the Event Reporting Manual. Additional Evaluations for extent of condition have been requested in the original CR as well as corrective maintenance work orders (CMWOs) to repair the identified void.

3.5.6 Containment Leakage Rate Testing Program - Type B and Type C Testing Program PVNGS Types B and C testing program requires testing of electrical penetrations, airlocks, hatches, flanges and CIVs in accordance with 10 CFR 50, Appendix J, Option B and RG 1.163 (Reference 1). The results of the test program are used to demonstrate that proper maintenance and repairs are made on these components throughout their service life. The Types B and C testing program provides a means to protect the health and safety of plant personnel and the public by maintaining leakage from these components below appropriate limits. In accordance with TS 5.5.16, the allowable maximum pathway total Types B and C leakage is 0.6 La [150,000 standard cubic centimeters per minute (sccm)] where La equals 250,000 sccm.

As discussed in NUREG-1493 (Reference 6), Type B and Type C tests can identify the vast majority of all potential containment leakage paths. Type B and Type C testing will continue to provide a high degree of assurance that containment integrity is maintained.

A review of the As-Found (AF)/As-Left (AL) test values for PVNGS Units 1, 2, and 3 can be summarized as follows:

Unit 1

 As-Found minimum pathway leak rate shows an average of 2.55% of 1.0 La with a high of 3.07% of 1.0 La.

 As-Left maximum pathway leak rate shows an average of 6.02% of 1.0 La with a high of 6.86% of 1.0 La.

Unit 2

 As-Found minimum pathway leak rate shows an average of 1.85% of 1.0 La with a high of 2.24% of 1.0 La.

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 As-Left maximum pathway leak rate shows an average of 4.56% of 1.0 La with a high of 6.86% of 1.0 La.

Unit 3

 As-Found minimum pathway leak rate shows an average of 1.54% of 1.0 La with a high of 1.86% of 1.0 La.

 As-Left maximum pathway leak rate shows an average of 3.67% of 1.0 La with a high of 5.48% of 1.0 La.

Tables 3.5.6-1, 3.5.6-2 and 3.5.6-3 provide LLRT data trend summaries for PVNGS Units 1, 2, and 3, respectively, including the most recent ILRTs for each unit.

Table 3.5.6-1 PVNGS Unit 1 Type B and C LLRT Combined As-Found/As-Left Trend Summary Outage & 1R15 1R16 1R17 1R18 1R19 1R20 1R21 Year 2010 2011 2013 2014 2016 2017 2019 AF Min Path 7060 4439 6267 7663 6828 5952 6410 (sccm)

%1.0La 2.82 1.78 2.51 3.07 2.73 2.38 2.56 AL Max Path 13337 16128 13080 15767 14951 17157 14952 (sccm)

%1.0La 5.3 6.45 5.23 6.31 5.98 6.86 5.98 AL Min Path 4733 5886 6043 7613 5996 7652 4674 (sccm)

%1.0La 1.90 2.35 2.42 3.05 2.40 3.06 1.87 Table 3.5.6-2 PVNGS Unit 2 Type B and C LLRT Combined As-Found/As-Left Trend Summary Outage & 2R16 2R17 2R18 2R19 2R20 2R21 2R22 Year 2011 2012 2014 2015 2017 2018 2020 AF Min Path 4894 4118 5274 3482 3606 5385 5600 (sccm)

%1.0La 1.95 1.65 2.1 1.4 1.44 2.15 2.24 AL Max Path 10754 9226 8170 8930 10622 14952 17151 (sccm)

%1.0La 4.30 3.69 3.26 3.57 4.25 5.98 6.86 AL Min Path 4535.5 4281 3701 3376 4735 4674 5598 (sccm)

%1.0La 1.81 1.71 1.48 1.35 1.89 1.87 2.24 64

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Table 3.5.6-3 PVNGS Unit 3 Type B and C LLRT Combined As-Found/As-Left Trend Summary Outage & 3R15 3R16 3R17 3R18 3R19 3R20 3R21 Year 2010 2012 2013 2015 2016 2018 2019 AF Min Path 4638 3967 3867 3914 3651 3027 3918 (sccm)

%1.0La 1.86 1.59 1.55 1.57 1.46 1.21 1.57 AL Max Path 13707 9608 9920 7666 5405 6908 11043 (sccm)

%1.0La 5.48 3.84 3.97 3.07 2.16 2.76 4.42 AL Min Path 6560 4993 5182 4384 3055 2623 4690 (sccm)

%1.0La 2.62 2.0 2.07 1.75 1.22 1.05 1.88 The As-Found minimum pathway summations represent the high quality of maintenance of Type B and Type C tested components while the As-Left maximum pathway summations represent the effective management of the Containment Leakage Rate Testing Program by the program owner.

3.5.7 Type B and Type C Local Leak Rate Testing Program Implementation Review Tables 3.5.7-1, 3.5.7-2 and 3.5.7-3 identify PVNGS Units 1, 2, and 3 components, respectively, which were on Appendix J, Option B performance-based extended test intervals, but have not demonstrated acceptable performance during the previous two outages. The component test intervals for the components shown have been reduced to 18 months.

Table 3.5.7-1 PVNGS Unit 1 Types B and C LLRT Program Implementation Review 1R20 - Unit 1 Fall of 2017 Refueling Outage Admin As- Limit As-left Cause of Corrective Scheduled Component found Alert sccm Failure Action Interval sccm /Action sccm 1JGRAUV0001 Note 1 500 10 Note 1 Reset Interval 18 months 1R21 - Unit 1 Spring of 2019 Refueling Outage Admin As- Limit As-left Cause of Corrective Scheduled Component found Alert sccm Failure Action Interval sccm /Action sccm 1JCHAHV0524 Note 2 750 10 Note 2 Reset Interval 18 months Note 1: 1GRAUV0001 had a torque switch adjusted as a result of static testing. The static testing was not recognized as a test requiring as-found testing during scope build. As a result, as-found data was not collected. Therefore, the 65

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Table 3.5.7-1 PVNGS Unit 1 Types B and C LLRT Program Implementation Review performance history was invalidated, and the valve was reset to the default interval of 18 months.

Note 2: 1CHAHV0524 work order was changed to allow a packing adjustment for a stem clean and lube which lead to a missed As-Found value. An As-Left LLRT was performed on the valve after a missed exam was identified. Additionally, the interval was reset to its default interval.

Table 3.5.7-2 PVNGS Unit 2 Types B and C LLRT Program Implementation Review 2R21 - Unit 2 Fall of 2018 Refueling Outage As- Admin As-left Cause of found Limit sccm Failure Corrective Scheduled Component sccm Alert/

Action Interval Action sccm Evaluation performed to Excessive document that 2JSSBUV0201 1365 1000 1365 18 months leakage the leakage is acceptable until 2R22 2R22 - Unit 2 Spring of 2020 Refueling Outage Admin As- Limit As-left Cause of Corrective Scheduled Component found Alert sccm Failure Action Interval sccm /Action sccm None Table 3.5.7-3 PVNGS Unit 3 Types B and C LLRT Program Implementation Review 3R20 - Unit 3 Spring of 2018 Refueling Outage Admin As- Limit As-left Cause of Corrective Scheduled Component found Alert sccm Failure Action Interval sccm /Action sccm Excessive Valve was 3JSSAUV0204 4802 1000 10 18 months leakage replaced.

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Table 3.5.7-3 PVNGS Unit 3 Types B and C LLRT Program Implementation Review 3R21 - Unit 3 Fall of 2019 Refueling Outage Admin As- Limit As-left Cause of Corrective Scheduled Component found Alert sccm Failure Action Interval sccm /Action sccm Evaluation performed to document Excessive 3JCHAUV0580 1047 500 1047 that the 18 months leakage leakage is acceptable until 3R22 Repeat Failures None were identified.

Performance Summary

 For Unit 1, 94% of all penetrations eligible for extended intervals are on extended intervals.

 For Unit 2, 94% of all penetrations eligible for extended intervals are on extended intervals.

 For Unit 3, 97% of all penetrations eligible for extended intervals are on extended intervals.

3.6 Operating Experience (OE)

During the conduct of the various examinations and tests conducted in support of the containment related programs previously mentioned, issues that do not meet established criteria or that provide indication of degradation, are identified, placed into the site's corrective action program, and corrective actions are planned and performed.

For the PVNGS Primary Containment, the following site specific and industry events have been evaluated for impact:

 Information Notice (IN) 1992-20, Inadequate Local Leak Rate Testing

 IN 2010-12, Containment Liner Corrosion

 IN 2014-07, Degradation of Leak-Chase Channel Systems for Floor Welds of Metal Containment Shell and Concrete Containment Metallic Liner Each of these areas is discussed in detail in Sections 3.6.1 through 3.6.3, respectively.

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3.6.1 IN 1992-20, Inadequate Local Leak Rate Testing The NRC issued IN 92-20 to alert licensees of problems with local leak rate testing of two-ply stainless steel bellows used on piping penetrations at four different plants:

Quad Cities, Dresden Nuclear Station, Perry Nuclear Plant, and the Clinton Station.

Specifically, LLRTs could not be relied upon to accurately measure the leakage rate that would occur under accident conditions, because, during testing, the two plies in the bellows were in contact with each other, restricting the flow of the test medium to the crack locations. Any two-ply bellows of similar construction may be susceptible to the problem. The common issue in the four events was the failure to adequately perform local leak rate testing on different penetration configurations leading to problems that were discovered during ILRT tests in the first three cases.

In the event at Quad Cities, the two-ply bellows design was not properly subjected to LLRT pressure and the conclusion of the utility was that the two-ply bellows design could not be Type B LLRT tested as configured.

In the events at both Dresden and Perry, flanges were not considered a leakage path when the Type C LLRT test was designed. This omission led to a leakage path that was not discovered until the plant performed an ILRT test.

In the event at Clinton, relief valve discharge lines that were assumed to terminate below the suppression pool minimum drawdown level were discovered to terminate at a level above that datum. These lines needed to be reconfigured and the valves should have been Type C LLRT tested.

Discussion:

An evaluation was performed and determined that PVNGS does not have the problems described in IN 92-20.

3.6.2 IN 2010-12, Containment Liner Corrosion The NRC issued IN 10-12 to alert plant operators to three events that occurred where the steel liner of the containment building was degraded and corroded. Concrete reactor containments are typically lined with a carbon steel liner to ensure a high degree of leak tightness during operating and accident conditions. The reactor containment is required to be operable as specified in plant technical specifications to limit the leakage of fission product radioactivity from the containment to the environment. The regulations at 10 CFR 50.55a, Codes and Standards, require the use of Subsection IWE of ASME Section XI, to perform inservice inspections of containment components. The required inservice inspections include periodic visual examinations and limited volumetric examinations using ultrasonic thickness measurements. The containment components include the steel containment liner and integral attachments for the concrete containment, containment personnel airlock and equipment hatch, penetration sleeves, moisture barriers, and pressure-retaining bolting. The NRC also requires licensees to perform leak rate testing of the containment pressure-retaining components and isolation valves according to 10 CFR Part 50, Appendix J, Primary Reactor Containment Leakage Testing for Water-Cooled Power Reactors, as specified in plant technical specifications. This operating experience highlights the importance of good quality assurance, housekeeping and high quality construction practices during construction operations in accordance with 68

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10 CFR Part 50, Appendix B, Quality Assurance Criteria for Nuclear Power Plants and Fuel Reprocessing Plants.

Operating experience shows that containment liner corrosion is often the result of liner plates being in contact with objects and materials that are lodged between or embedded in the containment concrete. Liner locations that are in contact with objects made of an organic material are susceptible to accelerated corrosion because organic materials can trap water that combined with oxygen will promote carbon steel corrosion. Organic materials can also cause a localized low pH area when they decompose. Organic materials located inside containment can come in contact with the containment liner and cause accelerated corrosion. However, corrosion that originates between the liner plate and concrete is a greater concern because visual examinations typically identify the corrosion only after it has significantly degraded the liner. In some cases, licensees identified such corroded areas by performing ultrasonic examination of suspect areas (e.g., areas of obvious bulging, hollow sound).

The objects and materials that caused liner corrosion that licensees have found lodged between or embedded in the containment concrete include both foreign material (e.g., wooden pieces, workers gloves, wire brush handles) and material that was deliberately installed as part of the design such as the felt material described in the above example at Brunswick Steam Electric Plant, Unit 1. Although there is no regulatory requirement to do so, one or more licensees have chosen to review design documents to identify locations where organic material was intentionally installed between the liner or penetration sleeve and schedule additional examinations of these areas to monitor for liner material loss.

Discussion:

There are three examples given in IN 10-12 of containment liner degradation caused by corrosion. The first one at Beaver Valley involved a piece of wood embedded in between the liner and concrete that was left there from construction days. The second example at Brunswick Steam Electric was the use of a layer of ethylene propylene film wrapped around the outside diameter of the containment penetration sleeve. This sleeve was also installed during construction. And the third example at Salem was heavy corrosion found in areas that were considered inaccessible. This area was located 6 inches above the moisture barrier seal and behind an insulation package. The source of the moisture that caused the liner corrosion was service water leakage from the containment fan coil units and associated piping.

In all three cases, corrosion was identified on the liner plate through various reasons.

In two instances, there was foreign material left from construction that gathered moisture and eventually corroded away the liner. PVNGS does not have an annulus and therefore cannot monitor the interior surfaces of the Containment liner plate for any possible foreign material left behind (i.e. wood, film). However, since the containment liner plate procedure was created, it has included in the criteria for inspection looking for any possible blistering, bulging, thinning, etc. in the liner. To date, PVNGS has not had an incident similar to Beaver Valley or Brunswick that included the characteristics described from the wood or film corroding through the liner. According to the specification which is titled, The Placing of Reinforcement Steel; reinforcing steel bar shall be securely tied with black annealed wire, of sufficient gauge to prevent movement, and held in position by metal chairs, metal spacers, metal hangers, or other approved supports. Also, after review of the 69

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specification which deals with concrete curing/installation, wood was used in the forming of the concrete containment, however, all wood and loose debris was required to be removed prior to final forming of concrete.

Additionally, drawings were reviewed and there was no evidence of film ever being wrapped around the penetration sleeves during construction to permit thermal loading. PVNGS does include in its visual inspections when at the liner plate penetrations to look for characteristics found at Brunswick.

The third instance at Salem described where corrosion was found behind insulation above the moisture barrier as a result of a service water leak from the containment fan coil units and associated piping. PVNGS does not have a moisture barrier on its liner plate, nor an insulation package that would be found above the barrier.

However, PVNGS has incorporated in its liner plate procedure to look for evidence of corrosion/degradation at the bottom of containment where the liner meets the floor.

IN 04-09, Corrosion of Steel Containment and Containment Liner, also contained OE where corrosion was found around or behind the moisture barrier similar to Salem.

PVNGS performed an evaluation of IN 04-09 and included in its subsequent inspections to pay particular attention to the areas at the bottom of the floor. No corrosion has been identified comparable to what was found in IN 04-09 or Salem.

3.6.3 IN 2014-07, Degradation of Leak-Chase Channel Systems for Floor Welds of Metal Containment Shell and Concrete Containment Metallic Liner The NRC issued this IN to inform addressees of issues identified by the NRC staff concerning degradation of floor weld leak-chase channel systems of steel containment shell and concrete containment metallic liner that could affect leak-tightness and aging management of containment structures. The NRC expected that recipients will review the information for applicability to their facilities and consider actions, as appropriate, to avoid similar problems.

The containment floor weld leak-chase channel system forms a metal-to-metal interface with the containment shell or liner, the test connection end of which is at the containment floor level. Therefore, the leak-chase system provides a pathway for potential intrusion of moisture that could cause corrosion degradation of inaccessible embedded areas of the pressure-retaining boundary of the basemat containment shell or liner within it. In addition to protecting the test connection, the cover plates and plugs and accessible components of the leak-chase system within the access box are also intended to prevent intrusion of moisture into the access box and into the inaccessible areas of the shell/liner within the leak-chase channels, thereby protecting the shell and liner from potential corrosion degradation that could affect leak-tightness.

The containment ISI program required by 10 CFR 50.55a is implemented in accordance with ASME Code Section XI, Subsection IWE, subject to regulatory conditions, requires special consideration of areas susceptible to accelerated corrosion degradation and aging, and barriers intended to prevent intrusion of moisture and water accumulation against inaccessible areas of the containment pressure-retaining metallic shell or liner. The containment floor weld leak-chase channel system is one such area subject to accelerated degradation and aging if moisture intrusion and water accumulation is allowed on the embedded shell and liner within it. Therefore, 70

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the leak-chase channel system is subject to ISI requirements of 10 CFR 50.55a(g)(4) and aging management requirements of 10 CFR 54.29(a)(1).

This IN provided examples of OE at some plants of water accumulation and corrosion degradation in the leak-chase channel system that has the potential to affect the leak-tight integrity of the containment shell or liner plate. In each of the examples, the licensee had no provisions in its ISI plan to inspect any portion of the leak-chase channel system for evidence of moisture intrusion and degradation of the containment metallic shell or liner within it. Therefore, these cases involved the licensees failure to perform required visual examinations of the containment shell or liner plate leak-chase systems in accordance with the ASME Code Section XI, Subsection IWE, as required by 10 CFR 50.55a(g)(4). The moisture intrusion and associated degradation found within leak-chase channels, if left uncorrected, could have resulted in more significant corrosion degradation of the containment shell or liner and associated seam welds. These examples and other similar previous industry operating experiences highlight the importance of licensees recognizing the existence of leak-chase channel systems in their containment floor. These experiences also highlight the importance of understanding the system configuration and how the leak-chase system components interact with the containment pressure-retaining metallic shell or liner plate within it to ensure that these systems are appropriately included for required examinations in the containment ISI program and the Subsection IWE aging management program.

For containments in which basemat shell/liner leak-chase channel systems exist with accessible interface at the containment floor level, licensees are required to comply with the containment ISI requirements of 10 CFR 50.55a(g)(4).

Discussion:

The purpose of the IN is to share recent issues identified at other plants that could affect leak-tightness of the metallic liner and provide recommendations to license holders.

The OE in the IN discusses three different pressurized water reactor plants that found corrosion and moisture intrusion in their leak chase system after the issue was identified by NRC Inspectors. In all three cases, the licensee had a leak chase system configuration with an accessible interface at the containment floor level that allowed for water accumulation. In addition to the susceptible configuration, the licensee had no requirements in place to perform inspections of the accessible leak chase components.

In the IN, the NRC clarified the requirements outlined in ASME Code,Section XI, Subsection IWE, Table IWE-2500-1, Note (3), and clarifies the intent of Figure IWE-2500-1. The intent of this clarification is to eliminate confusion to the user with regard to the scope of moisture barriers, and to identify the fact that Figure IWE-2500-1 is not all-inclusive.

The PVNGS Leak Chase Channel design and layout is similar to the designs discussed in the IN, except for the containment floor interface. At PVNGS, instead of having an embedded access box with cover plate, the leak chase tubing protrudes approximately 6 inches out of the concrete floor and has a threaded coupling and pipe plug on the end of the tubing. In addition to the tubing for the horizontal welds, 3 in.

channel protrudes from the containment floor on the outer edge of containment to 71

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capture the vertical liner plate welds embedded in the containment floor. The containment floor is sloped towards the containment sumps, and the sumps are continuously monitored for water and/or moisture.

Based on the fact that PVNGS does not have a cover plate that is relied on to keep water out of the leak chase channel nor is there any embedded access box that could act as a cavity for water accumulation, the PVNGS leak chase configuration does not fall within the definition of a "Moisture Barrier." PVNGS does not have a Code compliance issue as described in this IN.

As a conservative measure, based on the OE in this IN, and the potential for a failure in the leak chase system to challenge the integrity of the containment liner, PVNGS added the accessible portions of the leak chase system (tubing, channel, coupling and plugs) to the IWE program's General Visual Examination scope for each unit as identified in Table 3.5.2-2, ASME Item No. E1.30.

In addition, the pipe plugs on the leak chase tubing are removed during the performance of Type A testing.

3.7 License Renewal Aging Management In compliance with Unit 1 license condition 2.C.(16)(a), Unit 2 license condition 2.C.(11)(a), and Unit 3 license condition 2.C.(7)(a) of the PVNGS renewed operating licenses, Chapter 19 of the PVNGS UFSAR contains the information required by 10 CFR 54.21(d) that was contained in the PVNGS license renewal application, Appendix A, Updated Final Safety Analysis Report Supplement. The PVNGS license renewal application was submitted to the NRC in a letter dated December 11, 2008 and supplemented by letters submitted to the NRC through March 17, 2011. The NRC review of the PVNGS license renewal application is documented in NUREG-1961, Safety Evaluation Report Related to the License Renewal of Palo Verde Nuclear Generating Station, Units 1, 2, and 3, issued April 2011 (Reference 23). The aging management activity descriptions presented in the UFSAR, Section 19, represent commitments for managing aging of the in-scope systems, structures and components during the period of extended operation.

The following UFSAR programs/activities are credited with the aging management of the Primary Containment:

 UFSAR, Section 19.1.27, ASME Section XI, Subsection IWE The ASME Section XI, Subsection IWE containment inservice inspection program manages loss of material and loss of sealing of the steel liner of the concrete containment building, including the containment liner plate, piping and electrical penetrations, access hatches, and the fuel transfer tube.

Inspections are performed to identify and manage any containment liner aging effects that could result in loss of intended function. Acceptance criteria for components subject to Subsection IWE exam requirements are specified in Article IWE-3000. In conformance with 10 CFR 50.55a(g)(4)(ii), the PVNGS ISI Program is updated during each successive 120-month inspection interval to comply with the requirements of the latest edition and addenda of the Code specified twelve months before the start of the inspection interval.

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 UFSAR, Section 19.1.28, ASME Section XI, Subsection IWL The ASME Section XI, Subsection IWL program manages cracking, loss of material, and increase in porosity and permeability of the concrete containment building and post-tensioned system. Inspections are performed to identify and manage any aging effects of the containment concrete, post-tensioned tendons, tendon anchorages, and concrete surface around the anchorage that could result in loss of intended function. In conformance with 10 CFR 50.55a(g)(4)(ii) [in effect at the time (sic)], the ASME Section XI, Subsection IWL Program is updated during each successive 120-month inspection interval to comply with the requirements of the latest edition and addenda of the Code specified twelve months before the start of the inspection interval.

 UFSAR, Section 19.1.30, 10 CFR 50, Appendix J The 10 CFR 50, Appendix J program manages loss of material, loss of leak tightness, and loss of sealing. The program monitors leakage rates through the containment pressure boundary, including the penetrations and access openings, in order to detect degradation of containment pressure boundary.

Seals, gaskets, and bolted connections are also monitored under the program.

Containment leak rate tests are performed in accordance with 10 CFR 50 Appendix J, Primary Reactor Containment Leakage Testing for Water-Cooled Power Reactors, Option B; RG 1.163, Performance-Based Containment Leak-Testing Program; NEI 94-01, Industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50 Appendix J; and, ANSI/ANS 56.8, Containment System Leakage Testing Requirements.

Containment leak rate tests are performed to assure that leakage through the primary containment, and systems and components penetrating primary containment does not exceed allowable leakage limits specified in the TS.

Corrective actions are taken if leakage rates exceed established administrative limits for individual penetrations or the overall containment pressure boundary.

 UFSAR, Section 19.2.3, Concrete Containment Tendon Prestress The Concrete Containment Tendon Prestress program, within the PVNGS ASME Section XI, Subsection IWL Program, manages the loss of tendon prestress in the post-tensioning system.

The PVNGS post-tensioning system consists of inverted-U-shaped tendons, extending up through the basemat, through the full height of the cylindrical walls and over the dome; and horizontal circumferential (hoop) tendons, at intervals from the basemat to about the 45-degree elevation of the dome. The basemat is conventionally reinforced concrete. The tendons are ungrouted, in grease-filled glands.

The beginning of the first IWL tendon examination interval was September 9, 2001, for all three units. The beginning of the second interval was August 1, 2011, for all three units. As required by 10 CFR 50.55a, beginning August 1, 2011, the program will conform to a later edition of ASME Section XI, 73

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Subsection IWL, which permits a 10-year interval between tendon prestress surveillance tests, for each unit of a multi-unit plant. The entire scope of IWL-2500, including prestress lift-off measurements, will be required only every 10 years in each unit; except that the visual inspections and anticorrosion medium surveillances of IWL-2524 and IWL-2525 must be repeated at the intervening 5-year intervals.

The program includes randomly selected surveillance tendons for a 40-year license (through the year 35 surveillance). Prior to the period of extended operation, procedures will be enhanced to require an update of the regression analysis for each tendon group of each unit, and of the joint regression of data from all three units, after every tendon surveillance. The documents will invoke and describe regression analysis methods used to construct the lift-off trend lines, including the use of individual tendon data in accordance with IN 99-10, Degradation of Prestressing Tendon Systems in Prestressed Concrete Containments.

3.8 NRC SER Limitations and Conditions 3.8.1 Limitations and Conditions Applicable to NEI 94-01, Revision 2-A The NRC staff found that the use of NEI TR 94-01, Revision 2-A, was acceptable for referencing by licensees proposing to amend their TS to permanently extend the ILRT surveillance interval to 15 years, provided the limitations and conditions listed in Table 3.8.1-1 were satisfied.

Table 3.8.1-1 NEI 94-01, Revision 2-A, Limitations and Conditions Limitation/Condition PVNGS Response (From Section 4.0 of SE)

For calculating the Type A leakage rate, the PVNGS will utilize the definition in NEI 94-licensee should use the definition in the NEI 01, Revision 3-A, Section 5.0. This TR 94-01, Revision 2, in lieu of that in definition has remained unchanged from ANSI/ANS-56.8-2002. (Refer to SE Section Revision 2-A to Revision 3-A of NEI 94-01.

3.1.1.1)

The licensee submits a schedule of Reference Section 3.5.2, Table 3.5.2-1 and containment inspections to be performed Section 3.5.3, Tables 3.5.3-1, 3.5.3-2 and prior to and between Type A tests. (Refer to 3.5.3-3, of this submittal.

SE Section 3.1.1.3)

The licensee addresses the areas of the Reference Sections 3.5.2 and 3.5.3 of this containment structure potentially subjected submittal.

to degradation. (Refer to SE Section 3.1.3)

The licensee addresses any tests and Steam Generator replacements were inspections performed following major performed using the installed equipment modifications to the containment structure, hatches.

as applicable. (Refer to SE Section 3.1.4)

In the Unit 3 Containment, 80'-100' Level, a patch plate was welded over a gouge in the Containment Liner during Unit 3 Spring of 2017 refueling outage (3R18). The repair was then subject to the subsequent 3R18 ILRT.

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Table 3.8.1-1 NEI 94-01, Revision 2-A, Limitations and Conditions Limitation/Condition PVNGS Response (From Section 4.0 of SE)

The normal Type A test interval should be PVNGS will follow the requirements of NEI less than 15 years. If a licensee has to 94-01, Revision 3-A, Section 9.1. This utilize the provision of Section 9.1 of NEI requirement has remained unchanged from TR 94-01, Revision 2, related to extending Revision 2-A to Revision 3-A of NEI 94-01.

the ILRT interval beyond 15 years, the licensee must demonstrate to the NRC staff In accordance with the requirements of NEI that it is an unforeseen emergent condition. 94-01, Revision 2-A, SER Section 3.1.1.2, (Refer to SE Section 3.1.1.2) PVNGS will also demonstrate to the NRC staff that an unforeseen emergent condition exists in the event an extension beyond the 15-year interval is required.

For plants licensed under 10 CFR Part 52, Not applicable. PVNGS was not licensed applications requesting a permanent under 10 CFR Part 52.

extension of the ILRT surveillance interval to 15 years should be deferred until after the construction and testing of containments for that design have been completed and applicants have confirmed the applicability of NEI 94-01, Revision 2, and EPRI Report No. 1009325, Revision 2, including the use of past containment ILRT data.

3.8.2 Limitations and Conditions Applicable to NEI 94-01, Revision 3-A The NRC staff found that the guidance in NEI TR 94-01, Revision 3, was acceptable for referencing by licensees in the implementation of the optional performance-based requirements of Option B to 10 CFR 50, Appendix J. However, the NRC staff identified two conditions on the use of NEI TR 94-01, Revision 3 (Reference NEI 94-01, Revision 3-A, NRC SER 4.0, Limitations and Conditions):

Topical Report Condition 1 NEI TR 94-01, Revision 3, is requesting that the allowable extended interval for Type C LLRTs be increased to 75 months, with a permissible extension (for non-routine emergent conditions) of nine months (84 months total). The staff is allowing the extended interval for Type C LLRTs be increased to 75 months with the requirement that a licensee's post-outage report include the margin between the Type B and Type C leakage rate summation and its regulatory limit. In addition, a corrective action plan shall be developed to restore the margin to an acceptable level. The staff is also allowing the non-routine emergent extension out to 84-months as applied to Type C valves at a site, with some exceptions that must be detailed in NEI TR 94-01, Revision 3. At no time shall an extension be allowed for Type C valves that are restricted categorically [e.g., BWR main steam isolation valves (MSIVs)], and those valves with a history of leakage, or any valves held to either a less than maximum interval or to the base refueling cycle interval. Only non-routine emergent conditions allow an extension to 84 months.

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Response to Condition 1 Condition 1 presents the following three (3) separate issues that are required to be addressed:

 ISSUE 1 - The allowance of an extended interval for Type C LLRTs of 75 months carries the requirement that a licensee's post-outage report include the margin between the Type B and Type C leakage rate summation and its regulatory limit.

 ISSUE 2 - In addition, a corrective action plan shall be developed to restore the margin to an acceptable level.

 ISSUE 3 - Use of the allowed 9-month extension for eligible Type C valves is only authorized for non-routine emergent conditions with exceptions as detailed in NEI 94-01, Revision 3-A, Section 10.1.

Response to Condition 1, ISSUE 1 The post-outage report shall include the margin between the Type B and Type C Minimum Pathway Leak Rate (MNPLR) summation value, as adjusted to include the estimate of applicable Type C leakage understatement, and its regulatory limit of 0.60 La.

Response to Condition 1, ISSUE 2 When the potential leakage understatement adjusted Types B and C MNPLR total is greater than the PVNGS Units 1, 2, and 3, administrative leakage summation limit of 0.5 La, but less than the regulatory limit of 0.6 La, then an analysis and determination of a corrective action plan shall be prepared to restore the leakage summation margin to less than the PVNGS leakage limit. The corrective action plan shall focus on those components which have contributed the most to the increase in the leakage summation value and what manner of timely corrective action, as deemed appropriate, best focuses on the prevention of future component leakage performance issues so as to maintain an acceptable level of margin.

Response to Condition 1, ISSUE 3 PVNGS Units 1, 2, and 3 will apply the 9-month allowable interval extension period only to eligible Type C components and only for non-routine emergent conditions.

Such occurrences will be documented in the record of tests.

Topical Report Condition 2 The basis for acceptability of extending the ILRT interval out to once per 15 years was the enhanced and robust primary containment inspection program and the local leakage rate testing of penetrations. Most of the primary containment leakage experienced has been attributed to penetration leakage and penetrations are thought to be the most likely location of most containment leakage at any time. The containment leakage condition monitoring regime involves a portion of the penetrations being tested each refueling outage, nearly all LLRTs being performed during plant outages. For the purposes of assessing and monitoring or trending overall containment leakage potential, the as-found minimum pathway leakage rates for the just tested penetrations are summed with the as-left minimum pathway 76

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leakage rates for penetrations tested during the previous 1 or 2 or even 3 refueling outages. Type C tests involve valves, which in the aggregate, will show increasing leakage potential due to normal wear and tear, some predictable and some not so predictable. Routine and appropriate maintenance may extend this increasing leakage potential. Allowing for longer intervals between LLRTs means that more leakage rate test results from farther back in time are summed with fewer just tested penetrations and that total is used to assess the current containment leakage potential. This leads to the possibility that the LLRT totals calculated understate the actual leakage potential of the penetrations. Given the required margin included with the performance criterion and the considerable extra margin most plants consistently show with their testing, any understatement of the LLRT total using a 5-year test frequency is thought to be conservatively accounted for. Extending the LLRT intervals beyond 5 years to a 75-month interval should be similarly conservative provided an estimate is made of the potential understatement and its acceptability determined as part of the trending specified in NEI TR 94-01, Revision 3, Section 12.1.

When routinely scheduling any LLRT valve interval beyond 60-months and up to 75-months, the primary containment leakage rate testing program trending or monitoring must include an estimate of the amount of understatement in the Types B and C total leakage and must be included in a licensee's post-outage report. The report must include the reasoning and determination of the acceptability of the extension, demonstrating that the LLRT totals calculated represent the actual leakage potential of the penetrations.

Response to Condition 2 Condition 2 presents the following two (2) separate issues that are required to be addressed:

 ISSUE 1 - Extending the LLRT intervals beyond 5 years to a 75-month interval should be similarly conservative provided an estimate is made of the potential understatement and its acceptability determined as part of the trending specified in NEI TR 94-01, Revision 3, Section 12.1.

 ISSUE 2 - When routinely scheduling any LLRT valve interval beyond 60 months and up to 75 months, the primary containment leakage rate testing program trending or monitoring must include an estimate of the amount of understatement in the Types B and C total and must be included in a licensee's post-outage report. The report must include the reasoning and determination of the acceptability of the extension, demonstrating that the LLRT totals calculated represent the actual leakage potential of the penetrations.

Response to Condition 2, ISSUE 1 The change in going from a 60-month extended test interval for Type C tested components to a 75-month interval, as authorized under NEI 94-01, Revision 3-A, represents an increase of 25% in the LLRT periodicity. As such, PVNGS Units 1, 2, and 3 will conservatively apply a potential leakage understatement adjustment factor of 1.25 to the actual As-Left leak rate, which will increase the As-Left leakage total for each Type C component currently on greater than a 60-month test interval up to the 75-month extended test interval. This will result in a combined conservative Type C total for all 75-month LLRTs being "carried forward" and will be included whenever 77

Enclosure Evaluation of the Proposed Change



the total leakage summation is required to be updated (either while on-line or following an outage).

When the potential leakage understatement adjusted leak rate total for those Type C components being tested on greater than a 60-month test interval up to the 75-month extended test interval is summed with the non-adjusted total of those Type C components being tested at less than or equal to a 60-month test interval, and the total of the Type B tested components, results in the MNPLR being greater than the PVNGS administrative leakage summation limit of 0.50 La, but less than the regulatory limit of 0.6 La, then an analysis and corrective action plan shall be prepared to restore the leakage summation value to less than the PVNGS leakage limit. The corrective action plan should focus on those components which have contributed the most to the increase in the leakage summation value and what manner of timely corrective action, as deemed appropriate, best focuses on the prevention of future component leakage performance issues.

Response to Condition 2, ISSUE 2 If the potential leakage understatement adjusted leak rate MNPLR is less than the PVNGS administrative leakage summation limit of 0.50 La, then the acceptability of the greater than a 60-month test interval up to the 75-month LLRT extension for all affected Type C components has been adequately demonstrated and the calculated local leak rate total represents the actual leakage potential of the penetrations.

In addition to Condition 1, ISSUES 1 and 2, which deal with the MNPLR Types B and C summation margin, NEI 94-01, Revision 3-A, also has a margin-related requirement as contained in Section 12.1, Report Requirements.

A post-outage report shall be prepared presenting results of the previous cycles Type B and Type C tests, and Type A, Type B and Type C tests, if performed during that outage. The technical contents of the report are generally described in ANSI/ANS-56.8-2002 and shall be available on-site for NRC review. The report shall show that the applicable performance criteria are met and serve as a record that continuing performance is acceptable. The report shall also include the combined Type B and Type C leakage summation, and the margin between the Type B and Type C leakage rate summation and its regulatory limit. Adverse trends in the Type B and Type C leakage rate summation shall be identified in the report and a corrective action plan developed to restore the margin to an acceptable level.

At PVNGS, in the event an adverse trend in the aforementioned potential leakage understatement adjusted Types B and C summation is identified, then an analysis and determination of a corrective action plan shall be prepared to restore the trend and associated margin to an acceptable level. The corrective action plan shall focus on those components, which have contributed the most to the adverse trend in the leakage summation value and what manner of timely corrective action, as deemed appropriate, best focuses on the prevention of future component leakage performance issues.

At PVNGS, an adverse trend is defined as three (3) consecutive increases in the final pre-mode change Types B and C MNPLR leakage summation values, as adjusted to include the estimate of applicable Type C leakage understatement, as expressed in terms of La.

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3.9 Conclusion NEI 94-01, Revision 3-A, dated July 2012, and the limitations and conditions specified in NEI 94-01, Revision 2-A, dated October 2008, describe an NRC-accepted approach for implementing the performance-based requirements of 10 CFR 50, Appendix J, Option B. It incorporated the regulatory positions stated in RG 1.163 and includes provisions for extending Type A intervals to 15 years and Type C test intervals to 75 months. NEI 94-01, Revision 3-A, delineates a performance-based approach for determining Type A, Type B, and Type C containment leakage rate surveillance test frequencies. PVNGS is adopting the guidance of NEI 94-01, Revision 3-A, and the limitations and conditions specified in NEI 94-01, Revision 2-A, for the PVNGS Units 1, 2, and 3, 10 CFR 50, Appendix J testing program plan.

Based on the previous ILRTs conducted at PVNGS Units 1, 2, and 3, APS concludes that the permanent extension of the containment ILRT interval from 10 to 15 years represents minimal risk to increased leakage. The risk is minimized by continued Type B and Type C testing performed in accordance with Option B of 10 CFR 50, Appendix J, and the overlapping inspection activities performed as part of the following PVNGS inspection programs:

 Containment Inservice Inspection Program, Subsection IWE

 Containment Inservice Inspection Program, Subsection IWL

 PVNGS Coatings Program This experience is supplemented by risk analysis studies, including the PVNGS risk analysis provided in Attachment 1. The risk assessment concludes that increasing the ILRT interval on a permanent basis to a one-in-fifteen-year frequency is not considered to be significant because it represents only a small change in the PVNGS risk profile.

4.0 REGULATORY ANALYSIS

4.1 APPLICABLE REGULATORY REQUIREMENTS/CRITERIA The proposed change has been evaluated to determine whether applicable regulations and requirements continue to be met.

10 CFR 50.54(o) requires primary reactor containments for water-cooled power reactors to be subject to the requirements of Appendix J to 10 CFR 50, Leakage Rate Testing of Containment of Water Cooled Nuclear Power Plants. Appendix J specifies containment leakage testing requirements, including the types required to ensure the leak-tight integrity of the primary reactor containment and systems and components which penetrate the containment. In addition, Appendix J discusses leakage rate acceptance criteria, test methodology, frequency of testing and reporting requirements for each type of test.

The adoption of the Option B performance-based containment leakage rate testing for Type A, Type B and Type C testing did not alter the basic method by which Appendix J leakage rate testing is performed; however, it did alter the frequency at which Type A, Type B, and Type C containment leakage tests must be performed. Under the performance-based option of 10 CFR 50, Appendix J, the test frequency is based upon an evaluation that reviewed "as-found" leakage history to determine the frequency for leakage testing which provides assurance that leakage limits will be maintained. The 79

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change to the Type A test frequency did not directly result in an increase in containment leakage. Similarly, the proposed change to the Type C test frequencies will not directly result in an increase in containment leakage.

EPRI TR-1009325, Revision 2-A (Reference 11), provided a risk impact assessment for optimized ILRT intervals up to 15 years, utilizing current industry performance data and risk informed guidance. NEI 94-01, Revision 3-A, Section 9.2.3.1 (Reference 2), states that Type A ILRT intervals of up to 15 years are allowed by this guideline. EPRI Technical Report 1018243 (formerly TR-1009325, Revision 2-A), Risk Impact Assessment of Extended Integrated Leak Rate Testing Intervals, indicates that, in general, the risk impact associated with ILRT interval extensions for intervals up to 15 years is small. However, plant-specific confirmatory analyses are required.

The NRC staff reviewed NEI TR 94-01, Revision 2, and EPRI Report No. 1009325, Revision 2. For NEI TR 94-01, Revision 2, the NRC staff determined that it described an acceptable approach for implementing the optional performance-based requirements of Option B to 10 CFR 50, Appendix J. This guidance includes provisions for extending Type A ILRT intervals up to 15 years and incorporates the regulatory positions stated in RG 1.163. The NRC staff finds that the Type A testing methodology, as described in ANSI/ANS-56.8-2002 (Reference 37), and the modified testing frequencies recommended by NEI TR 94-01, Revision 2, serve to ensure continued leakage integrity of the containment structure. Type B and Type C testing ensures that individual penetrations are essentially leak tight. In addition, aggregate Type B and Type C leakage rates support the leakage tightness of primary containment by minimizing potential leakage paths.

For EPRI Report No. 1009325, Revision 2, a risk-informed methodology using plant-specific risk insights and industry ILRT performance data to revise ILRT surveillance frequencies, the NRC staff finds that the proposed methodology satisfies the key principles of risk-informed decision making applied to changes to TS as delineated in RG 1.174 (Reference 3) and RG 1.177, An Approach for Plant-Specific, Risk-Informed Decision making: Technical Specifications (Reference 42). The NRC staff, therefore, found that this guidance was acceptable for referencing by licensees proposing to amend their TS in regard to containment leakage rate testing, subject to the limitations and conditions noted in Section 4.2 of the SE.

The NRC staff reviewed NEI TR 94-01, Revision 3, and determined that it described an acceptable approach for implementing the optional performance-based requirements of Option B to 10 CFR 50, Appendix J, as modified by the limitations and conditions summarized in Section 4.0 of the associated SE. This guidance included provisions for extending Type C LLRT intervals up to 75 months. Type C testing ensures that individual CIVs are essentially leak tight. In addition, aggregate Type C leakage rates support the leakage tightness of primary containment by minimizing potential leakage paths. The NRC staff, therefore, found that this guidance, as modified to include two limitations and conditions, was acceptable for referencing by licensees proposing to amend their TS in regard to containment leakage rate testing. Any applicant may reference NEI TR 94-01, Revision 3, as modified by the associated SER and approved by the NRC, and the limitations and conditions specified in NEI 94-01, Revision 2-A, dated October 2008, in a licensing action to satisfy the requirements of Option B to 10 CFR 50, Appendix J.



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4.2 PRECEDENT This LAR is similar in nature to the following license amendments to extend the Type A Test Frequency to 15 years and the Type C test frequency to 75 months as previously authorized by the NRC in the associated referenced SERs:

 McGuire Nuclear Station, Units 1 and 2, issued January 31, 2018 (Reference 24 - ML18009A842)

 Vogtle Electric Generating Plant, Units 1 and 2, issued October 29, 2018 (Reference 25 - ML18263A039)

 Braidwood Station, Units 1 and 2, and Byron Station, Units 1 and 2, issued September 10, 2020 (Reference 31 - ML20149K698) 4.3 NO SIGNIFICANT HAZARDS CONSIDERATION DETERMINATION Arizona Public Service Company (APS) proposes to amend the Technical Specifications (TS) for Palo Verde Nuclear Generating Station (PVNGS) Units 1, 2, and 3, to allow extension of the Type A and Type C leakage test intervals. The extension is based on the adoption of the Nuclear Energy Institute (NEI) 94-01, Industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50, Appendix J, Revision 3-A, and the limitations and conditions set forth in Revision 2-A.

Specifically, the proposed change revises PVNGS TS 5.5.16, Containment Leakage Rate Testing Program, paragraph a., by replacing the reference to Regulatory Guide (RG) 1.163, Performance-Based Containment Leak-Test Program, with a reference to NEI 94-01, Revision 3-A, and the limitations and conditions specified in NEI 94-01, Revision 2-A.

APS has evaluated whether or not a significant hazards consideration is involved with the proposed amendment by focusing on the three standards set forth in 10 CFR 50.92, Issuance of amendment, as discussed below:

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

Response: No.

The proposed activity involves the revision of Palo Verde Nuclear Generating Station (PVNGS), Units 1, 2, and 3, Technical Specification (TS) Section 5.5.16, Containment Leakage Rate Testing Program, to allow the extension of the Type A integrated leakage rate test (ILRT) containment test interval to 15 years, and the extension of the Type C local leakage rate test (LLRT) interval to 75 months. The current Type A test interval of 120 months (10 years) would be extended on a permanent basis to no longer than 15 years from the last Type A test. The current Type C test interval of 60 months for selected components would be extended on a performance basis to no longer than 75 months. Extensions of up to nine months (total maximum interval of 84 months for Type C tests) are permissible only for non-routine emergent conditions.

The proposed test interval extensions do not involve either a physical change to the plant or a change in the manner in which the plant is operated or controlled.

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The containment is designed to provide an essentially leak tight barrier against the uncontrolled release of radioactivity to the environment for postulated accidents. As such, the containment and the testing requirements invoked to periodically demonstrate the integrity of the containment exist to ensure the plant's ability to mitigate the consequences of an accident, and do not involve the prevention or identification of any precursors of an accident. Therefore, this proposed extension does not involve a significant increase in the probability of an accident previously evaluated.

The change in Type A test frequency to once-per-fifteen years, measured as an increase to the total integrated plant risk for those accident sequences influenced by Type A testing, based on the internal events (IE) probabilistic risk analysis (PRA) is 0.12 person-rem/year for Units 1, 2, and 3. Electric Power Research Institute (EPRI) Report No. 1009325, Revision 2-A, states that a very small population dose is defined as an increase of 1.0 person-rem per year or 1%

of the total population dose, whichever is less restrictive for the risk impact assessment of the extended ILRT intervals. This is consistent with the Nuclear Regulatory Commission (NRC) Final Safety Evaluation for Nuclear Energy Institute (NEI) 94-01 and EPRI Report No. 1009325. Moreover, the risk impact when compared to other severe accident risks is negligible.

In addition, as documented in NUREG-1493, Performance-Based Containment Leak-Test Program, dated September 1995, Types B and C tests have identified a very large percentage of containment leakage paths, and the percentage of containment leakage paths that are detected only by Type A testing is very small.

The PVNGS Type A test history supports this conclusion.

The integrity of the containment is subject to two types of failure mechanisms that can be categorized as: (1) activity based, and (2) time based. Activity-based failure mechanisms are defined as degradation due to system and/or component modifications or maintenance. The LLRT requirements and administrative controls such as configuration management and procedural requirements for system restoration ensure that containment integrity is not degraded by plant modifications or maintenance activities. The design and construction requirements of the containment combined with the containment inspections performed in accordance with American Society of Mechanical Engineers (ASME)

Boiler and Pressure Vessel (BPV) Code,Section XI, Rules for Inservice Inspection of Nuclear Power Plant Components; Containment Coatings Program; and TS requirements, serve to provide a high degree of assurance that the containment would not degrade in a manner that is detectable only by a Type A test. Based on the above, the proposed test interval extensions do not significantly increase the consequences of an accident previously evaluated.

The proposed amendment also deletes the exceptions provided in TS 5.5.16.a, items 3-5, which were previously granted under TS Amendment No. 176

[Agencywide Documents Access Management System (ADAMS) Accession No. ML092810317, dated October 20, 2009] to allow one-time extensions of the ILRT test frequency for PVNGS Units 1, 2, and 3. These exceptions were for activities that have already taken place; therefore, their deletion is solely an administrative action that has no effect on any component and no impact on how the unit is operated.

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Therefore, the proposed change does not result in a significant increase in the probability or consequences of an accident previously evaluated.

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

Response: No.

The proposed amendment to the TS 5.5.16, Containment Leakage Rate Testing Program, paragraph a., involves the extension of the PVNGS Type A containment test interval to 15 years and the extension of the Type C test interval to 75 months. The containment and the testing requirements to periodically demonstrate the integrity of the containment exist to ensure the plants ability to mitigate the consequences of an accident do not involve any accident precursors or initiators. The proposed change does not involve a physical change to the plant (i.e., no new or different type of equipment will be installed) nor does it alter the design, configuration, or change the manner in which the plant is operated or controlled beyond the standard functional capabilities of the equipment.

The proposed amendment also deletes the exceptions provided in TS 5.5.16.a.,

items 3-5, which were previously granted under TS Amendment No. 176 to allow one-time extensions of the ILRT test frequency for PVNGS Units 1, 2, and 3.

These exceptions were for activities that have already taken place; therefore, their deletion is solely an administrative action that does not result in any change in how the unit is operated or controlled.

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

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

Response: No.

The proposed amendment to the PVNGS TS 5.5.16.a. involves the extension of the PVNGS Type A containment test interval to 15 years and the extension of the Type C test interval to 75 months for selected components. This amendment does not alter the manner in which safety limits, limiting safety system set points, or limiting conditions for operation are determined. The specific requirements and conditions of the TS Containment Leak Rate Testing Program exist to ensure that the degree of containment structural integrity and leak tightness that is considered in the plant safety analysis is maintained. The overall containment leak rate limit specified by TS is maintained.

The proposed change involves only the extension of the interval between Type A containment leak rate tests and Type C tests for PVNGS Units 1, 2, and 3. The proposed surveillance interval extension is bounded by the 15-year ILRT interval and the 75-month Type C test interval currently authorized within NEI 94-01, Revision 3-A. Industry experience supports the conclusions that Types B and C testing detects a large percentage of containment leakage paths and that the percentage of containment leakage paths that are detected only by Type A testing is small. The containment inspections performed in accordance with ASME Section Xl, Containment Coatings Program; and TS serve to provide a high degree of assurance that the containment would not degrade in a manner that is detectable 83

Enclosure Evaluation of the Proposed Change



only by Type A testing. The combination of these factors ensures that the margin of safety in the plant safety analysis is maintained. The design, operation, testing methods and acceptance criteria for Types A, B, and C containment leakage tests specified in applicable codes and standards would continue to be met, with the acceptance of this proposed change, since these are not affected by changes to the Type A and Type C test intervals.

The proposed amendment also deletes exceptions provided in TS 5.5.16.a, previously granted under TS Amendment No. 176 to allow one-time extensions of the ILRT test frequency for PVNGS Units 1, 2, and 3. These exceptions were for activities that have already taken place; therefore, the deletion is solely an administrative action and does not change how the unit is operated and maintained. Thus, there is no reduction in any margin of safety as a result of this administrative change.

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

Based on the above, APS concludes that the proposed amendment does not involve a significant hazards consideration under the standards set forth in 10 CFR 50.92(c),

and, accordingly, a finding of no significant hazards consideration is justified.

4.4 CONCLUSION

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

5.0 ENVIRONMENTAL CONSIDERATION

A review has determined that the proposed amendment would change a requirement with respect to installation or use of a facility component located within the restricted area, as defined in 10 CFR 20, or would change an inspection or surveillance requirement. However, the proposed amendment does not involve (i) a significant hazards consideration, (ii) a significant change in the types or significant increase in the amounts of any effluent that may be released offsite, or (iii) a significant increase in individual or cumulative occupational radiation exposure. Accordingly, the proposed amendment meets the eligibility criterion for categorical exclusion set forth in 10 CFR 51.22(c)(9). Therefore, pursuant to 10 CFR 51.22(b), no environmental impact statement or environmental assessment need be prepared in connection with the proposed amendment.

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6.0 REFERENCES

1. Regulatory Guide 1.163, Performance-Based Containment Leak-Test Program, September 1995 (ML003740058)

2. NEI 94-01, Revision 3-A, Industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50, Appendix J, July 2012 (ML12221A202)

3. RG 1.174, Revision 3, An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis, January 2018 (ML17317A256)

4. RG 1.200, Revision 2, An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities, March 2009 (ML090410014)

5. NEI 94-01, Revision 0, Industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50, Appendix J, dated July 21, 1995 (ML11327A025)

6. NUREG-1493, Performance-Based Containment Leak-Test Program - Final Report, September 1995 (ML20098D498)

7. Electric Power Research Institute (EPRI) Topical Report No. 104285, Risk Impact Assessment of Revised Containment Leak Rate Testing Intervals, Palo Alto, California, August 1994

8. NEI 94-01, Revision 2-A, Industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50, Appendix J, October 2008 (ML100620847)

9. Letter from NRC (M. J. Maxin) to NEI (J. C. Butler), Final Safety Evaluation for Nuclear Energy Institute (NEI) Topical Report (TR) 94-01, Revision 2, Industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50, Appendix J, and Electric Power Research Institute (EPRI) Report No. 1009325, Revision 2, August 2007, Risk Impact Assessment of Extended Integrated Leak Rate Testing Intervals (TAC No. MC9663), dated June 25, 2008 (ML081140105)

10. Letter from NRC (S. Bahadur) to NEI (B. Bradley), Final Safety Evaluation of Nuclear Energy Institute (NEI) Report, 94-01, Revision 3, Industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50, Appendix J (TAC No. ME2164), dated June 8, 2012 (ML121030286)

11. EPRI TR-1018243, Risk Impact Assessment of Extended Integrated Leak Rate Testing Intervals: Revision 2-A of 1009325, October 2008

12. Letter from NRC (C. R. Thomas) to Arizona Public Service Company (W. L.

Stewart), Issuance of Amendments [Nos. 103, 92, and 75] for the Palo Verde Nuclear Generating Station Unit No. 1 (TAC No. M94295), Unit No. 2 (TAC No.

M94296), and Unit No. 3 (TAC No. M94297), dated February 23, 1996 (ML021710536)

13. Letter from NRC (K. M. Thomas) to Arizona Public Service Company (J. M.

Levine), Issuance of Amendments [Nos. 113, 106, and 85] for the Palo Verde Nuclear Generating Station Unit No. 1 (TAC No. M97524), Unit No. 2 (TAC No.

85

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M97525), and Unit No. 3 (TAC No. M97526), dated September 11, 1997 (ML021710675)

14. Letter from NRC (B. M. Pham) to Arizona Public Service Company (G. R.

Overbeck), Palo Verde Nuclear Generating Station, Unit 2 (PVNGS-2) - Issuance of Amendment [No. 149] on Replacement of Steam Generators and Uprated Power Operations (TAC No. MB3696), dated September 29, 2003 (ML032720538)

15. Letter from NRC (M. Khanna) to Arizona Public Service Company (G. R.

Overbeck), Palo Verde Nuclear Generating Station, Units 1, 2, and 3 - Issuance of Amendment [No. 151] on Containment Tendon Surveillance Program and Containment Leakage Rate Testing Program (TAC Nos. MC1069, MC1070, and MC1071), dated March 19, 2004 (ML040850657)

16. Letter from NRC (M. B. Fields) to Arizona Public Service Company (J. M. Levine),

Palo Verde Nuclear Generating Station, Units 1, 2, and 3 - Issuance of Amendments [Nos. 157] Re: Replacement of Steam Generators and Uprated Power Operations and Associated Administrative Changes (TAC Nos. MC3777, MC3778, and MC3779), dated November 16, 2005 (ML053130275)

17. Letter from NRC (J. R. Hall) to Arizona Public Service Company (R. K. Edington),

Palo Verde Nuclear Generating Station, Units 1, 2, and 3 - Issuance of Amendments [No. 176] Re: Revision to Technical Specification 5.5.16, Containment Leakage Rate Testing Program (TAC Nos. MD9807, MD9808, and MD9809), dated October 20, 2009 (ML092810317)

18. Letter from NRC (B. K. Singal) to Arizona Public Service Company (R. K.

Edington), Palo Verde Nuclear Generating Station, Units 1, 2, and 3 - Issuance of Amendments [Nos. 189] Re: Request for Amendment to Various Technical Specifications to Implement Administrative Changes (TAC Nos. ME7621, ME7622, and ME7623), dated June 18, 2012 (ML120860092)

19. NUREG-2122, Glossary of Risk-Related Terms in Support of Risk-Informed Decision Making, dated November 2013 (ML13311A353)

20. Interim Guidance for Performing Risk Impact Assessments In Support of One-Time Extensions for Containment Integrated Leakage Rate Test Surveillance Intervals, Rev. 4, Developed for NEI by EPRI and Data Systems and Solutions, November 2001.

21. RG 1.200, Revision 0, An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities, February 2004 (ML040630078)

22. RG 1.147, Inservice Inspection Code Case Acceptability, ASME Section XI, Division 1, Revision 17, August 2014 (ML13339A689)

23. NUREG-1961, Safety Evaluation Report Related to the License Renewal of Palo Verde Nuclear Generating Station, Units 1, 2, and 3, issued April 2011

24. Letter from NRC (M. Mahoney) to Duke Energy (T. D. Ray), McGuire Nuclear Station, Units 1 and 2 - Issuance of Amendments to Extend the Containment 86

Enclosure Evaluation of the Proposed Change



Type A Leak Rate Test Frequency to 15 Years and Type C Leak Rate Test Frequency to 75 Months (CAC Nos. MF9020 and MF9021; EPID L-2016-LLA-0032), dated January 31, 2018 (ML18009A842)

25. Letter from NRC (M. Orenak) to Southern Nuclear Operating Company, Inc. (C.

A. Gayheart), Vogtle Electric Generating Plant, Units 1 and 2, Issuance of Amendments to Extend the Containment Type A Leak Rate Test Frequency to 15 Years and Type C Leak Rate Test Frequency to 75 Months (CAC Nos. MG0240 and MG0241; EPID L-2017-LLA-0295), dated October 29, 2018 (ML18263A039)

26. Regulatory Guide 1.11, Revision 0, Instrument Lines Penetrating the Primary Reactor Containment

27. ANSI N18.2-1973, Nuclear Safety Criteria for the Design of Stationary Pressurized Water Reactor Plants

28. Regulatory Guide 1.29, Seismic Design Classification

29. ABS Consulting, Palo Verde Generating Station Probabilistic Risk Assessment Focused-Scope Peer Review, R-4369996-2141, June 23, 2020.

30. ABS Consulting Report R-3882824-2037, Palo Verde Generating Stations PRA Finding Level Fact and Observation Closure Review, June 23, 2017.

31. Letter from NRC (J. S. Wiebe) to Exelon Generation Co. (B. C. Hanson),

Braidwood Station, Units 1 and 2, and Byron Station, Unit Nos. 1 and 2 -

Issuance of Amendment Nos. 215, 215, 219, And 219 Re: Permanent Extension of Type A and Type C Containment Leak Rate Test Frequencies (EPID L-2019-LLA-0208), dated September 10, 2020 (ML20149K698)

32. Letter from Constellation Nuclear (C. H. Cruse) to NRC (Document Control Desk), Calvert Cliffs Nuclear Power Plant, Unit No. 1; Docket No. 50-317 -

Response to Request for Additional Information Concerning the License Amendment Request for a One-Time Integrated Leakage Rate Test Extension, dated March 27, 2002 (ML020920100)

33. ASME/ANS RA-Sa-2009, Addenda to ASME/ANS RA-S-2008, Standard for Level 1/Large Early Release Frequency Probabilistic Risk Assessment for Nuclear Power Plant Applications, dated February 2009.

34. Palo Verde Nuclear Generating Station, Units 1, 2, and 3, Issuance of Amendments Re: Adoption of TSTF-425, Revision 3, Relocate Surveillance Frequencies to Licensee Control RITSTF Initiative 5b (ADAMS Accession Number ML112620293), dated December 15, 2011

35. Palo Verde Nuclear Generating Station, Units 1, 2, and 3, Issuance of Amendments Re: Changes To Technical Specification 3.8.7, Inverters-Operating (ADAMS Accession Number ML102670352), dated September 29, 2010

36. Relief Request 66 - Unit 2, Request for Relief from Containment Tendon Inspections dated November 5, 2020 (ADAMS Accession Number ML20315A156) 87

Enclosure Evaluation of the Proposed Change



37. American Nuclear Society, ANSI/ANS 56.8-2002, Containment System Leakage Testing Requirements, LaGrange Park, Illinois, November 2002

38. ASME B&PV Code,Section XI, Subsection IWE, Requirements for Class MC and Metallic Liners of Class CC Components of Light-Water Cooled Plants

39. ASME B&PV Code,Section XI, Subsection IWL, Requirements for Class CC Concrete Components of Light-Water Cooled Plant

40. NRR Email Capture, Palo Verde 2 -Verbal Authorization of RR 66 to Extend Containment Tendon Inspection by One Year Based on 10 CFR 50.55a(Z)(2) dated November 19, 2020 (EPID L-2020-LLR-0145) (ADAMS Accession Number ML20325A039)

41. ABS Consulting, Palo Verde Generating Station Probabilistic Risk Assessment Focused-Scope Peer Review, R-4076030-2073, June 21, 2018.

42. RG 1.177, An Approach for Plant-Specific, Risk-Informed Decisionmaking:

Technical Specifications, Revision 1, May 2011 (ML100910008)

43. NEI 12-13, External Hazards PRA Peer Review Process Guidelines, August 2012 (ML12240A027)

44. ABS Consulting, Palo Verde Generating Station Probabilistic Risk Assessment Finding Level Fact and Observation Closure Review, R-3882824-2037, June 25, 2018.

45. ABS Consulting, Palo Verde Generating Station Probabilistic Risk Assessment Finding Level Fact and Observation Closure Review, R-4369996-2142, June 23, 2020.

46. RG 1.200, Revision 3, Acceptability of Probabilistic Risk Assessment Results for Risk-Informed Activities, December 2020 (ML20238B871) 88

Enclosure Attachment 1 Evaluation of the Proposed Change



ATTACHMENT 1:

Evaluation of Risk Significance of Permanent ILRT Extension







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Enclosure Attachment 4 Evaluation of the Proposed Change



ATTACHMENT 4:

Results of Recent Containment Examinations



Enclosure Attachment 4 Evaluation of the Proposed Change



Assessment of the PVNGS Unit 2 Containment Coatings in 2R22, April 2020 Coronavirus Disease 2019 (COVID-19)

Due to the COVID-19 pandemic during Unit 2 Spring of 2020 refueling outage (2R22),

the physical assessment of the Unit 2 containment building was abbreviated. The majority of the coating damage in the PVNGS containment buildings is due to mechanical damage from mishandling of tools and equipment or improper storage of sharp items along the containment liner plate. It was decided not to do a high radiation area (high rad) entry into the pump bays and behind the bio-shield wall as these are low traffic areas and the coating in these areas is rarely damaged. Instead, the time allotted for this assessment was spent inspecting outside the bio-shield wall on all elevations.

2R22 General Comments The coating work performed during the past outages by PVNGS coaters is in all cases workmanlike and continues to exhibit good visual quality, with the exception of small areas of mechanical damage. The damage that is listed below is from poor treatment (mechanical damage, spills that were not cleaned up, etc.) rather than the coatings failing or showing signs of poor application. Hence, most of the damage to the containment coatings could have been prevented through better housekeeping or more care in transporting scaffolding, storing equipment, etc.

Unit 2 Spring of 2020 refueling outage (2R22) saw the beginning of the containment liner plate being protected from mechanical damage due to storage of sharp objects against the containment liner plate. The insulators placed padded blue plastic along the liner plate. This plastic was held in place by magnets rather than tape as the residue tape leaves behind eventually damages the coating. This is a big step for PVNGS, as recorded above, the majority of damage to the liner plate coating and the steel of the liner could be prevented with this type of measure.

ISI does not re-inspect the rust areas on the liner plate that have a number on them.

These areas were inspected at some earlier date and have been considered acceptable.

Wormtrails that were marked with a sharpie during previous outages do not appear to have degraded further. These are not scheduled for repair because prior dry film thickness (DFT) readings show that there is still inorganic zinc coating (IOZ) left in these areas.

Every single defect in the coating in Unit 2 is not recorded in this submittal There are literally hundreds of thousands of areas of mechanical damage to the coating. During these walk downs, an underline or circle, was made with a black Sharpie, identifying scratches which are particularly deep, or areas that look to be scraped down to bare steel or areas where rust is starting to appear. Also, areas are underlined where there is a great deal of minor mechanical damage, as these areas could get enveloped in rust once corrosion starts. Not all of these areas are photographed and entered into this submittal if the damage to the coating is minor. Rather the markings with Sharpie help the inspectors to check on these areas and monitor them from outage to outage.

White spills on Containment Liner Plate - the areas where there is white staining are monitored in containment as these areas are subject to zinc depletion. The liner plate sections were coated with IOZ prior to installation at PVNGS. During installation, the 1



Enclosure Attachment 4 Evaluation of the Proposed Change



sections of the liner were welded together, then areas of bare steel and welds were coated with epoxy coating.

The zinc coating protects the steel in two ways. It serves as a barrier between the steel and the environment. It also protects the steel electrochemically due to its position in the galvanic series as it corrodes preferentially before steel. When boric acid or other harsh chemicals are spilled on the inorganic zinc coating, the chemical corrosion process begins. The zinc becomes a sacrificial anode that corrodes preferentially and prevents corrosion of the steel. Zinc depletion is the consumption of the zinc surrounding exposed carbon steel until no zinc remains, thus removing the protection from the carbon steel and allowing the carbon steel to corrode. These areas transform from white to a light rust color and eventually to a deeper rust color.

The color in these areas is indicative of the amount of rust present, hence the degree of corrosion. Due to the high temperatures and dry atmosphere of containment during operation, the corrosion process is normally very slow unless it is exacerbated by chemicals or moisture leaks.

In general, the containment was very dark during 2R22. Because of the reduced work scope in this outage due to the COVID-19 pandemic, many of the overhead lights were not on. Rather, they were just lighting the areas where specific work was being done. Because of this it was difficult to get good photographs. The assessment was completed successfully using a flashlight, but some of the photos had to be taken from previous Unit 2 outages.

Reactor Coolant Pump (RCP) Bays foot Elevation The pump bays were not entered and assessed this outage.

80-foot entrance to 2A RCP Bay staining on walls and structural steel; must be from a boric acid leak on the 90-foot elevation. The floor was cleaned but not the wall or steel.

2B RCP Bay Black spill on floor coating at the top of the stairs. Unclear if it may have damaged the floor coating. Check this area in Unit 2 Fall of 2021 refueling outage (2R23).

Lube Oil Tank Room between RCP Bays 2B and 1A Everything looks good in the Lube Oil Tank Room at the 80-foot elevation. There is some minor white staining on the concrete ceiling above the tanks. Nothing seen weeping or dripping through the concrete ceiling and no residue on the tanks to indicate leaking from the ceiling.

80-foot Elevation There are not as many wormtrails on the 80-foot elevation as compared to the other elevations of Unit 2.

0-degrees - Mechanical damage with small amount of rust above first weld. There is rust staining around the area, but no rust on the exposed steel of the liner plate.

Keep on Unit 2 Containment Coatings Watch List.

5-degrees - Large area where graffiti has been scrapped off with some sort of abrasive. This has done more damage to the coating on the liner plate than if the graffiti had been left intact. There is still enough inorganic zinc left in this area to protect the liner, but it will be kept on the Unit 2 Containment Coatings Watch List.

2



Enclosure Attachment 4 Evaluation of the Proposed Change



10 & 13 degrees - Two new white spills, very little rust. Keep on Unit 2 Watch List.

40 & 50 degrees - Two white spills on liner unchanged since Unit 2 Spring of 2017 refueling outage (2R20). Keep on Unit 2 Containment Coatings Watch List.

85-degrees - (from 90 ft platform) Penetration 75 has epoxy on the penetration and on the liner plate rather than inorganic zinc. The epoxy is not on the pipe, which is the highest temperature area, but rather just on the base on the penetration, so it may not degrade. First discovered in Unit 2 Fall of 2016 refueling outage (2R19),

almost no change in the coating since then. Keep on Unit 2 Containment Coatings Watch List.

110-degrees - Boric acid leak on floor coating just outside t-wall. Unchanged since Unit 2 Fall of 2018 refueling outage (2R21). Keep on Unit 2 Containment Coatings Watch List.

110-150 degrees - Areas where Carboguard 890N was used to repair small defects in the liner coating. This was done prior to GSI-191 when if the repair was less than 30 sq. inches it did not have to be reported as unqualified coating. So, small areas like this were repaired with very little surface preparation. Despite this, the coating is still in very good condition and has not degraded or detached in these areas.

150-degrees - During the operating cycle prior to 2R21, water/boric acid from a valve on the 90 ft elevation sprayed the liner plate and dripped down through the grating.

The valve or vent on the 90 ft was bagged with a plastic cover and taped up, presumably to prevent the leak from hitting the liner plate, which was unsuccessful.

ISI inspected the liner during 2R21 and stated that there is no degradation of the liner, it is staining from the rusting of the structural steel on the 90-foot elevation. It is important that the liner plate and structural steel are cleaned and recoated as the boric acid remaining will continue to degrade the coating and the steel. Corrective maintenance work order (CMWO) was generated to recoat these areas during 2R22.

This work was postponed in the reduced work scope of 2R22 due to the COVID-19 pandemic.

220-245 degrees - Several wormtrails on liner plate near the floor. No rust at this time. Keep on Unit 2 Containment Coatings Watch List.

220 - 230 degrees - Scrape marks around first weld have been coated over. No degradation of coating but it is uncertain what might have caused this. It has been like this for many years as evidenced by the color of the coating. Keep on Unit 2 Containment Coatings Watch List.

245-degrees - Mechanical damage near floor. Very little rust present. Keep on Unit 2 Containment Coatings Watch List.

250-degrees - Alligatoring of coating on liner plate. This is probably due to excessive DFT of the IOZ and has probably appeared as the heating and cooling of containment over the years has put stress on the surface of the coating. It does not appear to be delaminating at this time, nor does it seem to degrade further from outage to outage.

This area will be kept on the Unit 2 Containment Coatings Watch List.

3



Enclosure Attachment 4 Evaluation of the Proposed Change



310 to 315 degrees - There are a number of wormtrails on liner below the first weld, across from the door to the 1A RCP Bay. The rest of the 80-foot elevation does not have many wormtrails. This is an area where the original inorganic zinc coating was put on too thick, causing the wormtrails to develop over time.

310 to 335 degrees - Concrete floor and coating damage outside 1A RCP Bay. There are a number of locations of damage in this area. Keep on Unit 2 Containment Coatings Watch List to monitor, but no action required.

325-345 degrees - Insulators have properly protected the liner plate in this area with padded plastic tarps and using magnets to secure it rather than tape.

325-degrees - Small area of mechanical damage on liner plate approximately three-eighths of an inch in diameter was discovered during 2R20 Containment Coating Assessment. A small amount of steel has peeled back from the area and is still attached. Generated condition report (CR) - engineering work request (EWR) to Engineering Inspections to determine if the damage is acceptable. Visual Examination Report 17-VT-2013 states that the condition of this area is acceptable. CMWO was generated to smooth out the area and recoat it during 2R21, CMWO was moved out to 2R22, then moved again in the reduced work scope of 2R22 due to the Covid-19 pandemic.

345-degrees - Crack in floor and epoxy floor coating. No change in 2R22.

355-degrees - White spill unchanged. Keep on Unit 2 Containment Coatings Watch List.

90-foot Elevation Liner plate coating and structural steel coating at 90-foot elevation is in good condition with very little mechanical damage. This is a less traveled area and scaffolding is not being shuffled around as much on this elevation. Very little coating damage on 90-foot elevation.

20-degrees - cracked epoxy coating on pipe support for SG 002 (DCID 2SG002H006-T), visible from the platform on the 80 ft elevation. Areas are approximately 12 inches x 8 inches and 14 inches x 4 inches. CR was generated to document this unqualified coating. CMWO has been generated to have the area recoated. This area was evaluated in engineering evaluation (ENG-EVAL) and will be added to the Unit 2 Unqualified Coatings Log until the condition is corrected.

90-degrees - There is an area of rust behind the T-wall, visible from the 90-foot elevation platform. Keep on Unit 2 Containment Coatings Watch List.

190-degrees - Two areas of mechanical damage on liner coating, one is higher than the other. Very little rust in these areas. Both areas have been marked and have been placed on the Unit 2 Containment Coatings Watch List.

100-foot Elevation 45, 55, 70 and 75 degrees - Mechanical damage to the floor coating in these areas is unchanged, no further degradation. Keep on Unit 2 Containment Coatings Watch List.

105-degrees - Penetration 47 - Epoxy coating on penetration has not degraded, but the inorganic zinc closer to the pipe has discolored. There is no harm in this 4



Enclosure Attachment 4 Evaluation of the Proposed Change



discoloration. There was insulation stacked in this area, approximately 4 feet deep, so close access to the penetration was not possible. However, it was inspected with a flashlight from a distance and it was unchanged since 2R21.

105-degrees - By the T-wall, insulators have used proper storage techniques with blue plastic and magnets to protect the liner plate from the sharp edges of the insulation.

150-180 degrees - There are quite a few wormtrails above and below the first weld in this area.

155-170 degrees - Areas where graffiti has been scrapped off from the liner with an abrasive. Has done more damage to the coating than if the graffiti had been left in place. There is still some inorganic zinc coating in these areas, but this area will be watched for rust. Keep on Unit 2 Containment Coatings Watch List 230-degrees - Regen Heat Exchanger (HX) Room - Was able to look inside the Regen HX Room and quickly assess the coatings inside without entering the room during 2R21. The coating was acceptable and intact in all the visible areas from the doorway. There is quite a bit of mechanical damage to the floor coating in the entry of the HX room and also to the RCP 2B pump bay entrance. Did not inspect the Regen Heat Exchanger Room during 2R22, but did look at the floor damage, which is unchanged since 2R21.

230-degrees - Many small areas of mechanical damage to floor coating outside the elevator. This does not need to be repaired unless Radiation Protection (RP) sees it as a potential radon or decontamination issue. It is a high traffic area and would have to be cordoned off for days while the coating cured. There is no reason to recoat this area at this time.

355-degrees - Triangular rust spot is unchanged since 2R20.

120-foot Elevation The 120-foot elevation in Unit 2 does not have nearly as many wormtrails as the 120-foot elevations in Units 1 and 3.

There is quite a bit of graffiti on the liner plate on the 120-foot elevation. It is not malicious graffiti; it is areas where they have used paint markers and the liner plate as a scratch pad for work related notes, etc. These paint markers have damaged the liner plate coating because the paint flakes off and takes the IOZ with it when it delaminates.

45-degrees - The rust spot at approximately 138 feet elevation is unchanged since 2R21. Very dark in this area, difficult to photograph - no photo from last outage.

Light rust in this area. Keep on Unit 2 Containment Coatings Watch List.

55-degrees - New white spill on liner. It looks like maintenance tried to clean it off; however, the white staining indicates the presence of boric acid and the potential for zinc depletion. This area will be added to the Unit 2 Containment Coatings Watch List.

80 & 85 degrees - Penetration 1 and 2 still had the insulation on the pipe so couldnt see the entire surface of the inorganic zinc. There were no lights on behind the t-5



Enclosure Attachment 4 Evaluation of the Proposed Change



wall, so inspector could not get a photograph, but using a flashlight, could see that there was no further degradation of the exposed coating.90-100 degrees - Mechanical damage behind t-wall is unchanged since 2R21. This damage is likely from when the large metal insulation pieces are removed from the penetrations and pipes the sharp edges of the insulation are scraped against the liner plate damaging the coating. Keep on Unit 2 Containment Coatings Watch List. HVAC coil cleaning group used tape on the liner plate to rope off the area, rather than using cones or stanchions to hold the barrier ribbon in place. The tape leaves a residue on the coating and will degrade the coating over time.

95 & 105 degrees - Penetrations 3 and 4 behind the t-wall are unchanged since last outage. There is some discoloration of the inorganic zinc, but no significant change.

150-190 degrees - This area, above and below the first weld, are areas where the paint marker graffiti has been scrubbed off with some type of abrasive. Removing the graffiti has caused more damage to the coating than if it was left as is. Put on Unit 2 Containment Coatings Watch List.

190-degrees - Small area of mechanical damage with small amount of rust is unchanged. Keep on Unit 2 Containment Coatings Watch List.

210-degrees - Minor white spill stain. Keep on Unit 2 Containment Coatings Watch List.

215-degrees - No change in white spill, small amount of rust present, which was noted during the 2R19 inspection.

290-degrees - The liner plate coating damage where the coating has been scrubbed to remove an arrow and other writing is still unchanged. Keep on Unit 2 Containment Coatings Watch List.

140-foot Elevation 30-degrees - Carpenters have made an effort to protect the containment liner plate by putting up a white paper protection layer against the liner plate. They have used magnets to hold the paper up, but unfortunately, they have also used tape, which will degrade the liner plate coating.

55-degrees - Damage to floor coating around the reactor head stand. Most of the marks are stains, but there are some burned areas as well as mechanical damage.

No reason to repair these areas as the coating is still performing its function of protecting the concrete.

65-degrees - there is an area of coating failure behind the reactor head stand at about 144 ft elevation which was discovered during 2R21. The area is approximately 6 feet x 2.5 feet. The coating is peeling off as small sheets. This is an unusual failure and has not been seen in the PVNGS Containment Buildings prior to this. DFT readings were taken in and around the area of the failure.

Epoxy DFT in the center of the failed area:

6.4 mils, 8.3 mils, 7.6 mils The epoxy DFT around the failure 6



Enclosure Attachment 4 Evaluation of the Proposed Change



14.2 mils, 15.2 mils, 16.2 mils Inorganic zinc (IOZ) away from failed areas:

9.4 mils, 10.2 mils, 10.0 mils, 8.0 mils, 5 mils Paint chip samples were collected and examined under a 200X power microscope in the Lube Oil Lab and photos taken of the surface. There were small amounts of inorganic zinc coating attached to the failed side of the coating chips. The inorganic zinc is evidenced as spheres in the microscopic photos.

As there are still 6-8 mils of epoxy coating, even in the failed areas, there is no need to repair this area. The remaining coating will protect the liner plate from corrosion.

It is thought that when the bar beneath the failed coating area was welded to the liner plate (probably prior to the reactor head stand being placed) the bare steel welded area was repaired with epoxy. If they extended the new epoxy from the weld over the existing coating on the liner plate without proper surface preparation, this could cause this type of failure. Also noted is that the inorganic zinc coating was very thick in this area. A typical DFT for IOZ is 2-3 mils and manufacturers suggest it not exceed 6 mils. As shown by the DFT readings above, the IOZ is in excess of 10 mils in some areas.

During 2R22, the area behind the reactor head stand was only inspected from approximately 10-12 feet as there was storage in front of the area, which prevented a closer look. The delamination did not appear to have increased. The concern for this area was that the coating would continue to peel off in sheets, but this has not happened. This area will be kept on the Unit 2 Watch List and inspected every outage for further degradation.75-105 degrees - Photographed the area just east of the control element assembly (CEA) Change Platform to show the coating mechanical damage. No changes since 2R20.

105-135 degrees - The area under the multi-stud tensioner (MST) stand was not staged when inspecting the 140 ft elevation during 2R20. Was able to get a close look at the liner plate in that area. There is a fair bit of mechanical damage, which is not unexpected with all the equipment that is stored under the stand. There is very little rust in these areas.

195-degrees - Mechanical damage on liner area circled during a previous outage to monitor. No rust present at this time. Keep on UNIT 2 Containment Coatings Watch List.

240-degrees - Mechanical damage near the personal airlock (PAL) door. Keep on Unit 2 Containment Coatings Watch List.

245-265 degrees - Mechanical damage in RP staging area. Keep on Unit 2 Containment Coatings Watch List.

250-315 degrees - The liner plate coating along the fuel transfer canal, across from the foreign material exclusion (FME) table and the pressurizer cubical has quite a bit of mechanical damage. This is due to the storage of sharp objects against the liner by the pressurizer cubical and the narrow width of this heavily trafficked passage 7



Enclosure Attachment 4 Evaluation of the Proposed Change



along the fuel transfer canal and FME table. Very little rust in these areas which is surprising due to the close proximity to the containment hatch. Keep on Unit 2 Containment Coatings Watch List.

280-degrees - Several areas of mechanical damage with a small amount of rust.

Keep on Unit 2 Coatings Watch List.

295-degrees - Mechanical damage on pressurize stairs floor coating. Keep on Unit 2 Containment Coatings Watch List.

160-foot Elevation 10-degrees and 25-degrees - Just below the 160-foot elevation grating there is a fairly dark rusted, circular area about 8 inches in diameter at approximately 160-foot elevation. There are a number of rust areas around the dome area. These are difficult to inspect and evaluate.

8



Enclosure Attachment 4 Evaluation of the Proposed Change



Assessment of the PVNGS Unit 3 Containment Coatings in 3R21, October 2019 3R21 General Comments All areas of the Unit 3 Containment Building were inspected with the exception of the Locked High Rad areas. These areas were looked into but not entered.

The coating work performed during the past outages by PVNGS coaters is in all cases workmanlike and continues to exhibit good visual quality, with the exception of small areas of recent mechanical damage. The damage that is listed below is from poor treatment (mechanical damage, spills that were not cleaned up, etc.) rather than the coatings failing or showing signs of poor application. Hence all the damage to the containment coatings could have been prevented through better housekeeping or more care in transporting scaffolding, storing equipment, etc.

The Coatings Responsible Engineer met with RP, the insulators and the carpenters, prior to the spring 2016 outage to explain that storing sharp insulation, carts, ladders, etc. against the liner plate damages the coating and the carbon steel. It was also explained that gluing and taping things to the liner compromises the coating, hence will result in rust. Performed the walkdown of Unit 3, it was apparent none of these behaviors had changed. There were several attempts to protect the liner this outage in the form of taping tarps and padding to the liner plate. Unfortunately, the tape damages the coating on the liner plate. Padded magnets should be used to secure items to the liner. It also impaired the assessment of the liner coating underneath these tarps. A condition report (CR) was initiated to resolve these issues.

Unit 3 has far fewer wormtrails on all elevations than the other two units. This is due to the inorganic zinc coating not being applied so thickly, thus the Containment Liner Plate coating is not cracking and failing.

Wormtrails that were marked with a sharpie during previous outages do not appear to have degraded further. These are not scheduled for repair because prior DFT readings show that there is still IOZ left in these areas.

Every single defect in the coating in Unit 3 is not recorded in this submittal. There are literally hundreds of thousands of areas of mechanical damage to the coating.

During these walk downs, an underline or circle, with a black Sharpie, identifying scratches which are particularly deep, or where it looks to be scraped down to bare steel or areas where rust is starting to appear. Also underline areas where there is a great deal of minor mechanical damage, as these areas could get enveloped in rust once corrosion starts. Not all of these areas are photographed and entered into this submittal if the damage to the coating is minor. Rather the markings with Sharpie help to check on these areas and monitor them from outage to outage.

In general, the containment was very dark during 3R21. Many of the overhead lights were not on and it was difficult to get good photographs. The assessment was completed successful using a flashlight.

9



Enclosure Attachment 4 Evaluation of the Proposed Change



ISI does not re-inspect the rust areas on the liner plate that have a number on them.

These areas were inspected at some earlier date and have been considered acceptable.

80-foot Elevation 0-degree azimuth - White spill from the 100-foot elevation to the 80-foot elevation is unchanged since the last outage. Small amount of rust coloring which was present previously. Keep on Unit 3 Containment Coatings Watch List.

0-degree azimuth - Scratch near white spill is being repaired this outage. The repair is being accomplished using a blunt edge repair with Carboguard 890N using power tool cleaning (SSPC SP3) surface preparation.

20-30-degree azimuth - The vertical scratches below the first weld are being repaired this outage. The repair is being accomplished using a blunt edge repair with Carboguard 890N using an SSPC SP3 surface preparation.

20-degree azimuth - The green spill is still present on the concrete coating. It is probably corrosion from air conditioning unit (ACU) A01B. It is possible it is a stain and cannot be removed. There is no sign that it is degrading the coating. Keep on Unit 3 Containment Coatings Watch List.

30-degree azimuth - Scratch in liner coating scrapped down to metal below first weld.

Shiny and no rust present yet, no change since last outage. Keep on Unit 3 Containment Coatings Watch List.

40-degree azimuth - Small gouge on liner plate coating below the first weld where all the coating has been removed and a similar one just above the first weld.

45-degree azimuth - Improper storage in containment. Sharp objects are being stored against the liner plate, which damages the coating and could potentially damage the carbon steel.

75-degree azimuth - White spill from 100 ft down to 80 ft elevation is unchanged since last outage. Keep on Unit 3 Containment Coatings Watch List.

85-degree azimuth - Slight damage to floor coating behind the t-wall looks unchanged. Keep on Unit 3 Containment Coatings Watch List.

85-degree azimuth - from the platform at the 90-foot elevation, behind the t-wall there are scratches in the liner plate coating above the platform railing. It is mechanical damage from work being done on the platform and not being aware of the damage being done to the coating by tools or other sharp objects. Circled some of the damage. Photos are unclear due to the poor lighting in this area.

88-degree azimuth - Penetration 75, Auxiliary Feedwater Supply, at approximately 92-foot elevation as seen from the 90-foot platform behind the t-wall is bare steel.

Unclear if it is to be left as bare steel or if they are waiting to coat it with IOZ.

90-degree azimuth - Behind the stem of the T-wall against the liner plate there is quite a bit of white deposit on the liner plate. The deposit is fairly tenacious and does not appear to be flaking off and taking the coating with it. There is a patina of rust in some areas. Keep on Unit 3 Containment Coating Watch List.

10



Enclosure Attachment 4 Evaluation of the Proposed Change



90-105-degree azimuth - Behind the T-wall the liner coating is in very good condition. There is very little mechanical damage. The nuclear cooling water pipe runs through this area at about chest height making it difficult to access, which is probably why the coating has not been damaged in this area.

95-degree azimuth - Staining and minor coating damage to floor coating near the wet layup pump. It is covered with a mop head, presumably to soak up water from a chronic leak. Keep on Unit 3 Containment Coating Watch List in case floor coating damage increases.

105-degree azimuth - Oil spill or stain in area behind the T-wall. The oil should not damage the coating but keep on the Unit 3 Containment Coating Watch List.

105-120 - degree azimuth - Mechanical damage below the first weld behind the nuclear cooling pipe is unchanged since the last outage. Areas where the coating has been scraped down to the metal are still shiny and there is very little rust present. It is very dark in this area, so the pictures are not very clear. But on visual inspection with a flashlight it is clear that very little change has occurred in these areas. The area will be kept on the Unit 3 Containment Coatings Watch List.

125-degree azimuth - Old mechanical damage - overcoated with IOZ. Another spot of mechanical damage right next to it with a small amount of rust. No change since the last outage. Keep on Unit 3 Containment Coatings Watch List.

165-degree azimuth - 4 areas of rust on liner place around the first weld. Wormtrail with small amount of rust - 1 of 4 areas. Keep on Unit 3 Containment Coatings Watch List.

165-degree azimuth - Small gouge approximately 2 feet below the first weld beneath the 4 areas of rust on the liner plate. Approximately 1/4 inch in diameter slight shearing of metal up. It is not clear what happens behind these stairs that would cause mechanical damage to the liner coating. Nothing sharp is stored in this area and it is not a throughway where mechanical damage from transporting scaffolding, etc., would occur.

175-degree azimuth - Small gouge on the liner approximately 15 inches below the first weld. A small amount of the metal of the liner has been peeled back, perpendicular to the liner. The area is approximately 1/4 inch in diameter and there is a small amount of rust present. Because the metal has been disturbed, ISI Liner Plate Inspector was contacted via email to look at this small area to be certain the liner has not been compromised.

ISI went out to look at the indications. The indications displaced more paint than the metal. ISI did not perform an IWE report as they had no scheduled work this outage.

The dents are less than acceptable per ASME XI and clearly bounded by conditions approved in an evaluation. ISI will be performing a full IWE exam in Unit 3 Fall of 2019 refueling outage (3R21).

160-180-degrees azimuth - Many small areas of rust and mechanical damage in this area. Keep on Unit 3 Containment Coatings Watch List.

11



Enclosure Attachment 4 Evaluation of the Proposed Change



270-degrees azimuth - Lube Oil Collection Tank Manway - The room and tanks look in good condition, no changes to the coatings since last outage. There is debris on floor of the room. It is an open area, so it will be noticed and removed during the Mode 4 clean up.

275-degrees azimuth - Burnished area 1.5 feet above the first weld as though the area has been buffed with a power tool. No change in this area since the last outage.

Light patina of rust over the area. Keep on Unit 3 Containment Coatings Watch List.

285-degree azimuth - Small gouge (size of a quarter) in coating above the first weld across from the 1A RCP bay. It is unchanged since Unit 3 Spring of 2017 refueling outage (3R18). There is a small amount of rust present. Keep on Unit 3 Containment Coatings Watch List.

295-degree azimuth - Small area of mechanical damage on first weld. It is less than 1/2 inch in diameter. Epoxy has chipped off in this area. Light patina of rust. Put on the Unit 3 Containment Coatings Watch List.

315-degree azimuth - Small gouge in coating just above the weld. No change since 3R18, no rust present. Keep on Unit 3 Containment Coatings Watch List.

325-350 degrees azimuth - An attempt was made to properly store sharp objects against the liner plate. Although this will protect the liner and liner coating from the sharp edges of the insulation, the tape used to secure the mats will harm the coating on the liner plate. Padded magnets should be used to attach items to the liner plate.

CR was generated to resolve this issue.

90-foot Elevation 245-255 degrees azimuth 90-foot platform - Added here for information only. Graffiti is not typical; this area has more graffiti than most - probably because it is an isolated area. This is not malicious graffiti but rather markings for their work when they have used the liner plate like a tablet to record things. They have used the thick paint pens used for marking cable trays, etc., this is unqualified coating and damages the inorganic zinc coating on the liner plate.

100-foot Elevation There are more wormtrails on the 100-foot elevation than on the 140- or 80-foot elevations. Even so, not nearly as many as in the other units.

5-degree azimuth - 5 small scratches above the first weld, approximately 3/4 inch high by 1/2 inch wide, some bare metal areas, but no rust present. Keep on Unit 3 Containment Coatings Watch List.

50-degree azimuth - Storing the lids to the lead storage bins behind the bins up against the liner plate, which is causing new scratches and mechanical damage each outage. Another example of poor storage practices. There is one particularly deep scratch which was circled last outage and will be monitored. At this time, it is still shiny and there is no rust present. Keep on Unit 3 Containment Coatings Watch List.

60-degree azimuth - Floor coating outside RCP Bay 1B has quite a bit of mechanical damage. The yellow primer is showing through in many areas and the concrete is exposed in other areas. Due to the long cure time of the floor coating and the heavy 12



Enclosure Attachment 4 Evaluation of the Proposed Change



traffic in this area, it is not justified to recoat at this time. There has been no change in this area since the last outage. Keep on Unit 3 Containment Coatings Watch List.

80-degree azimuth - Someone has drawn a smiley face on the liner plate behind the t-wall. This is new graffiti since Unit 3 Spring of 2018 refueling outage (3R20). It is in a very visible area and would not have been missed in the 3R20 Containment Coatings Assessment. It looks to be a viscous paint rather than a marker. It does not appear to be a type of paint that would harm the liner plate coating, but there is no way to be certain without knowing what was used. Removing this graffiti will do more damage to the liner plate coating than just leaving it in place. Put on Unit 3 Containment Coatings Watch List to determine if the coating underneath will degrade.

90-100-degree azimuth - Improper storage behind the t-wall. Sharp objects are being stored against the liner plate, which damages the coating and could potentially damage the metal of the liner.

105-degree azimuth - Floor coating damage in front of the scaffolding trays and just across the walkway near the t-wall. This is also old damage that does not need to be repaired, just watched for further degradation. Keep on Unit 3 Containment Coatings Watch List.

120-degree azimuth - Minor floor coating damage outside the 2A RCP Bay. Some of it might be staining. This is old damage and there is no reason to recoat at this time.

Keep on Unit 3 Containment Coatings Watch List.

135-degrees azimuth - Rust on floor from valves leaking under insulation. Two areas of rust. Floor coating does not appear to be damaged, just stained from the chronically leaking normal chilled water system (WC) isolation valve. Keep on Unit 3 Containment Coatings Watch List.

145-degree azimuth - Small indent on liner at approximately 107 ft. It is about the size of a pea. Drew an arrow pointing to it, as it could not be reached to circle the area. It has been coated over, so it is not new. Keep on Unit 3 Containment Coatings Watch List.

150-degree azimuth - Patch on liner plate is in good condition and the coating is intact.

190-degree azimuth - Rust spill from 120 to 100-foot elevation is unchanged since the last outage. Keep on Unit 3 Containment Coatings Watch List.

230-degrees azimuth - Floor coating outside RCP Bay 2B has mechanical damage.

The concrete is exposed in some areas. Due to the long cure time of the floor coating and the heavy traffic in this area, it is not justified to recoat at this time. Keep on Unit 3 Containment Coatings Watch List.

235-degree azimuth - Minor floor coating damage in front of elevator. Keep on Unit 3 Containment Coatings Watch List.

295-300-degree azimuths - The wide scratches above and below the first weld discovered in 3R20 are unchanged. They are still shiny, and rust has not started to develop. Workman must have been staging scaffolding or some other equipment with 13



Enclosure Attachment 4 Evaluation of the Proposed Change



disregard for the liner plate to make such wide, deep scratches in the liner coating.

Keep on Unit 3 Containment Coatings Watch List.

310-degree azimuth - Deep and wide scratch that had been underlined last outage (circled it this outage to make it easier to see) is unchanged. It is still shiny, and no rust has started yet. This scratch is similar to the ones from 295 degrees to 300 degrees azimuths. Keep on Unit 3 Containment Coatings Watch List.

320-degree azimuth to the PAL Door - There are too many nicks and scratches to the coating to itemize or photograph. The damage is from storing sharp objects against the liner. It is difficult to inspect this area as it is always blocked with items being stored there. Only the deep scratches, or areas where rust has progressed are repaired. Keep on Unit 3 Containment Coatings Watch List.

355-degree azimuth - Two small scratches above the first weld. Marked boxes around them to make them easier to monitor. No rust at this time. Keep on Unit 3 Containment Coatings Watch List.

120-foot Elevation The liner plate coating on 120-foot elevation of the Unit 3 Containment Building is in excellent shape. All the cable trays in front of the liner plate act as a barrier from mechanical damage from scaffolding and tools being carried around and staged.

0-degree azimuth - Wormtrails with coating delaminating. Much fewer in Unit 3 than in the other two units. When the wormtrails were first discovered, it was thought that only the epoxy would delaminate from a wormtrail area. With further investigation it was shown that the IOZ was thick enough and became brittle enough in some areas that it delaminated without an epoxy topcoat being present.

5-degree azimuth - Mechanical damage on liner plate. Keep on Unit 3 Containment Coatings Watch List.

25-degree azimuth - 3 small areas of mechanical damage, 1/2 - 3/4 inch in diameter, approximately 18 inches above the floor grating. There is more mechanical damage around this area, so keep on Unit 3 Containment Coatings Watch List.

45-degree - Mechanical damage behind the Duct Heater box. Marked one area last outage and underlined another area 3R21. These areas are shiny and show no rust yet. Keep on Unit 3 Containment Coatings Watch List.

100-degree azimuth - the Carboline Carbozinc 11SG is starting to discolor slightly, which should not affect the quality of the coating. Discoloration has not increased significantly. Keep on the Unit 3 Containment Coatings Watch List.

145-degree azimuth - Rust under valves - on the Unit 3 Containment Coatings Watch List.

190-degree azimuth - Corrosion on chillers is very similar to last outage.

280-degree azimuth - Area of concrete repair outside the pressurizer and valve gallery door. It looks as though the concrete has spalled away and been repaired with grout along the edges. Keep this area on the Unit 3 Containment Coatings Watch List to monitor in case the spalling continues or progresses.

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Enclosure Attachment 4 Evaluation of the Proposed Change



140-foot Elevation 0-30-degree azimuth - Severe mechanical damage to the liner plate coating due to scaffold storage.

40-degree azimuth - Floor coating damage. Keep on Unit 3 Containment Coatings Watch List.

55-degree azimuth - Floor coating damage. Keep on Unit 3 Containment Coatings Watch List.

90 degrees azimuth - The dance floor coating is in fairly good shape considering the traffic and equipment that is staged there. The rails were covered with checker plate and so the area on either side of the rails was not visible. This is normally an area where the coating gets damaged but in Unit 3, there has been nothing noteworthy thus far.

120-degrees azimuth - Floor coating damage where equipment has been stored. This area is not normally visible, due to the storage in this area. With the old MST being brought back into Containment, the staging area below the MST has not been staged and areas not normally visible were visible on this day. Not necessary to repair but should be watched for further degradation. Keep on Unit 3 Containment Coatings Watch List.

125 degrees azimuth - Scratch above first weld is unchanged since the last outage.

Was unable to get close enough to get a new photo but could inspect it using a flashlight. Keep on Unit 3 Containment Coatings Watch List.

150-200 degrees azimuth - Liner has been covered with white tarps. Presumably to protect the liner from mechanical damage - however, the tape used to secure these tarps damages the coating on the liner plate. The tarps also prevented the coating in these areas from being assessed. CR was initiated to resolve these issues.

245 degrees azimuth - Mechanical damage below the first weld behind the stainless-steel storage box. Very narrow area and liner gets scratched from scaffolding and tools. No rust at this time, but many scratched and scrapped areas. The whole area below the first weld from the stainless-steel storage box to the transfer canal is very scratched. Nothing too deep or rusted but this entire area must be monitored. Keep on Unit 3 Containment Coatings Watch List.

255 degrees azimuth - 3.5 feet long scratch at an angle, some rust at top near first weld. No change from last outage. Keep on Unit 3 Containment Coatings Watch List.

260-degree azimuth - Scratch in epoxy on first weld; scratch goes right down to the steel. Steel is still shiny, no rust, no change from last outage. Keep on Unit 3 Containment Coatings Watch List.

265-degree azimuth 5 small gouges above the first weld. Very shallow and no rust present but should be watched for rust development. Area is already heavily scratched as the area is narrow and scaffolding, carts and other metal items come in contact with the liner. ISI inspected these gouges during 3R20 and found they were not deep enough to be of concern.

15



Enclosure Attachment 4 Evaluation of the Proposed Change



290-295-degree azimuth - 3 gouges in the liner that have been coated over. They are circled with Sharpie so they can be easily found each outage. This is old damage and has been checked by ISI. Too dark in this area to get new pictures but was easily inspected with a flashlight. Keep on Unit 3 Containment Coatings Watch List.

290-320-degree azimuth - Mechanical damage all along the liner, below and above the first weld. This is a narrow area and the damage is from the mishandling of tools, scaffolding, etc. Keep on Unit 3 Containment Coatings Watch List.

350-360-degree azimuth - Scratches to liner coating from scaffolding and tools being mishandled. Keep on Unit 3 Containment Coatings Watch List.

160-foot Elevation There are very few wormtrails in the liner coating in Unit 3. If shining the flashlight against the liner plate where it can be reached on the 160ft-168ft platforms, very few wormtrails are seen. This is very different from the other two Units.

65-degree azimuth - Rust area on liner plate at about 170-foot elevation, just above the HVAC ducts. It is surrounded by white paint and states Do Not Paint or weld in this area. It was very dark, so the photo is not very helpful. Certain ISI is aware of this area as it is outlined with white paint and has writing on it. It is very clearly visible.

The coating on the Dome of the Unit 3 Containment Building is in much better shape than the other two Units. There are not as many large rust areas. There are a few, but not nearly as many as the other units and the areas are smaller in size as well.

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Enclosure Attachment 4 Evaluation of the Proposed Change



Assessment of the PVNGS Unit 1 Containment Coatings in 1R21, April 2019 General Comments The coating work performed during the past outages by the Maintenance Coaters is in all cases workmanlike and continues to exhibit good visual quality, with the exception of small areas of recent mechanical damage. The damage that is listed below is from poor treatment (mechanical damage, spills that were not cleaned up, etc.) rather than the coatings failing or showing signs of poor application. Hence all the damage to the Containment coatings could have been prevented through better housekeeping or more care in transporting scaffolding, storing equipment, etc.

Wormtrails that were marked with a sharpie during previous outages do not appear to have degraded further. These are not scheduled for repair because prior DFT readings show that there is still IOZ left in these areas.

The Coatings Responsible Engineer met with Radiation Protection (RP), the Insulators and the Carpenters, prior to Unit 1 Spring of 2016 refueling outage (1R19) to explain that storing sharp insulation, carts, ladders, etc., against the liner plate damages the coating and the carbon steel. Also, gluing and taping things to the liner compromises the coating; hence, will result in rust. Per the Coatings Responsible Engineer in 1R20, none of these behaviors had changed (improved).

ISI does not re-inspect the rust areas on the liner plate that have an ISI number on them. These areas were inspected at some earlier date and have been considered acceptable.

In Unit 1 Spring of 2019 refueling outage (1R21), there were numerous paper and signs taped to the liner plate and other coated surfaces with different tape colors, i.e.,

not a consistent tape. Additionally, there were steel items stored in contact with the liner plate and other coated surfaces.

1R21 General Comments are consistent with the stated position in the assessment per 1R20.

Observations The observations from 1R20 will be confirmed in the 1R21 walkdown. The conclusion will be provided with each observation.

1R21 General Comments The Containment Building is an active environment during refueling outages. Work toolboxes, scaffolds materials, shielding and equipment pieces, often with sharp edges, are moved about. The storage areas are typically next to the liner plate. The main walking path is often along the liner plate in which personnel in Orex protective clothing and rubber overshoes can also rub the liner plate. In many areas, signs are taped to coated surfaces such as the liner plate. The type of tape seems to vary in color and type.

1R21, 104-foot elevation, Azimuth 65°, Typical - Signs Taped to the Liner Plate also Temporary Cables and Hangers Routed along the Liner Plate.

55-foot Elevation, under the Reactor No documented observations prior to 1R21. The area under the reactor was observed using a robot with a camera that was placed by Engineering Programs. The 17



Enclosure Attachment 4 Evaluation of the Proposed Change



robot/camera was manipulated, with sufficient light, to see approximately 70% of the volume including the coating on the concrete walls. Only a small wall area was close enough to see within a few feet. The concrete floor coating was not visible, with a light coating of dust and the camera limitation. When the robot moved, dust was raised, limiting a close look at the coating as the room has little air flow and the suspended dust was in the air and some settled on the lens.

The walls have a concrete coating scheme, per the Architectural PVNGS Drawing, 13-A-ZCD-0101. The robot was rotated about 270 degrees (of 360 degrees) to see most of the wall area. On the nearest wall, which had concrete crack and break in the coating, the coating was present with no visible rust or evidence of mechanical damage. There were only a few concrete/coating cracks visible. In one location there was particulate that had dripped down from a higher elevation. In the access shaft from 100-foot down to 55-foot there was a red stain that Engineering Programs, the team who placed the camera, said was from cleaning of steel at a higher elevation, about 100-foot, that their Unit is following the issue.

1R21 - For 55-foot elevation there is no coating deficiency and no addition to the Containment Coatings Watch List.

RCP Bay 1A 80-foot Elevation Entrance 1R20 - This room was not entered but inspected using a flashlight through the chain link door. Some of the concrete is uncoated and the yellow area is where the surface was not top coated during installation and the surface has yellowed.

1R21 - No change. The floor coating is abraded due to high traffic.

RCP Bay 2A 80-foot and Stair from 80-foot to 87-foot Elevation Entrance 1R20 - Some of the concrete is uncoated where the coating was removed. The yellow area is where the surface was not top coated during installation and the surface has yellowed. It was thought that because the un-topcoated surface had yellowed that it was unqualified. But the manufacturer said that the yellowing did not compromise the integrity of the coating, so the coating removal stopped. The area has not been recoated.

1R21 - No change.

RCP Bay 2B 80-foot and Stair from 80-foot to 87-foot Elevation Entrance 1R21 - RCP Bay 2B. Stair from 80-foot to 87-foot elevation, consistent with 1R20 Assessment.

80-foot, Manway, Room C-A06, Between the RCP Bay 1A and RCP Bay 2B 1R21 - Manway, Abraded Floor Coating in High Personnel Traffic Area. Consistent with descriptions in 1R20.

80-foot Elevation General Floor General - the 80-foot elevation liner plate has relatively few wormtrails and the liner is in comparatively good condition considering there are so many wide-open spaces which can be damaged by mishandling of scaffolding, improper storage of sharp objects against liner, etc.

15-degree azimuth - Burns on floor are unchanged. Degradation is not ongoing.

Discovered in Unit 1 Fall of 2011 refueling outage (1R16).

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Enclosure Attachment 4 Evaluation of the Proposed Change



1R20 80-degree azimuth - Scratches around the first weld have not changed since Unit 1 Fall of 2014 refueling outage (1R18). No rust is present. Keep this area on Unit 1 Containment Coatings Watch List.

1R21 - Azimuth 20 degrees at 84-foot elevation or First Weld of Liner Plate. The scratches previously identified have been recoated. The 1st Ring is from 77-foot elevation 3 1/4 to 84-foot elevation - 5 1/4 (first weld). This should be verified in Unit 1 Fall of 2020 refueling outage (1R22) and then address the entry in the Unit 1 Containment Coatings Watch List.

32-degree azimuth - Chip in floor coating is unchanged. Chip is approximately 5 inches long by 3 inches wide. The concrete is exposed, but this is only an issue for decontamination, so can be left as is. On Unit 1 Containment Coatings Watch List to ensure the cracking does not continue.

50-degree azimuth foot elevation - Seen from the 80-foot elevation and on the 90-foot platform. Degraded coating on an abandoned appurtenance. The coating is just beginning to degrade, and the appurtenance is no longer connected to a source of heat, so the coating should not continue to degrade. On Unit 1 Containment Coatings Watch List. 1R21 - No change.

70-degree azimuth - Crack in floor coating and coating has chipped away in some areas. On Unit 1 Containment Coating Watch List. 1R21 - No change.

75-degree azimuth - Narrow crack in floor coating and coating has chipped away in some areas. Placed on Unit 1 Containment Coating Watch List. 1R21 - No change.

75-degree azimuth - New coating and floor damage near wet lay-up pump. Valve above floor leaked during 1N20 operating cycle and damaged floor and coating. 1R21

- No change.

80-degree azimuth - Chipped floor coating near wet lay-up pump. On Unit 1 Containment Coatings Watch List. 1R21 - No change.

85-degree azimuth - Rust on support beams for 100-foot grating at approximately 98-foot elevation as seen from the 90-foot platform behind the T-wall. Generated CR to clean and coat beams per Procedure, Control of Painting and Coating Operations.

CMWO has been generated to recoat. On April 18, 2019, the CMWO was at location code 200, scheduled for 2020, the next refueling outage. 1R21 - No change.

110-degree azimuth - Chipped floor coating - old damage. Put on Unit 1 Containment Coatings Watch List. 1R21 - No change.

130-degree azimuth - Area of mechanical damage marked with sharpie for easier identification, no rust present. Put on Unit 1 Containment Coatings Watch List. 1R21

- located at approximately 83-foot elevation. 1R21 - No change.

135-degree azimuth - 3 areas of mechanical damage on liner around the first weld.

Small amount of rust present. One of the areas was recoated with white Amercoat 90N which has yellowed during the 1N20 operating cycle. On Unit 1 Containment Coatings Watch List. 1R21 - Approximate 84-foot elevation - No change.

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Enclosure Attachment 4 Evaluation of the Proposed Change



135-degree azimuth - New coating and floor damage. Valve on 90-foot platform leaked during 1N20 operating cycle and damaged floor and coating. 1R21 - No change.

175-degree azimuth - Area of mechanical damage on liner below the first weld. No rust present at this time. Keep on Unit 1 Containment Coatings Watch List. 1R21 -

No change.

176-degree azimuth - Mechanical damage to liner plate above first weld. No rust present at this time. Place on Unit 1 Containment Coatings Watch List. 1R21 - Could not confirm. Leave on the list, revisit in 1R22.

178-degree azimuth - Mechanical damage to liner plate near floor. No rust present at this time. Place on Unit 1 Containment Coatings Watch List. 1R21 - No change.

190-degree azimuth, 88-foot elevation Platform and other items above this including the 100-foot elevation grating. Chemical leak from a higher elevation down to 80-foot elevation. Reddish color is the spilled chemical. No apparent damage to the coating. 1R21 - Red Chemical Spill on Plant Items including the 88-foot elevation Platform Steel.

225-degree azimuth - Many abrasions/scratches on the liner plate just passed the sump strainers. Some work must routinely be going on in the area to generate these scratches. Area seems no worse than in 1R19, no rust present. Keep on Unit 1 Containment Coatings Watch List. 1R21 - No change.

265-degree azimuth - Burn on white wainscot coating at about 84-foot elevation outside the 2B pump bay. Coating does not need to be repaired, as it is on concrete, but no apparent reason why the burning should have happened. Keep on Unit 1 Containment Coatings Watch List for signs of further degradation. 1R21 - No change.

100-foot Elevation 60-70-degree azimuth - Wide scratches, some as wide as 1/2 inch, behind the lead shielding storage bins. It could be happening when the lids to the bins are removed and stored behind the bins. The sharp metal lids could be coming into contact with the liner plate. No rust at this point. Keep on Unit 1 Containment Coatings Watch List. 1R21 - No change.

70-degree azimuth - Wormtrails on liner above the first weld - similar to the 150-160-foot elevation. Unusual, as Unit 1 does not have as many wormtrails as other Units. 1R21 - Wormtrails - confirmed no change.

80-degree azimuth - Storage of sharp insulation against liner behind T-wall. Sharp edges will damage coating and possibly liner plate as well. 1R21 - Storage of insulation pieces continued.

80-degree azimuth - Scratches around penetration 46 behind the T-wall. May be from when the pipe insulation is taken off the pipe and the sharp edges of the insulation scratch the coating. No rust at this point. Keep on Unit 1 Containment Coatings Watch List. 1R21 - No change.

95-degree azimuth - Scratches around penetration 12 behind the T-wall. May be from when the pipe insulation is taken off the pipe and the sharp edges of the 20



Enclosure Attachment 4 Evaluation of the Proposed Change



insulation scratch the coating. No rust at this point. Keep on Unit 1 Containment Coatings Watch List. 1R21 - No change. Insulation stored against the liner plate.

Tag taped to line plate.

120-degree azimuth - Rust spill area which was repaired during 1R19 under CMWO was cleaned and coated with white Amerlock 90N. During the last 18 months, the coating has yellowed significantly. This color change does not affect the integrity of the coating. When this coating was DBA tested, the radiation part of the test resulted in the coating turning from white to yellow and following the autoclave test the panels had turned a medium brown color. However, the coating was still attached, with minor blistering after the test was complete. 1R21 - No change. Signs taped to the liner plate over the repaired coating.

175-degree azimuth - Scratch in epoxy coating above the first weld, no rust present.

Area just below Coating Survey #1. 1R21 - No change.

270-310-degree azimuth - Mechanical damage to coating on liner around first weld and below, mostly due to storage of sharp objects against liner. 1R21 - No change.

335-degree azimuth - The DAS Cabinet left in Containment following 1R19 has been removed from the 100-foot elevation - this will be removed from the Unit 1 Unqualified Coatings Log. In 1R21 - Confirmed DAS Cabinet was removed.

120-foot Elevation The 120-foot elevation seems to have more wormtrails than any other elevation in Unit 1. 1R21 - Concur that there are more wormtrails at 120-foot elevation.

30-40-degree azimuth - Many wormtrails with failing/cracking coating. Marked a number of them to track whether or not they are increasing in this area. They do not seem to be increasing in size. At least, not significantly enough in 18 months to make the difference notable. 1R21 - No change.

50-degree azimuth - there are many areas where glue has been applied to the liner plate and left in-situ. The glue is RTV (Room Temperature Vulcanization) silicone adhesive. Design NSSS is aware of this product being used in Containment and counts it as debris for the ECCS sump only if it is inside the Zone of Influence. 1R21

- No change.

60-degree azimuth - Rust spot which was identified during 1R19 as at the 50-degree azimuth is actually closer to the 60-degree azimuth. It is the same spot, as it was marked during the previous outage. Keep on Unit 1 Containment Coatings Watch List. 1R21 - No change.

80-degree azimuth - The Main Steam Line Penetrations that were coated with IOZ are still in good repair. There is a small amount of color change at the small end of the penetration, closer to the pipe, but the coating is still intact in all areas. It is unchanged since 1R19. Keep on Unit 1 Containment Coatings Watch List. 1R21 - No change.

120-degree azimuth - Rust spill area, which was repaired during 1R19, was cleaned and coated with white Amerlock 90N. During the last 18 months, the coating has yellowed significantly. 1R21 - No change.

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Enclosure Attachment 4 Evaluation of the Proposed Change



150-degree azimuth - White spill from 140-foot elevation down to 120-foot elevation has been present for some time, as some of the area has been overcoated with epoxy. Very little rust staining on this spill. 1R21 - No change.

140-foot Elevation 215-degree azimuth - Abraded area on liner plate above first weld behind RP desk outside PAL door. No rust. Keep on Unit 1 Containment Coatings Watch List. 1R21 -

No change.

240-300-degree azimuth - Wormtrails with the epoxy coating cracked. DFT readings were taken and found that there is still IOZ in these exposed areas. These wormtrails do not need to be repaired, as no rust is forming and there is still 1-2 mils of IOZ on the steel underneath. Marked many of the larger areas with a Sharpie to monitor.

These areas are already on the Unit 1 Containment Coatings Watch List. 1R21 - No change.

280-degree azimuth - Mechanical damage on liner plate. ISI inspected the area during 1R19 and found the damage to be less than 1/64 of an inch, which is within the allowed tolerance. 1R21 - No change.

300-320-degree azimuth - Wormtrails, scratches all along this area. Small amounts of rust. 1R21 - No change.

310-degree azimuth - Mechanical damage approx. 3 feet above the floor - no rust.

Another small area of mechanical damage, closer to 310 degree discovered by ISI inspector. This area has metal peeling back. ISI determined that the depth of the scrap is acceptable and will have the area blended out during 1R20.

NOTE: In 1R21, the AZ 310-degree damage, located near the Containment Equipment Hatch, was covered up and blocked by storage items. The completed repair could not be verified.

315-degree azimuth - Scratch in liner coating with small amount of rust present, no change since 1R19. Keep on Unit 1 Containment Coatings Watch List.

330-degree azimuth - Scratch and small amount of surface rust on Containment Hatch (Approximately 144 ft Elev.).

NOTE: In 1R21, the AZ 315 & AZ 330-degree damage, located near the Containment Equipment Hatch, was covered up and blocked by storage items and could not be verified.

345-degree azimuth - Mechanical damage approx. 3 feet above the floor with a small amount of rust, no change since 1R19. Keep on Unit 1 Containment Coatings Watch List. 1R21 - No change.

352-degree azimuth - Two small areas of mechanical damage and rust where all the scaffolding is stored behind the HVAC unit on the 140 elevation. One spot is about 1 foot above grating and the other directly above it. No change since 1R19. Keep on Unit 1 Containment Coatings Watch List.

NOTE: In 1R21 the AZ 352-degree damage was covered up and blocked by storage items. The previous observation could not be verified.

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Enclosure Attachment 4 Evaluation of the Proposed Change



160-foot Elevation.

The Steam Generator (SG) North #1 and South #2 Platform nominal elevations are at 168.5-foot. These platforms are used to observe surfaces from the platform to the top of the dome.

0-degree azimuth - Wormtrails as seen from the North SG 1 Platform. In 1R21 the wormtrails are present and do not appear to be changing. 1R21 - No change.

180-degree to 200-degree azimuth - Many wormtrails from 165-foot elevation down to the 155-foot elevation as viewed from the platform by Steam Generator 2. In 1R21, the wormtrails are present and do not appear to be changing.

180-degree azimuth - Small area of mechanical damage on liner plate (1/2 inch wide by 3 inches long). No rust at this time. Put on Unit 1 Containment Coatings Watch List. 1R21 - No change.

200 - 215-degree azimuth - An unusual number of wormtrails at the 150-160-foot elevation, more easily seen from the 150-foot platform by the 2B SIT Tank. Also, the liner plate has a number of bulges in this same area. Keep on Unit 1 Containment Coatings Watch List. In 1R21 the wormtrails are present and do not appear to be changing.

225-degree azimuth - Rust spot approximately 2 feet x 1 foot - could be staining.

Keep on Unit 1 Containment Coatings Watch List. 1R21 - No change.

230-degree clockwise to 65-degree azimuth - Rust areas on wide flanges that support the polar crane rail and on the liner plate between these supports. These are probably where something was welded in place to these supports and then removed without recoating. These have been there for many years - first noted in Unit 1 Spring of 2013 refueling outage (1R17). Keep on Unit 1 Containment Coatings Watch List. In 1R21, there is no change.

330-degree azimuth - Rust spot on liner plate behind the raised Containment Hatch.

Put on Unit 1 Containment Coatings Watch List. 1R21 - No change. Hatch is lowered.

330-degree azimuth - Rust area on top weld of Containment Hatch and 4 rust spots below that weld. CMWO generated during 1R19 to repair this area. NOTE: On April 18, 2019 the CMWO is at location code 500, scheduled to be recoated at the end of 1R21. 1R21 - No change.

345 to 40-degree azimuth (clockwise) - Area of many wormtrails just to the right of the Containment Hatch below the first weld on the 160-foot elevation and continuing to 40-degree azimuth. This is not typical of Unit 1. Unable to photograph. In 1R21 -

No change.

Containment Dome Difficult to inspect and to photograph, lights on bottom of Polar Crane distract the eye and camera lens. Even with the hatch open, there is very little light. Because of the light in the foreground from the Polar Crane the Dome comes out dark in photos regardless of the flash setting. Visually, there is no discoloring or staining, either rust 23



Enclosure Attachment 4 Evaluation of the Proposed Change



or white stains. The coating looks in good shape above Polar Crane on the Dome. In 1R21 - No change.

24



Enclosure Attachment 5 Evaluation of the Proposed Change



ATTACHMENT 5:

Results of Recent IWE Examinations



Enclosure Attachment 5 Evaluation of the Proposed Change

Results of Recent IWE Examinations Table 3.5.5-1: PVNGS Unit 2 IWE Examination, Fall of 2018 Refueling Outage (2R21)

Report Number ASME Item No.

Method Accept Description of Abnormal Conditions Comments Component 2AZCNB01 Containment Liner 18-VT-2002 - E1.11 General Yes No abnormal condition noted. Some Some debris noted in Penetrations 6, 8, All Penetrations debris noted and light surface rust. 10. Pen 58 has a nest and egg at end of penetration. The following Penetrations have light surface rust at penetration weld location or entire flue:

1,2,3,4,5, 6, 8, 9, 10, 14, 22, 44, 58, 60, 61, 66, 67, 68 ,69, 70, 71, 72, 74.

Most electrical Pens had boxes covering the penetration.

Many penetrations were covered making inside the penetration inaccessible 18-VT-2003 - E4.11 VT-1 Yes No abnormal condition noted. Light Surface rust looked less severe using the Penetrations 60, 61 surface rust at the penetration weld. boroscope.

18-VT-205 - E1.11, E1.30 Zone 202 General / Yes Examined from 77'-3" to 140'-6". No **Rust and boric acid on containment liner VT3 reject indications noted. **,*** from a leak on 2JSIEV0474 PSV, CR was Zone 203 Yes Examined from 77'-3" to 140'-6". No written. Per the visual exam, it appears reject indications noted. *** that no measurable material loss has Zone 204 Yes Examined from 77'-3" to 140'-6". No occurred. The wall was UTed in 2R21 reject indications noted. *** outage with no noted degradation, 18-UT-CBD-15 (Leak Chase) Yes No indications and all caps in place. 2101. ***Boric acid by T-wall with no 1



Enclosure Attachment 5 Evaluation of the Proposed Change

Table 3.5.5-1: PVNGS Unit 2 IWE Examination, Fall of 2018 Refueling Outage (2R21)

Report Number ASME Item No.

Method Accept Description of Abnormal Conditions Comments Component 100' Pres. Hatch Yes Examined inside and outside, some corrosion, worm tacks in paint, surface standing water outside. *** corrosion with no wall loss, chipped paint, general surface corrosion where paint has been removed. No areas detected outside the boric acid leak on Zone 202 that require a follow up examination for thickness or to validate material loss. Note that some standing water was noted on the outside of the 100' personnel hatch, but no sign of material loss is present.

Some surface corrosion noted along edge of water, CR was generated to refresh the coating around the standing water.

18-VT-2007 - E1.11 Zone 202 General / Yes Examined from 140'-6" to polar crane. **Noted chipped paint, worm tacks in VT3 No reject indications noted. ** paint, general surface corrosion where Zone 203 Yes Examined from 140'-6" to polar crane. paint has been removed and tape No reject indications noted. ** remnants. No areas require a follow up Zone 204 Yes Examined from 140'-6" to polar crane. examination for thickness or to validate No reject indications noted. ** material loss.

140' Personnel Hatch Yes Examined inside and outside surfaces with no indications noted.

Pen 53 Yes No noted indications from visible surface of Pen 53 from the 140' elevation.

18-VT-2008 - E1.11 Zone 204 VT-3 Yes 120' elevation approx. 7° Azimuth, below 120' elevation area - 2.5-inch square area grating level, SAT for coating. that was prepped for coating.

Zone 203 Yes Approx. 141.5', - 225° Azimuth, behind 140' elevation area - 0.5-inch x 1.5-inch RP desk/scaffolding box. area prepped for coating.

18-VT-2010 - E1.11 General / Yes 140' Equipment Hatch outside surface, Zone 204 VT3 no indications noted.

2



Enclosure Attachment 5 Evaluation of the Proposed Change

Table 3.5.5-1: PVNGS Unit 2 IWE Examination, Fall of 2018 Refueling Outage (2R21)

Report Number ASME Item No.

Method Accept Description of Abnormal Conditions Comments Component 18-VT-2011 - E1.11 General / Yes No noted indications above the Polar Zones 201-204 VT3 Crane to the top of the dome.

18-VT-2012 - E1.11 VT-3 Yes No indications noted on pen 23 inside the Zone 205 - Pen 23 A RAS Sump, 2MSIAF04.

18-VT-2013 - E1.11 Zone 203 VT-1 Yes 80' level, 180° azimuth about 5 ft. above *Small gouge in liner (less than 1/16 in floor. Acceptable* depth), acceptable per evaluation.

Zone 204 Yes 80' level, 0° azimuth about 5 ft. above floor. No indications noted.

Zone 203 Yes 100' level, 245° azimuth just above the grating. No indications noted.

18-VT-2014 - E1.11 General / Yes No indications noted on pen 24 inside the Zone 205 - Pen 24 VT3 B RAS Sump, 2MSIBF04.

18-VT-2015 - E1.11 VT-3 Yes 150' elevation ~300° Azimuth, no Zone 204 indications noted. Area SAT for coating.

3



Enclosure Attachment 5 Evaluation of the Proposed Change

Table 3.5.5-1: PVNGS Unit 2 IWE Examination, Fall of 2018 Refueling Outage (2R21)

Report Number ASME Item No.

Method Accept Description of Abnormal Conditions Comments Component 2AZCNB0I Extent of Condition Walkdown 18-VT-2022 - N/A* VT-3 Yes Two indications were noted on the 85' of Typical unintentional type marks on the containment that appear to be from carts liner. UT thickness with a DL38+ and a other unintentional impacts into the THRU-COAT transducer were used to liner. Other than indications on report obtain local material thicknesses at the 18-VT-2021, no other notable indications indentation, ref 18-UT-2104. A dial pit were noted during the walk down that gauge was used to obtain the depth of the have not been documented in the IWE pits measure from the top of the coated program or coated over during surface with the following remaining construction or from precious repairs. ligament for indentations noted above.

85' indentation at ~330° Azimuth: 0.260" Metal, 0.006" coating, 0.016" Indentation

= 0.250" remaining wall 85' indication at - 0° Azimuth: 0.258" Metal, 0.006" coating, 0.020" Indentation

= 0.244" remaining wall

• All elevations were walked down 11/28/2018 specifically looking for punch marks for extent of condition.

Elevations include readably accessible portions of the containment liner on the 80', 90', 100', 120', 140', 150' and 168' of containment: This examination was not intended to document non-degradation indications (paint chips, small gouges, light surface rust, etc.).

18-VT-2023 - N/A 105' Elevation VT-3 Yes Single indentation noted at UT thickness with a DL38+ and a THRU-approximately the 30° Azimuth* COAT transducer were used to obtain local 125' Elevation Yes Single indentation noted at material thicknesses at the discussed approximately the 300° Azimuth** indentations, ref 18-UT-2104. A dial pit 4



Enclosure Attachment 5 Evaluation of the Proposed Change

Table 3.5.5-1: PVNGS Unit 2 IWE Examination, Fall of 2018 Refueling Outage (2R21)

Report Number ASME Item No.

Method Accept Description of Abnormal Conditions Comments Component 145' Elevation Yes 17 Indentations noted at approximately gauge was used to obtain the depth of the the 50° Azimuth*** pits measure from the top of the coated surface with the following remaining ligament for indentations noted above.

• 0.259" Metal Thickness, 0.006" coating thickness, 0.055" indentation:

0.259"+0.006"-0.055" = 0.210 remaining wall.

• • 0.284" Metal Thickness, 0.040" indentation: 0.284"-0.040" = 0.244" remaining wall.

• • • 0 .267", 0.283" and 0.281" Metal Thickness, unreadable coating thickness, 0.026", 0.020", 0.027" indentations:

0.267"-0.055" = 0.241", 0.283"-0.020" =

0.263", 0.281 "-0 .027" = 0.254" remaining wall.

Note all noted indentations appear to be legacy indications and would typically not be reportable or recordable for the IWE program.

Dust and some light surface rust noted inside the indentations. Many of the 145' indications appear to be made with a low stress stamp. The only indentation past 90% of the liner nominal thickness is at the 105' elevation.

Per discussion with civil engineer on 11/28/2018, the indentation is bounded by evaluation (min wall of 5/32inch).

Containment Penetration #60 18-VT-2024 - E4.11 VT-1 Yes Light Surface Corrosion Detected ID of Penetration No gross/excessive corrosion was detected. The deepest portion detected with a pit-gauge along the 7 to 8 Adjacent to weld affected inches of the root was 1/32'. Thickness measurements were taken using UT. See UT report 18-1054.

18-UT-2101, Containment liner, near west sump adj to 2JSIEV0474 1-foot grid, 7 feet up the A B C D wall and 3' wide, 8

• 0.265/0.009 0.270 0.270 5



Enclosure Attachment 5 Evaluation of the Proposed Change

Table 3.5.5-1: PVNGS Unit 2 IWE Examination, Fall of 2018 Refueling Outage (2R21)

Report Number ASME Item No.

Method Accept Description of Abnormal Conditions Comments Component measurements taken on 7 0.257/0.007 0.255/0.007 0.262 0.271 grid points. 6 0.265 0.263 0.261 0.271 5 0.245/0.009 0.250/0.007 0.259/0.006 0.250/0.012 4 0.262 0.263 0.264 0.265 3 0.263 0.264 0.261 0.264 2 0.263 0.270 0.257/0.006 0.261/0.006 1 0.274 0.263/0.019 0.251/0.014 0.251/0.011

• Not readable due to boron on wall as full decontamination of the area has not occurred.

Readings are (Liner thickness/coating if measurable on DL38+)

18-UT-2104, 2AZCNBOI Containment Liner Extent of Condition Zone 203 Elevation Azimuth Metal Thickness Coating Thickness Zone 204 85' 330° 0.260" 0.006" 85' 0° 0.258" 0.006" 105' 300° 0.259" 0.006" 125' 50° 0.284"

• 145' 50° 0.267"

• 145' 50° 0.283"

• 145' 50° 0.281" *

• Coating thickness readings were not obtained for some areas. The THRU-COAT transducer does not read coating under 0.005" thick and thick coatings are difficult to measure as well. Most of the areas scanned had thick coating and the coating thickness is included in the metal thickness readings.

6



Enclosure Attachment 5 Evaluation of the Proposed Change

Table 3.5.5-1: PVNGS Unit 2 IWE Examination, Fall of 2018 Refueling Outage (2R21) 18-UT-2105, Unit 2 Containment Penetration 60 7



Enclosure Attachment 5 Evaluation of the Proposed Change

Table 3.5.5-2: PVNGS Unit 2 IWE Examination, Spring of 2020 Refueling Outage (2R22)

Report Number Description of Abnormal ASME Item No. Method Accept Comments Conditions Component 2MCLEU58 Containment Penetration 20-VT-2064 - E-G/E8.10 VT-1 Yes No abnormal condition noted Bolting was uninstalled 12 studs and 24 nuts Penetration 58 Bolting were examined 2AZCNB0I Extent of Condition Walkdown 20-VT-2072 - E1.11 125' Indications VT-1 Yes 125-foot indication note at 300° Azimuth no change from report 18-VT-2023 Yes 1 indication at the~ 125', ~305° Azimuth 123' Indications Yes 3 indications at the ~ 123', ~275° Azimuth Yes 1 indication at the~ 123', ~ 290° Azimuth Condition Report 20-05413, identified marks on the containment liner. No indications measured deeper than 5/32 of an inch. All indications are acceptable per evaluation that allows a minimum wall of 5/32 of an inch.

8



Enclosure Attachment 5 Evaluation of the Proposed Change

Table 3.5.5-3: PVNGS Unit 3 IWE Examination, Spring of 2018 Refueling Outage (3R20)

Report Number Description of Abnormal Method Accept Comments Component Conditions UT Report 18-451, 3AZCNBOI Containment Liner Liner Metal Thickness 145', 215 degrees 0.260" 0.258" 0.200" 0.258" 0.260" 0.260" 0.260" Area measured 4" x 6". Location behind the polar crane disconnect box. Grind location is from construction UT Report 18-0543, 3MWCEU60/PEN 60 Zone 202 Metal Thickness Containment Wall 1" Above Weld .500"/.008" .470"/.007" .533"/.007"

.509"/.007" .461"/.008" .517"/.010" Weld .630"/.006" .540"/.008 .621"/.006" 1" Below Weld .547"/.006" .534"/.007" .533"/.007"

.639"/.007" .566"/.009" .624"/.005" 9



Enclosure Attachment 5 Evaluation of the Proposed Change

Table 3.5.5-3: PVNGS Unit 3 IWE Examination, Spring of 2018 Refueling Outage (3R20)

Report Number Description of Abnormal ASME Item No. Method Accept Comments Conditions Component Pen 60 18-VT-3010 - E1.1 Zone 202 VT-3 Yes Surfaces sand blasted to clean 87' Aux Building metal. No loss on material noted.

3AZCNB01 Containment Liner 18-VT-3011 - E1.11 Zone 203 Containment Liner 145' VT-1 Yes Non coated surface noted. Surface Ground area is behind the Polar Crane disconnect 215 degrees had been ground, from box. This box was removed during the exam.

construction, probably a lug Reference balance of plant report 18-451, removal area. Area measures 4" x minimum wall thickness was 0.200-inch with a 6". The deepest ground area 0.250-inch nominal liner wall. Acceptable per measures 3/32" using a pit gauge evaluation.

in an area-1" x 1". The remaining areas are 1/32" or less.

18-VT-3006 - E1.11 Zone 202, 203, 204 100' 0 degrees to 360 VT-3 Yes Non coated minor scratched surface degrees noted. No degradation noted 10



Enclosure Attachment 5 Evaluation of the Proposed Change

Table 3.5.5-3: PVNGS Unit 3 IWE Examination, Spring of 2018 Refueling Outage (3R20)

Report Number Description of Abnormal ASME Item No. Method Accept Comments Conditions Component 120' 270 degrees to Yes 5 bulging areas ~3' long 145' in 310 degrees front of PZR room due to construction anomalies.

3 bulging areas ~280 129' on PZR side of fuel canal, 5' long due to construction anomalies. Some scrapes and scratches. No degradation noted.

11



Enclosure Attachment 5 Evaluation of the Proposed Change

Table 3.5.5-4: PVNGS Unit 3 IWE Examination, Fall of 2019 Refueling Outage (3R21)

Report Number Description of Abnormal ASME Item No. Method Accept Comments Conditions Component 3AZCNB01 Containment Liner 19-VT-3061 - E1.11, E1.30 Zone 202, 203, 204, 205 77'-3" to 140'-6" General Yes No reject indications detected. Examinations were performed from the 80' Leak Chase VT-1, Yes No reject indications detected. (77'-3") of containment to the bottom the 140' 100' Per. Hatch VT-3 Yes No reject indications detected. (140'-6") of containment.

140' Per. Hatch Yes No reject indications detected. Typical indications were noted such as chipped Fuel Trans. Tube Yes No reject indications detected. paint, worm tracks in paint, legacy arc strikes, general surface corrosion, dents and other signs of mechanical interaction with the coating and liner.

19-VT-3062 - E1.11 Zone 203 Pen 53 Vault Side VT-3 Yes Slight surface corrosion, no other notable conditions.

3AZCNB01, Penetrations Outside of Containment 19-VT-3067 - E1.11 General Yes Slight surface corrosion, no other General visual and VT-3 of accessible portions Zone 202, 203, 205 / VT-3 notable conditions. of penetrations from outside of containment except mechanical penetrations 58, 60, and 61.

3AZCNB0I, Containment Liner 19-VT-3068 - E1.11 VT-3 Yes Slight surface corrosion. The paint around the code name plate is Zone 204 blistering some due to the location on the Pen 58 bottom of Pen 58 piping. Wrote CR to have the name plate removed and the penetration coated. Further VT examination will take place after name plate is removed.

19-VT-3069 - E1.11 Zone 202, 203, 204 140' 6" to bottom of the VT-3 Yes No reject indications detected. Examinations were performed from the 140' polar crane (140'-6") of containment to the bottom of the 12



Enclosure Attachment 5 Evaluation of the Proposed Change

Table 3.5.5-4: PVNGS Unit 3 IWE Examination, Fall of 2019 Refueling Outage (3R21)

Report Number Description of Abnormal ASME Item No. Method Accept Comments Conditions Component Coating repair area Yes No reject indications detected, sat polar crane. Typical indications were noted inspected for WO 5004702 for coating. such as chipped paint, worm tracks in paint, Indication noted by Civil Yes No reject indications detected. legacy arc strikes, general surface corrosion, Engineering Depth less than 1/32 of an inch. dents and other signs of mechanical interaction with the coating and liner.

19-VT-3081 - E1.11 Zone 203, 204 Coating Repair Areas VT-3 Yes SAT 3AZCNB01, Pen 60 and 61 Aux. Bld. Side 19-VT-3091 Zone 202 Pen 60 VT-1, Yes Coated area is sat. Some signs of VT-1 and VT-3 of accessible portion of the VT-3 light surface stains from penetration. Used horoscope on a stick to condensate off of the chill water examine the back of the penetrations.

line but no base material degradation noted.

Pen 61 Yes VT-1, slight corrosion at flued head to penetration weld joint. No other indications noted.

3MWCEU61, Pen 61 19-VT-3207 Zone 202 Pen 61 VT-1, Yes Inspected flued head to penetration VT-3 weld. No pitting noted after sand blasting. SAT for coating 19-VT-3103 - E1.11 Zone 202 Pen 61 VT-3 Yes No abnormal conditions noted. Insulation removed and surfaces coated. This Penetration coated. Coating is a post coating examination.

smooth and uniform.

13



Enclosure Attachment 5 Evaluation of the Proposed Change

Table 3.5.5-4: PVNGS Unit 3 IWE Examination, Fall of 2019 Refueling Outage (3R21)

Report Number Description of Abnormal ASME Item No. Method Accept Comments Conditions Component 3AZCNB01, Containment Liner 19-VT-3203 - E1.11 Zone 202 Coating Repair Per WO VT-3 Yes 3 small locations inspected. No 4650837 degradation noted. SAT for 115', 140° Azimuth coating.

19-VT-3205 - E1.11 Zone 201, 202, 203, 204, 205 RAS Sump A, Pen 23 General Yes No indication noted.

RAS Sump B, Pen24 / VT-3 Yes No indication noted.

Dome Yes No Abnormal conditions detected Dome exam consisted of elevation 195' and above (zones 201, 202, 203, 204). Top of rail

~207'. Some backing bar fitting, fit-up irregularities, tape, and slight misalignment that is all construction discontinuities.

VT-3 of accessible portion of the penetrations and containment liner from 195' and above.

19-VT-3207 - E1.11, E4.11 Zone 202 Pen 61 VT-1 Yes Inspected flued head to penetration VT-3 weld. No pitting noted after sand blasting. SAT for coating.

14



Enclosure Attachment 5 Evaluation of the Proposed Change

Table 3.5.5-5: PVNGS Unit 1 IWE Examination, Spring of 2016 Refueling Outage (1R19)

Report Number Description of Abnormal ASME Item No. Method Accept Comments Conditions Component 1AZCNB0l **STRUCT 16-VT-1007 VT-3 Yes Aux Bld. outside containment Some of the electrical penetrations had Zone 202, 203, 204 penetrations 100' to 140' were some oily looking residue around the examined as well as the outside penetration/concrete joint, same material MSSS Penetrations and Pen 58. existing on the electrical box joints.

Note some slight surface Limitations exist from seeing all bolting. All corrosion on outside portion s of visible bolting accessible from platforms, the uncoated surfaces. Pen 6 ladders and with the aid of a mirror. MSSS and Pen 58 had a substantial Penetrations have some obstructions due to amount of debris. Penetrations plant configuration.

11, 12, 46, 47, 64 and 65 have insulation/dust covers.

16-VT-1012 VT-3 Yes 77' 3" to the 120' 6" including No change from 1R18 exam reports.

Zone 202, 203, 204 inside penetrations, no During inspection there were multiple unacceptable condition noted. common indications noted that did not Exam included VT-3 at joint exceed the acceptance standards. These between the concrete and indications included concrete spatter, containment liner in the bulges, flaking paint/chips, worm tracks in basement of containment. paint, bent attachments /unistrut with no deformations in the containment liner, stains, slight surface rust, uncoated attachments with surface rust and construction stamping.

Limitations exist from seeing some areas around the penetrations and liner due to plant configuration.

16-VT-1014 VT-3 Yes No degradation detected. Visible All caps were on the Leak Chase Channels CBD-15 portion of the Leak Chase Channels examined.

16-VT-1015 Zone 203 VT-3 Yes 140' Personnel Lock Vessel, no Accessible areas examined.

indications noted.

15



Enclosure Attachment 5 Evaluation of the Proposed Change

Table 3.5.5-5: PVNGS Unit 1 IWE Examination, Spring of 2016 Refueling Outage (1R19)

Report Number Description of Abnormal ASME Item No. Method Accept Comments Conditions Component Zone 204 Yes 100' Personnel Lock Vessel. *Rust to be removed on the 19th of April Inside surface has some slight 2016 or as dictated by the outage schedule.

surface rust on the interior shell Re-examination will occur at this time to above the outside door and weld determine extent of corrosion loss; reject joint. report will be filled out if material removal Zone 204 Yes *Excessive rust was found on the is greater than 10% wall thickness.

outside of the exit door, 16-VT-1015 VT-3 Yes No abnormal conditions noted. Examined from the 140' CBD-13 16-VT-1017 Zone 202, 203, 204 VT-3 Yes Examination from the 120'-6" to General conditions noted as listed and 140'-6" of containment and Pen pictured in report 16-VT-1012 including

44. flaking paint, chipped paint, blisters, bulges Zone 203 Yes

• Ark Flash area, needs further in the liner, slight surface rust already investigation. recorded by the coatings engineer and Zone 204 Yes **Noted some corrosion on angle various types of stains not affecting the iron to containment wall joint function of the liner.

holding grating on the 140' elevation on both sides of the equipment hatch. Carpenters are working on scaffolding for further investigation.

Some limitations exist due to cables, conduit and electrical penetrations.

• Coaters to remove paint from arc flash area for further investigation.

• • WOs have been generated to build scaffolding to the corroded areas for further investigation.

16



Enclosure Attachment 5 Evaluation of the Proposed Change

Table 3.5.5-5: PVNGS Unit 1 IWE Examination, Spring of 2016 Refueling Outage (1R19)

Report Number Description of Abnormal ASME Item No. Method Accept Comments Conditions Component 16-VT-1018 VT-3 Yes Mechanical Penetrations Some limitations exist due insulation on Zone 202, 203 examined with only indications piping obstructing the view of the noted on Penetrations 60 and 61 penetrations.

due to rust. Acceptance of the Slight surface rust on some penetrations penetrations will be determined around heat affected zone and also on by UT. Pen 44 was noted to have support plates for smaller diameter piping.

Plywood inside the penetration. Only relevant condition under further investigation is mechanical penetrations 60 and 61.

16-VT-1027

• EQ Hatch Bolting VT-3 Yes Bolting sat, some slight surface *Used the new calibration card, for General rust on some bolts but no Visual of liner, VT-3 performed on the EQ degradation noted. hatch bolting. General Visual letters verified a 1/32-inch scale measuring 14/32 of an inch.

140'-6" to Polar Crane Yes Typical issues exist as staining, and other 140' flaking paint, worm tracks in Penetrations paint, concrete, on liner, and other issues shown in reports from 2014 with no change noted.

Also, historical rust spots exist but no flaking of the surface is occurring. Some dents were noted but acceptable in size.

Some obstructions exist due to plant equipment such as cable trays, HVAC, piping, and other plant structures. All accessible areas inspected.

16-VT-1028 Zone 205 RAS A VT-3 Yes Examined from top of the RAS suction, no indications noted.

17



Enclosure Attachment 5 Evaluation of the Proposed Change

Table 3.5.5-5: PVNGS Unit 1 IWE Examination, Spring of 2016 Refueling Outage (1R19)

Report Number Description of Abnormal ASME Item No. Method Accept Comments Conditions Component 16-VT-1031 Zone 205 RAS B VT-3 Yes Examined from top of the RAS suction, no indications noted.

16-VT-1032 Zone 202, 203 100' Manway VT-1 Yes Coating removed. Pressure Coating repairs listed above are near the T-retaining portion had minimal wall and other repairs on the 100' and 120' pitting -1/64" in depth. Originally of containment around the 110° location.

identified on report 16-VT-1015.

120' Arc Yes Arc area between penetrations Z52 and Z53 blistered paint but did not damage the liner, initial identification on report 16-VT-1017.

Coating Repairs Yes Few indications noted but acceptable.

16-VT-1033 Zone 201 Containment Liner General Yes No abnormal conditions noted Examined Containment liner from Polar Dome Crane Rail and above 16-VT-1034 Zone 202, 204 Zone 204 104ft - 005 VT-3 Yes 1" x 1" area, coating repair, bare metal (no indications)

Zone 202 84ft - 136 Yes 1.5" x 3.5" area, coating repair, bare metal. Minor surface scratches with no measurable depth.

16-VT-1037 Zone 204 18



Enclosure Attachment 5 Evaluation of the Proposed Change

Table 3.5.5-5: PVNGS Unit 1 IWE Examination, Spring of 2016 Refueling Outage (1R19)

Report Number Description of Abnormal ASME Item No. Method Accept Comments Conditions Component Outside of EQ Hatch VT-3 Yes No indications noted.

16-VT-1044 Zone 203 Zone 203 VT-3 Yes Minor surface scaling. No Penetration 44 flued head partially Penetration 44 evidence of material loss. obstructed by 4" H x 6" W pile of debris.

16-UT-1008 Pen 60 - General Area 0.507", 0.503" with Nominal approx. 0.525". General area bottom 1/4 is Pen 60, 61 0.506" - 0.529" Pen 61 - General Area 0.593", 0.586" with Nominal approx. 0.625". General area bottom 1/4 is 0.508" - 0.525" 19



Enclosure Attachment 5 Evaluation of the Proposed Change

Table 3.5.5-6: PVNGS Unit 1 IWE Examination, Fall of 2017 Refueling Outage (1R20)

Report Number Description of Abnormal ASME Item No. Method Accept Comments Conditions Component 17-VT-1101 - E1.11 Zone 202 Penetration 60 VT-3 Yes No abnormal condition noted.

Some minor shallow pitting noted along bottom of penetration.

17-1074 1MWCEU60 UT of Penetration 60 Scanned 18" of the penetration sleeve perpendicular to axis. Lowest reading by wall is .618", average reading is .622". Average reading by weld is .520" 20



Enclosure Attachment 6 Evaluation of the Proposed Change

ATTACHMENT 6:

Results of Recent IWL Examinations



Enclosure Attachment 6 Evaluation of the Proposed Change

Indication Category The following Indication Categories are utilized in Table 3.5.5-7 (PVNGS Unit 1), Table 3.5.5-8 (PVNGS Unit 2), and Table 3.5.5-9 (PVNGS Unit 3):

 NI - No Indication

 RI - Relevant Indication

 IO - Information Only Table 3.5.5-7, PVNGS Unit 1 IWL Concrete Examination, 2016 - 2017 Report Number Type of Acceptable Indication Description of Conditions Notes Zone Drawing Examination Category IWL-2016-1016 VT-3C YES IO Conditions reported in 2012 have not changed. Spalling at She-bolt patches was 18 110-C6 Remote Bug holes, poor surface finish, and some grout noted during the baseline exam.

patches have popped out at she-bolts.

IO Two areas are noted as having very fine spider cracking, tight and closed in 2012.

RI Dark rectangular rust stains at 2 she-bolt locations.

RI 4" diameter spall note at 1 she-bolt location.

Spall is greater than 1" deep. Dark rust stains originate from the center of the spall.

IWL-2016-1017 VT-3C YES IO 1. Previously reported data from 2012 is Condition 4 is grout patches near 18 110-C7 Remote accurate. she-bolt popping out. This is not IO 2. Bug holes are present throughout this zone. a structural issue.

IO 3. Degraded and popped out grout patches at she-bolt locations.

RI 4. One 6" X 10" area of concrete has popped out and is separating from the wall at between 2 she-bolt locations.

RI 5. Vertical and horizontal rust stains originate from the she-bolt directly above.

IWL-2016-1020 VT-3C YES IO Previously reported conditions from 2012 do not The 4ft diagonal crack is within 17 110-D2 Remote match this zone. Tier 1 acceptance criteria.

1



Enclosure Attachment 6 Evaluation of the Proposed Change

Table 3.5.5-7, PVNGS Unit 1 IWL Concrete Examination, 2016 - 2017 Report Number Type of Acceptable Indication Description of Conditions Notes Zone Drawing Examination Category RI There is an approximately 4ft diagonal shrinkage crack that extends from the 146ft construction joint. Surface finish is poor throughout this entire zone; therefore, the exact extent of the crack cannot be determined.

Crack is less than .010" wide. The entire area is riddled with crazed cracking and pattern cracking as well.

IO There are bug holes and voids throughout the entire zone.

IO Grout work at the 146ft elevation construction joint shows several vertical cracks. Grout is separating from the wall.

IWL-2016-1022 VT-3C YES IO Previous conditions recorded in 2012 do not Grease does not negatively 17 110-D4 Remote match this zone. impact concrete. Change to IO Poor surface finish in this entire area, especially stain will be monitored in the at construction joint patched grout. next IWL exam.

IO Patched area does not match elevations established on zone drawings.

IO Bug holes are present throughout this zone.

RI There is evidence of grease leakage from one she-bolt location. This location is at the 145ft elevation, and 8ft east of the missile door.

Moderate pattern cracking exists as well and seems to originate from this spalled area.

2



Enclosure Attachment 6 Evaluation of the Proposed Change

Table 3.5.5-7, PVNGS Unit 1 IWL Concrete Examination, 2016 - 2017 Report Number Type of Acceptable Indication Description of Conditions Notes Zone Drawing Examination Category IWL-2016-1027 VT-3C YES IO Previous data from 2012 records bug holes in Indications are less than Tier 1 17 110-E1 Remote this area and a repaired bearing plate rust criteria.

stain.

RI 1 additional very fine vertical crack that is 20ft long runs through the entire zone and stops at the top and bottom construction joints.

Estimated to be less than 0.010" wide.

RI 1 additional very fine vertical crack that is 10ft long run across the upper half of this zone from construction joint to construction joint.

Estimated to be less than 0.010" wide.

IO Bug holes and small voids are present throughout the zone.

IWL-2016-1029 VT-3C YES IO Note: As reported in 2012, this is a limited The horizontal crack is less than 17 110-E3 Remote exam area because of the equipment hatch and Tier 1 criteria.

missile doors.

IO Moderate size bug holes are present throughout the entire zone.

IO Previously recorded degraded grout at the construction joint has failed and popped out.

The grout is cracking and continuing to separate from the joint.

RI 1 additional horizontal crack appears to be <

0.010" extends across the entire zone at approximately 170ft elevation above missile door.

IWL-2016-1035 VT-3C YES IO Previous data from 2012 only records small bug Indications are less than Tier 1 17 110-F1 Remote holes for this zone. criteria.

RI 1 additional very fine vertical crack that is 10ft long run across the upper half of this zone from construction joint to construction joint.

3



Enclosure Attachment 6 Evaluation of the Proposed Change

Table 3.5.5-7, PVNGS Unit 1 IWL Concrete Examination, 2016 - 2017 Report Number Type of Acceptable Indication Description of Conditions Notes Zone Drawing Examination Category Estimated to be less than 0.010" wide.

IWL-2016-1037 VT-3C YES IO No change to conditions recorded in 2012. The edge spalling appears to be 17 110-F3 Remote RI Edge spalling with dark to black rust stains from from removal. The discoloration the 2 lower embedded plates. The same was present in 2001. It was condition exists in zone G3 and was accepted by determined not to be rust in engineer review. 2001 by the program owner.

IO Bug holes and small voids present throughout this entire zone.

IWL-2016-1043 VT-3C YES IO No change to condition reported in 2012. CMWO was generated to repair 17 110-G1 Remote RI The spall reported at the 210ft elevation that is the corner edge spall.

4" dia. X 3/4" deep has not yet been repaired.

CR was issued in 2012.

IO Previous 2012 data indicates rust on an embedded plate in this zone. The plate could not be located during this 2016 exam. The first embedded plate visible is in zone G3.

IWL-2016-1045 VT-3C YES IO No change to conditions recorded in 2012. Repair is part of CMWO 4215690.

17 110-G3 Remote RI Edge spalling with dark to black rust stains from No changes since 2001.

embedded plates. Same condition exists in zone F3. Previous Conditional Report was generated to rework this area has not been addressed.

IWL-2016-1053 VT-3C YES IO Previously recorded data indicates an edge spall The cracks in this zone were 14 111-A5 Remote at Penetration #7. It has been repaired. marked with chalk during prior IO Penetration #69 has two shrinkage cracks that exam. They are not noted in are tight and less than 0.005" wide that extend previous IWL reports. Chalk grid approximately 2ft each from the edge of the is noted on plant drawing. The penetration. coating below Pen #26 is IO There is one shrinkage crack less than 0.005" cracked as well.

that is vertical between Pens #25 and #61 IO 1 additional shrinkage crack extends from floor 4



Enclosure Attachment 6 Evaluation of the Proposed Change

Table 3.5.5-7, PVNGS Unit 1 IWL Concrete Examination, 2016 - 2017 Report Number Type of Acceptable Indication Description of Conditions Notes Zone Drawing Examination Category level vertical 15ft just to the right of Pen #61 and is less than 0.005" wide.

IO 1 additional shrinkage crack is approximate 0.020" wide and extends across the bottom half of this zone below Pen #39.

IO 1 additional shrinkage crack extends vertical 4ft and is 0.020" wide, below Pen #26 and stops at the middle construction joint.

RI 1 additional shrinkage crack is greater than 0.025" wide in several spots. It extends from floor grade vertical to Pen #26.

IWL-2016-1056 VT-3C YES IO No change in previously reported area The flaking is a thin layer. There 14 111-A8 Remote conditions: Pigeon excrement on grease caps, are no signs of corrosion in the Bug holes, small voids, surface abrasions, poor area.

finish at all she-bolts locations, surface stains throughout this zone. Degraded grout patches over construction joints, small areas have popped out.

RI Concrete flaking below top construction joint over area approx. 5' x 1'. Note: This condition requires RPE review.

RI Dark grease stain area approx. 2' x 1' wide leaching through zone wall. Note: This condition requires RPE review.

IWL-2016-1058 VT-3C YES IO Previous data from 2012 only records small bug The reported edge spalls are 14 111-B4 Remote holes as a general condition. from initial construction. Coating RI Embedded plates beneath Penetration #45 and is in good condition indicating no adjacent to it have large edge spalls, 3 total. degradation has occurred.

All other embedded plates in this zone and adjacent zones have been grout repaired.

These edge spall have been painted over.

5



Enclosure Attachment 6 Evaluation of the Proposed Change

Table 3.5.5-7, PVNGS Unit 1 IWL Concrete Examination, 2016 - 2017 Report Number Type of Acceptable Indication Description of Conditions Notes Zone Drawing Examination Category IO There is 1 additional shrinkage crack that extends from the 100ft floor grade to Penetration #45. It is less than 0.005" wide.

IWL-2016-1059 VT-3C YES IO No change to general conditions reported in WO reworked a patch at 14 111-B5 Remote 2012 as: Surface stains. penetration 42. No further RI In 2012 the program owners review states that degradation was noted at Pen a construction joint grout patch at penetration 42.

1. 42 was reworked under W.O. #2924945.

Grout patch at penetration #42 has not been reworked. The same surface condition recorded in 2012 still exists.

IWL-2016-1064 VT-3C YES IO No change to general conditions reported in Exposed rebar is documented in 14 111-C4 Remote 2012 as: Surface stains, small bug holes. nonconformance report. Clear IO There is a shrinkage crack approximately 0.005" sealer is still intact.

wide between Penetrations #89 and #91.

RI There is 2ft of horizontal exposed rebar inside Penetration #91.

IWL-2016-1065 VT-3C YES IO No change to general conditions reported in The coating on the spall near Pen 14 111-C5 Remote 2012 as: Surface stains, small bug holes. 85 is intact indicating no active IO 2 shrinkage cracks previously noted as less than degradation is occurring.

0.010" wide between penetrations #83 & #85 and between penetrations #85 & #87.

IO 1 additional shrinkage crack noted between Penetrations #87 & #89, less than 0.010" wide.

RI 6" X 3" X 1/2" deep edge spall noted at the bottom of Penetration #85. It has been painted over.

IWL-2016-1066 VT-3C YES IO No change to general conditions reported in NCR documents exposed rebar in 14 111-C6 Remote 2012 as: Surface stains, small bug holes. several penetrations in this zone.

IO Poor surface finish noted at the construction The clear sealer is providing joints of Penetrations #73 and #75. cover for the rebar where the 6



Enclosure Attachment 6 Evaluation of the Proposed Change

Table 3.5.5-7, PVNGS Unit 1 IWL Concrete Examination, 2016 - 2017 Report Number Type of Acceptable Indication Description of Conditions Notes Zone Drawing Examination Category RI There is a cold joint inside of Penetration #77. concrete cover was too thin. The It has irregular surface geometry and there is debris in the penetration is also excessive amounts of debris caught in the joint coated and is showing no signs including plastic bag, tape, foam, and a of degradation.

cigarette. The debris has been clear coated with surrounding concrete. The spall at this location is 1" deep. There is also 1" of exposed rebar.

RI There is 6" of exposed rebar inside of Penetration #73.

IO There is a previously reported 36" horizontal Shrinkage crack 12" above Penetration #79.

The crack extends from a grout patch in the containment wall but is less than 0.010" wide.

IWL-2016-1076 VT-3C YES IO No change to conditions reported in 2012.

13 111-E2 Remote IO Bug holes noted throughout the zone.

RI Surface rust discoloration and slight abrasion possibly due to ADV steam release.

IO Two sections grout have popped out at the 176ft construction joint. 1 is 4" long, and 1 is 12".

RI There is a 10" X 3" X 3/8" deep abrasion noted in the upper half of this zone.

IO It should be noted that the bottom half of this zone must be examined from inside the MSSS.

IWL-2016-1077 VT-3C YES IO No change to conditions reported in 2012.

7



Enclosure Attachment 6 Evaluation of the Proposed Change

Table 3.5.5-7, PVNGS Unit 1 IWL Concrete Examination, 2016 - 2017 Report Number Type of Acceptable Indication Description of Conditions Notes Zone Drawing Examination Category IO Bug holes noted throughout the zone.

RI Surface rust discoloration and slight abrasion possibly due to ADV steam release.

IO Could not locate previously recorded 2" X 1/2" deep abrasions.

IO 1 additional horizontal shrinkage crack noted that is estimated to be less than 0.005" wide.

IO One 8" section of grout has popped out at the 176ft construction joint.

IO It should be noted that less than half of this zone is above the MSSS elevation, and the rest must be accessed from inside the MSSS.

IWL-2016-1078 VT-3C YES IO General area conditions are as follows:

14 111-E4 Remote IO Small bug holes throughout the zone.

IO Shallow abrasions probably due to construction form removal.

IO Poor surface finish around she-bolts.

RI Generally, the surface is peeling and eroding in several locations with minor surface material loss. There is no exposed aggregate at this time. Possibly due to steam release from ADV's.

IO Note: 156ft to 166ft of this zone must be partially observed from inside the MSSS.

IWL-2016-1079 VT-3C YES IO Previous data from 2012 reports the following The shrinkage cracks are well 14 111-E5 Remote only as general area conditions: bug holes, below Tier 1 acceptance criteria.

small voids, surface rust discoloration, and light The surface condition is abrasion. consistent with what was RI Additionally, sample photos attached were identified during the baseline taken as record of the current surface condition exam.

8



Enclosure Attachment 6 Evaluation of the Proposed Change

Table 3.5.5-7, PVNGS Unit 1 IWL Concrete Examination, 2016 - 2017 Report Number Type of Acceptable Indication Description of Conditions Notes Zone Drawing Examination Category of staining, discoloration, abrasion, and surface erosion. No exposed aggregate at this time.

RI There are several fine shrinkage cracks, both horizontal and vertical. Too many to document them all. The most severe are documented on the zone map. No cracks exceed 0.005" in width.

IWL-2016-1080 VT-3C YES IO General area conditions are as follows: The surface condition is 14 111-E6 Remote IO Small bug holes throughout the zone. consistent with what was IO Light surface rust discoloration. reported during the baseline RI The surface seems to be peeling or flaking, exam.

signs of erosion are evident, with minor surface material loss. There is no exposed aggregate.

IO Several shrinkage cracks have not been previously reported. All are tight and very fine.

Estimated to be less than 0.005" wide.

IO There is a 6ft section of grout at the 166ft construction joint, that is degraded. It is popping out and separating from the wall.

IWL-2016-1081 VT-3C YES IO Previously recorded data includes bug holes and The crack appears to have 14 111-E7 Remote small voids, slight surface abrasions, and very surface widening. The edges fine horizontal and vertical shrinkage cracks. have spalled making the crack This includes a 60ft shrinkage crack that runs appear wider. No other signs of completely through this zone and F7 and G7. degradation in the area.

IO There are two 6" sections of grout that have popped out at the 166ft construction joint. The grout work is degraded and separating from the wall.

IO There is a 1" X 1" void at a she-bolt location where an exposed aggregate is visible.

RI Two 6" sections of the 20ft long Horizontal 9



Enclosure Attachment 6 Evaluation of the Proposed Change

Table 3.5.5-7, PVNGS Unit 1 IWL Concrete Examination, 2016 - 2017 Report Number Type of Acceptable Indication Description of Conditions Notes Zone Drawing Examination Category crack at 167ft are greater than 0.025" by visual comparison to the gray placard.

IWL-2016-1082 VT-3C YES IO General area conditions are as follows: The surface condition is 14 111-E8 Remote IO Small bug holes throughout the zone. consistent with what was IO Light surface rust discoloration run down the reported in 2001. A VT-1 exam wall from zone 08 above. was performed in 2001 and did RI The surface seems to be peeling or flaking, not identify any significant signs of erosion are evident, with minor surface impacts to the structure.

material loss. There is no exposed aggregate.

IO 166ft grout at the construction joint is degraded and separating from the wall. One spot 8" long has popped out.

IWL-2016-1083 VT-3C YES IO No apparent changes to conditions reported in Program Owner Review. H21-14 111-F1 Remote 2012. 044 is scheduled to have the IO Random bugholes and small voids. gasket replaced in Feb. 2017 IO There are degraded grout patches and small pop-outs at most she-bolt locations.

RI Previously reported grease leakage from above is still present. Grease runs down the wall at the inner corner of buttress #1. The grease originates from behind the retention plate of H21-044.

IWL-2016-1084 VT-3C YES IO General area conditions are as follows: CMWO has been generated to 13 111-F2 Remote IO There are bug holes and small voids throughout allow access during the recent the zone. This zone is mostly covered by dark Unit 1 outage.

staining from ADV steam release.

RI The surface is peeling and eroding in several *CR written.

areas due to the steam from the ADV's IO *Previous indications of a 6" void that is 1/2" deep either was mis mapped on the zone 10



Enclosure Attachment 6 Evaluation of the Proposed Change

Table 3.5.5-7, PVNGS Unit 1 IWL Concrete Examination, 2016 - 2017 Report Number Type of Acceptable Indication Description of Conditions Notes Zone Drawing Examination Category drawing or does not exist.

IO Previously mapped area of particular poor surface finish could not be determined, because the whole zone has poor surface finish.

RI There is a 3" X 8" pop out that is greater than 1" deep that has wood material trapped inside.

RI There is a 2ft X 1 ft grout patch below the 186ft construction joint. The bottom portion of the grout has popped out and left an 8" area that is 3/4" deep with exposed aggregate.

IO There is 1, 5ft horizontal shrinkage crack in the bottom half of the zone less than 0.005" wide.

IO There is 1 additional vertical shrinkage crack that is 10ft long and less than 0.005"wide.

• While performing a general visual, VT-3, exam of the Unit 1 Containment concrete (December 21, 2016) an indication was identified that requires more detailed examination. ASME BPVC Section XI Article IWL-2310 requires a detailed exam, VT-1, be performed when suspect areas are noted in a general exam. The indication was identified in previous exams as a 6-inch-long, 1/2-inch-deep spall; however, the utilization of new cameras allowed for a higher resolution examination of the area. This indication does not impact the structures ability to perform its function based on the following logic: There has been minimal change since the indication was first recorded in 2006 and there are no signs of steel reinforcement corrosion (rust) present. The Containment structure successfully passed the integrated leak rate test in 2014 and no indications have been noted in the liner plate exams (IWE). The Containment concrete shell thickness at this location is 4 feet and heavily reinforced /post-tensioned.

Concrete cover over the reinforcement at this location is at least 4 inches.

The indication is located approximately 15 ft above the MSSS building roof; therefore, a scaffold will be required to reach the area. The area is located adjacent to the ADV stacks.

This CR documents the need to perform a detailed exam on a specific spall discovered on the exterior of the Unit 1 Containment Structure while performing a general visual exam. A spall is flakes of material, in this case the concrete, generally caused by weathering. As stated in the CR there is no evidence this spall has impacted the Unit 1 Containment Structures ability to perform the specified Safety Function. Integrated Leakage Rate Test was performed satisfactorily and acceptance reviewed on November 6, 2014. The spall has had minimal change since the first indication was noted in 2006. There is no evidence of steel reinforcement corrosion (rust) present indicating the spall is deeper than it appears.

There have been no signs of liner plate degradation during the performance of examinations. As such trend code OPERABLE will be applied. EWR 11



Enclosure Attachment 6 Evaluation of the Proposed Change

Table 3.5.5-7, PVNGS Unit 1 IWL Concrete Examination, 2016 - 2017 Report Number Type of Acceptable Indication Description of Conditions Notes Zone Drawing Examination Category has been created to perform a detailed examination of the spall.

Report Number IWL-2016-1084 was signed off as acceptable on August 22, 2017.

IWL-2016-1085 VT-3C YES IO Previous data from 2012 records the following: The reported abrasion appears to 13 111-F5 Remote degraded grout patches have pop outs and fine be poor surface finish from shrinkage cracks. construction.

IO Additionally, most of this zone is peeling and shows signs of erosion due to ADV steam release.

IO There are 2 additional 10ft shrinkage cracks that are vertical throughout the top half of this zone.

RI There is a 1ft tall by 2ft wide abrasion below the 186ft construction joint. Less than 1/4" deep.

There is no exposed aggregate.

IWL-2016-1086 VT-3C YES IO No change to conditions reported in 2012. The surface finish is consistent 14 111-F4 Remote IO Bug holes are present throughout this zone. with what was reported in 2001.

IO Dark rust stains exist possibly due to ADV steam release.

RI The surface appears to have minor erosion and peeling, again possibly due to ADV's. No aggregate is exposed.

IWL-2016-1087 VT-3C YES IO Previous data from 2012 records a pop out 8" X Comparison of photos to the 14 111-F3 Remote 8" X 1" depth, of a grout patch below the 186ft 1012 sketch indicated no construction joint. changes have occurred. It IO Previous Program owner review dismisses the appears the grout patch was indication as a grout condition, not the performed to cover poor surface containment wall. finish from construction.

RI The condition still exists, and is 1 ft below the construction joint, in the containment wall.

IWL-2016-1088 VT-3C YES IO General area conditions are as follows: The surface condition is 12



Enclosure Attachment 6 Evaluation of the Proposed Change

Table 3.5.5-7, PVNGS Unit 1 IWL Concrete Examination, 2016 - 2017 Report Number Type of Acceptable Indication Description of Conditions Notes Zone Drawing Examination Category 14 111-F6 Remote IO Small bug holes throughout the zone. consistent with what was IO Light surface rust stains run down the wall from identified in 2001.

above.

RI The surface seems to be peeling or flaking, signs of erosion are evident, with minor surface material loss. There is no exposed aggregate.

IWL-2016-1089 VT-3C YES IO General area conditions are as follows: The surface condition is 14 111-F7 Remote IO Small bug holes throughout the zone. consistent with what was IO Light surface rust stains run down the wall from identified in 2001.

above.

RI The surface seems to be peeling or flaking, signs of erosion are evident, with minor surface material loss. There is no exposed aggregate.

IO Previously reported fine shrinkage crack runs through this zone. It originates in zone E7 and continues through zone G7. Overall length is greater than 60ft. Previously reported as less than 0.010" wide.

IWL-2016-1090 VT-3C YES IO General area conditions are as follows: The surface condition is 14 111-F8 Remote IO Small bug holes throughout the zone. consistent with what was IO Light surface rust stains run down the wall from identified in 2001.

the G8 zone above.

RI The surface seems to be peeling or flaking, signs of erosion are evident, with minor surface material loss. There is no exposed aggregate.

IO Previously reported fine shrinkage crack 10ft long and less than 0.010" wide.

IO Previously reported horizontal fine shrinkage crack 7ft long and less than 0.010" wide.

IWL-2016-1091 VT-3C YES IO No change to general conditions reported in Rust stains were reported around 13



Enclosure Attachment 6 Evaluation of the Proposed Change

Table 3.5.5-7, PVNGS Unit 1 IWL Concrete Examination, 2016 - 2017 Report Number Type of Acceptable Indication Description of Conditions Notes Zone Drawing Examination Category 13 111-G1 Remote 2012. she-bolts in 2006 and 2012.

IO Grease leak from H21-044 from above still Grease leak is minor from H21-exists and runs down the wall into this zone and 050.

zones below.

RI Grease leaking onto concrete from above from grease cap H21-050.

RI At the 210ft elevation there are rust stains around she-bolt locations. There is also fine pattern cracking present in this area.

IWL-2016-1098 VT-3C YES IO Previous data only records the obvious dark rust Rust like stains have been 14 111-G8 Remote discoloration of this zone. present since construction. No RI There is no exposed metal surfaces in the area, changes have been documented.

but the rusts appear to originate from the 210ft construction joint, and run down the wall to the zones below.

IO Additionally, 12ft-16ft of grout has popped out at the 206ft and 210ft construction joints.

IO 1 additional fine shrinkage crack 3ft vertical above the 210ft elevation.

IWL-2016-1099 VT-3C YES IO No change in previously reported area Prior repots listed poor surface 15 112-A1 Remote conditions: Pigeon excrement on grease caps, finish in the entire zone. The Bugholes, small voids, surface abrasions, poor flaking is a thin layer and does finish at all she-bolts. not expose any large aggregate.

RI Concrete flaking in a 3' x 4' area. No signs of corrosion.

IO 2 Shrinkage cracks noted: (1) Length 18' - 9" x

<.025" wide. (2) Length 8'-9" x <.025".

IWL-2016-1102 VT-3C YES IO The data recorded in 2012 for general area Void is still covered in clear 15 112-A4 Remote was: Bug holes throughout the zone. Light coating and is not showing any surface stains. Shrinkage cracks through a signs of degradation. There are grout patch less than no rust stain present in the 0.010" wide, and 1 vertical shrinkage crack 4ft vicinity of the exposed she-bolts 14



Enclosure Attachment 6 Evaluation of the Proposed Change

Table 3.5.5-7, PVNGS Unit 1 IWL Concrete Examination, 2016 - 2017 Report Number Type of Acceptable Indication Description of Conditions Notes Zone Drawing Examination Category long on the right side above the 87ft indicating no active corrosion is construction joint, less than 0.005" wide. occurring.

IO Additional fine shrinkage crack between Penetration #20 and Penetration #54. Less than 0.005" wide.

IO There are two 1ft shrinkage cracks extending from Penetration #35. Less than 0.005" wide.

IO There are two 10ft vertical shrinkage cracks extending from the 87ft construction joint that are less than 0.005" wide.

IO There is one vertical shrinkage crack that extends from the 87ft construction joint to Pen

1. 20, less than 0.005" wide.

RI There is a 1" X 1" X 1" deep void on the right-hand side of the previously recorded grout patch.

RI There are 2 exposed, rusted she-bolts adjacent to the previously recorded grout patch.

IWL-2016-1103 VT-3C YES IO The data recorded in 20 I 2 for general area Coating over the spall is in good 15 112-A5 Remote was: Bug holes throughout the zone. condition. No active corrosion or IO Several additional shrinkage cracks noted deterioration present.

throughout the bottom half of the zone and documented on the current zone drawing. All are less than 0.005" wide.

IO Penetrations 40 and 52 have minor edge spalling less than tier 1 criteria.

RI Penetration 29 has a 6" X 6" spall that is 1/2" deep and has been painted over.

IO There is a fine shrinkage crack that runs between Penetrations 15 and 19. Less than 0.010" wide.

15



Enclosure Attachment 6 Evaluation of the Proposed Change

Table 3.5.5-7, PVNGS Unit 1 IWL Concrete Examination, 2016 - 2017 Report Number Type of Acceptable Indication Description of Conditions Notes Zone Drawing Examination Category IO There is no access to this zone at this time.

Crane support and scaffold will be required.

IWL-2016-1105 VT-3C YES IO No change in previously reported area Flaking concrete is thin. No 15 112-B1 Remote conditions: Pigeon excrement on grease caps, corrosion or exposed aggregate bugholes, small voids, surface abrasions, poor is present.

finish at all she-bolts locations, surface stains.

RI Concrete flaking in a 3' x 1' area and one small area 6" x 1". This item requires RPE review.

Shrinkage crack noted: Length 5' x <.025" wide.

IWL-2016-1109 VT-3C YES IO Previously recorded data from 2012 only Coating is intact. No active 15 112-B5 Remote records small bug holes throughout the zone. degradation is occurring.

RI There is a 4" diameter X 3/8" deep spall that has been painted over, below Penetration #4.

IO There is a 4" X 2" X 1/4" deep impact that has been painted over.

IWL-2016-1111 VT-3C YES IO No change in previously reported area 16 112-B8 Remote conditions: Bugholes. Small abrasions throughout zone due to equipment impact.

Poor surface conditions at she-bolt areas.

RI Construction joint grout patch pop out 3'-6" length with exposed aggregate.

RI Surface abrasion 3" in length x 2" wide x .250" maximum depth. RPE review required RI Surface abrasion 4" length x 2" width x .375" maximum depth. Crack noted on right upper corner 2" length x less than .015" width. RPE review required IWL-2016-1114 VT-3C YES IO Poor surface finish around Penetration #61. The exposed rebar in this zone 15 112-C3 Remote IO Minor surface stains and discoloration. was previously evaluated. The IO No evidence of grout patches leeching. clear coat is still intact.

16



Enclosure Attachment 6 Evaluation of the Proposed Change

Table 3.5.5-7, PVNGS Unit 1 IWL Concrete Examination, 2016 - 2017 Report Number Type of Acceptable Indication Description of Conditions Notes Zone Drawing Examination Category IO Bug holes throughout this zone.

RI There is a 1 ft section of exposed rebar inside Penetration #59. The surface area and the re bar are bulged out in appearance.

IWL-2016-1115 VT-3C YES IO No change to previously recorded area 15 112-C4 Remote conditions from 2012.

IO Minor surface discoloration and staining noted.

IO Poor surface finish around Penetration #53.

RI 1 grout patch over an embedded plate is leeching with white stains running down the wall.

IWL-2016-1119 VT-3C YES IO No change in previously reported area 16 112-C8 Remote conditions: Bugholes present in the entire area.

Small abrasions throughout zone due to equipment impact. Poor surface conditions at she-bolt areas.

RI Degraded grout patches in zone and construction joint between C8 and D8.

Erosion/rough surfaces area span entire length from buttress to B7. (Not previously recorded.)

Note: RPE Review required.

IWL-2016-1120 VT-3C YES IO Previously reported general conditions are as 15 112-D1 Remote follows: Bugholes and small voids throughout the zone. Abrasions from construction forms.

Poor surface finish at she-bolts.

IO Previously reported 6"x2" edge spall has been repaired by grout.

RI There is an 8" crack that breaks across the outer edge of Buttress #2 and between H32-019 & H32-020. Crack is at least 0.075" wide and separating from the edge of the buttress.

17



Enclosure Attachment 6 Evaluation of the Proposed Change

Table 3.5.5-7, PVNGS Unit 1 IWL Concrete Examination, 2016 - 2017 Report Number Type of Acceptable Indication Description of Conditions Notes Zone Drawing Examination Category IWL-2016-1128 VT-3C YES IO No active leakage exists that was previously During the Unit 1 tendon test a 15 112-E1 Remote recorded. better viewing angle was IO Conditions recorded in 2012 include bug holes available. The cracks and grout small voids, some rust staining, and very fine patches on the edge of buttress spider cracking or crazed cracking throughout are all acceptable and are not the zone. separating from the wall.

RI Edge and corner of buttress #2 is degraded, cracking and spalling from this elevation and above. There is a significant crack 6" long across the corner of the buttress #2 and next to tendon cap H32-029. Previous attempts at grout patching of spallings are degraded and separating from the wall. Some grout has popped out. Several cracks exist from this elevation and above at the edge of the buttress.

IWL-2016-1131 VT-3C YES IO In 2012 previous reported conditions included: The width of the crack is due to 15 112-E4 Remote Bug holes and small voids, minor rust staining surface widening. A ladder was surface abrasions, erosion, and degraded grout used to perform a more detailed patches over construction joints. exam and the crack was less IO Erosion previously noted appears to be further than 0.005" wide.

degrading with minimum surface loss, especially around she-bolt locations.

RI There is an 8ft horizontal crack noted that is greater than 0.050" wide at its center widest dimension. The crack appears to originate from a vertical construction form seam and extends left and right tapering to less than 0.005" wide.

IWL-2016-1136 VT-3C YES IO Conditions reported in 2012 include: Bugholes Buttress edge was examined 15 112-F1 Remote and small voids. during the tendon test. The RI There is a 6" crack across the edge of the cracks meet Tier 1 acceptance buttress adjacent to H32-035 tendon cap. Edge criteria and the grout patches 18



Enclosure Attachment 6 Evaluation of the Proposed Change

Table 3.5.5-7, PVNGS Unit 1 IWL Concrete Examination, 2016 - 2017 Report Number Type of Acceptable Indication Description of Conditions Notes Zone Drawing Examination Category of buttress above and below this elevation is are still adhered to the degraded and failing. Several grout patches surrounding concrete.

have separated from the wall. There are too many cracks to list between the tendon caps and the edge of buttress #2.

IO 1 additional vertical shrinkage crack noted that is 10ft long but less than 0.010" wide.

IWL-2016-1143 VT-3C YES IO Conditions reported in 2012 include: Bugholes Crack was examined during the 16 112-F8 Remote and small voids, orange discoloration from form tendon test while access to the removal, and poor surface finish at she-bolts containment surface was with some popped out grout patches. available. Below surface IO There is one additional shrinkage crack that is widening the crack was less than 10ft long and less than .010" wide that runs 0.015" wide.

from the bottom construction joint to the middle construction joint.

RI There is an additional crack that is approximately 18" is length overall but is estimated by visual comparison to the gray placard to be greater than 0.025" wide at its widest dimension. This is beyond Tier 1 criteria. The crack appears to follow a vertical form joint.

IWL-2016-1150 VT-3C YES IO Conditions reported in 2012 include: Bugholes 16 112-G7 Remote and small voids, orange discoloration from form removal, and poor surface finish at she-bolts with some popped out grout patches.

IO There are light rust stains in this zone and all of the zones at this elevation.

RI There is an embedded she-bolt from construction that is peened over. An attempt was made to grout over it. That grout patch 19



Enclosure Attachment 6 Evaluation of the Proposed Change

Table 3.5.5-7, PVNGS Unit 1 IWL Concrete Examination, 2016 - 2017 Report Number Type of Acceptable Indication Description of Conditions Notes Zone Drawing Examination Category has popped out. The bolt is now exposed degraded and rusted. The peened over portion is approximately 4" in length.

IWL-2016-1152 VT-3C YES RI Active grease leak at tendon H21-044 grease Grease leak was repaired during 1 of 3 Remote cap. Grease runs down the buttress from the the Unit 1 tendon test in grease cap flange. February 2017.

IO No change in previously reported general area conditions: Bugholes, voids, poor finish on grout patch areas, shrinkage cracks, fine vertical shrinkage cracks. Cracks run from the springline up towards the dome crest. Cracks are 15' to 40' long but <0.010" wide 20



Enclosure Attachment 6 Evaluation of the Proposed Change

Table 3.5.5-8, PVNGS Unit 2 IWL Concrete Examination, 2016 - 2017 Report Number Type of Acceptable Indication Description of Conditions Notes Zone Drawing Examination Category IWL-2016-2003 VT-3C YES IO Conditions are not the same as reported in The diagonal crack is less than Tier 17 110-B1 Remote 2012. 1 criteria. There are no other IO There are 3 vertical shrinkage cracks that are signs of degradation in the area.

tight and less than 0.005" wide and run through the entire zone. Spalled area meets Tier 2 criteria IO There is a 6" X 1" impact abrasion that is for spalled concrete size.

approx. 1/4" deep.

IO There is an 8" grout patch on the construction joint across the face of the buttress that is separating from the wall.

RI There is an 8" diameter spall at a she-bolt that is at least 0.75" deep. The grout patch has popped out and fallen to the ground.

RI There is an additional diagonal crack that extends from an embedded plate across to zone B2. It appears to be greater than 0.015" but less than 0.025" in width.

IO Bottom 4ft of this zone are inspected from tunnel below grade.

IWL-2016-2011 VT-3C YES IO No change to previously recorded horizontal Spall depth is within acceptance 17 110-C1 Remote and vertical shrinkage cracks as documented criteria. Spall diameter meets Tier on the zone map. 2 criteria.

IO Bugholes and small voids noted throughout this zone.

IO Previously reported grease stain from H13-011 still exists but is dry.

RI There is an 8" spall just above the 126ft construction joint than is estimated to be 0.375" deep.

IWL-2016-2014 VT-3C YES IO No change in previously reported conditions: Surface corrosion is on the 17 110-C4 Remote Surface voids, l/2" deep she-bolt voids, 2-1" equipment hatch platform. Not on 21



Enclosure Attachment 6 Evaluation of the Proposed Change

Table 3.5.5-8, PVNGS Unit 2 IWL Concrete Examination, 2016 - 2017 Report Number Type of Acceptable Indication Description of Conditions Notes Zone Drawing Examination Category drilled holes in this zone, Bugholes. the containment building.

RI No change in previously reported condition of structural steel bolting connections exhibiting varying degrees of surface corrosion.

Requires RPE evaluation for acceptance.

IO Rust stains on embed plates.

IWL-2016-2043 VT-3C YES IO No change in previously reported area Grease leak is minor. 5% of 17 110-G1 Remote conditions: Bugholes. Small voids. Surface tendon duct is the allowable loss.

rust on embed plates RI Grease leak from H13-039 under can flange.

Leak is not active.

IWL-2016-2054 VT-3C YES RI No change to Previously reported pop out Pop out has not changed since 14 111-A6 Remote above an embedded plate. 1 1/2" wide X previous inspection.

1/2" deep.

IO No change to previously recorded shrinkage cracks throughout the bottom half of this zone. Coating is cracked but not deteriorating further. All recorded cracking is less than 0.005" wide IO 1 additional 18" diagonal shrinkage crack extends from the right side of Penetration #

18 to an embedded plate on the left-hand side. Less than 0.010" wide.

IO 1 additional 18" vertical shrinkage crack extends between Pen # 18 and Pen #66.

This crack is 0.010" wide.

IO 1 additional vertical shrinkage crack extends 1ft from the bottom of Pen #68. This is fine and less than 0.005" wide.

IWL-2016-2057 VT-3C YES IO No change to the previously recorded Honeycombing was noted in 2001.

13 111-B1 Remote shrinkage crack that runs parallel to the No changes. Spalls on buttress 22



Enclosure Attachment 6 Evaluation of the Proposed Change

Table 3.5.5-8, PVNGS Unit 2 IWL Concrete Examination, 2016 - 2017 Report Number Type of Acceptable Indication Description of Conditions Notes Zone Drawing Examination Category center vertical construction form joint. This not containment wall. Pop out crack is 13ft long and less than 0.010" wide. meets acceptance criteria.

IO 3 additional vertical, and 1 additional horizontal shrinkage cracks noted. All are documented on the zone sketch, and less than 0.005" wide.

RI There is a 3ft long section of honey combing just above the 106ft construction joint and centered in the zone. There is exposed aggregate.

RI There are 2 edge spalls side by side 8" long total, and 1/2" deep at the widest point.

They are located on the left edge of the buttress at the 106ft construction joint. It appears a previous grout patch may have popped out.

RI There is a 2" diameter pop out at the far left of this zone, and just above the 106ft construction joint. It is 1/4" deep with exposed aggregate.

IWL-2016-2058 VT-3C YES IO No change to previously recorded stress Edge spalls show no further signs 14 111-B4 Remote crack across a grout patch. Crack does not of degradation. Condition is propagate to surrounding concrete. Location acceptable.

of grout patch has been redrawn on the zone boundary sketch to show proper defect orientation and location.

RI The left side of Penetration #45 has several edge spalls above tier# 1 criteria.

IWL-2016-2059 VT-3C YES IO No change to previously reported edge spalls Spall depth is less than Tier 2.

14 111-B5 Remote at Penetrations #39 and #40. Spalls have There are no other signs of been previously reviewed to be within tier #1 degradation around the spalls.

23



Enclosure Attachment 6 Evaluation of the Proposed Change

Table 3.5.5-8, PVNGS Unit 2 IWL Concrete Examination, 2016 - 2017 Report Number Type of Acceptable Indication Description of Conditions Notes Zone Drawing Examination Category criteria. Condition is acceptable.

RI Additional edge spalls noted down the left and right sides of Penetration #44 not previously noted.

IWL-2016-2060 VT-3C YES IO No change to previously recorded condition of Exposed rebar is covered with 14 111-B6 Remote small edge spalls around all penetrations in clear coating and shows no signs this zone. of degradation.

RI Additionally, the left side of Penetration #34 has a 6" section of exposed rebar. The area is bulged.

IWL-2016-2061 VT-3C YES IO No change to previously recorded small edge Rebar is covered with clear coating 14 111-B7 Remote spalls around Penetrations. and does not show any signs of RI Penetration #31 has four sections of exposed corrosion. This is the result of rebar inside the penetration and spaced poor construction. Condition evenly on the left-hand side. The lower left acceptable. Similar condition was exposed section is 10" long and has been evaluated in 2002.

ground flush to the surface.

RI Penetration #33 has a 4" section of exposed rebar inside the lower right-hand corner. The surface is bulged.

IWL-2016-2063 VT-3C YES RI No change to previously reported grease leak Spalls are on buttress face, not 13 111-C1 Remote at H21-014. However, grease stain on the containment wall. The horizontal buttress edge appears dry and not active at crack appears to be in an area time. which is scaling. Area will be RI There are 5 vertically aligned spalls on the accessible for closer exam during left face of buttress #1 at approximately next tendon test. Condition meets 132ft elev. Each is 2" to 3" in diameter and Tier 2 acceptance criteria.

approximately 1/2" deep.

RI A horizontal crack runs through an area with rough surface finish and a thin grout patch.

Portions of the grout patch have spalled off.

24



Enclosure Attachment 6 Evaluation of the Proposed Change

Table 3.5.5-8, PVNGS Unit 2 IWL Concrete Examination, 2016 - 2017 Report Number Type of Acceptable Indication Description of Conditions Notes Zone Drawing Examination Category Some aggregate is exposed. The area of concern is approximately 16" long and 4" wide. The visible portion of the crack is less than 0.025" wide by comparison to the gray placard, but greater than 0.015".

IO No change to previously recorded as passive horizontal and vertical shrinkage cracks. All are less than 0.005" wide.

IWL-2016-2064 VT-3C YES RI No change to previously recorded 8" X 2" X No change in condition at Pen 89.

14 111-C4 Remote 3/4" deep, edge spall at Penetration #89. Edge spalls at Pen 91 is coated Has not and shows no sign of degradation.

been repaired.

RI Additional 3" X 3/4" deep, edge spall at the top of Penetration #91.

IO Additional 4ft vertical, fine shrinkage crack between Pen #90 and #91. Less than 0.005" wide.

IWL-2016-2070 VT-3C YES RI Based on the sketched data from 2012; the Crack is within acceptance criteria.

14 111-D4 Remote previously recorded horizontal shrinkage crack has changed area conditions. The crack has extended across the top half of this zone, and into the adjacent zone D-5. There are 2 additional vertical shrinkage cracks that intersect as well. The widest section of all these cracks measures 0.015" wide. Less than tier #1 criteria.

IWL-2016-2071 VT-3C YES RI Based on the zone sketch provided in 2012, Cracks are all less than acceptance 14 111-D5 Remote the previously reported horizontal shrinkage criteria.

crack has changed the area general condition. The crack extends through the upper half of this zone and into zone D-6.

25



Enclosure Attachment 6 Evaluation of the Proposed Change

Table 3.5.5-8, PVNGS Unit 2 IWL Concrete Examination, 2016 - 2017 Report Number Type of Acceptable Indication Description of Conditions Notes Zone Drawing Examination Category Two additional fingers or branches exist. All cracking is less than 0.005" wide.

IO Several white stains exist and run the walls.

These are suspected to be from water intrusion from the deck above.

IWL-2016-2073 VT-3C YES IO Previously noted stress crack in the grout Edge spalls show no other 14 111-D5 Remote patch was recorded as less than 0.010" wide. indication of degradation and are The crack is actually 0.020" wide but does within Tier 2 acceptance criteria.

not extend to surrounding concrete.

IO In addition to the previously recorded horizontal shrinkage cracks in the upper half of the zone, there are several more mapped on the attached zone sketch. All are less than 0.010" wide.

RI Previously recorded 3" X 1" X 1/2" deep edge spall at Penetration #57 still exists.

Indication was previously accepted by the program owner as less than tier# 1.

RI There is 1 additional 2" edge spall at the top of Pen #57 that is 1/2" deep.

IWL-2016-2076 VT-3C YES RI No change to previously reported 2" void, WO 2417439 was generated in 13 111-E2 Remote that is 3/4" 2001 to install a non-structural IO No change to degrade grout patch with pop repair. The WO was cancelled due outs at the construction joints. to it being a priority and not IO No change to rust stains that run down the economically feasible. Void has wall due to ADV steam release. not changed since 2001.

RI There is poor surface finish around she-bolt locations. Some grout patches have popped Degraded grout patches are less out. 1 she-bolt location has a 2" diameter than 1/4" deep. Condition is pop out that is less than 1/4" deep, but there acceptable.

is exposed aggregate.

26



Enclosure Attachment 6 Evaluation of the Proposed Change

Table 3.5.5-8, PVNGS Unit 2 IWL Concrete Examination, 2016 - 2017 Report Number Type of Acceptable Indication Description of Conditions Notes Zone Drawing Examination Category IWL-2016-2077 VT-3C YES RI Previously reported area of large surface Voids have not changed since 13 111-E3 Remote voids still exists. Has not been repaired. The 2001. WO was generated to repair area is approximate 10" X 4", with voids from non-structural condition but was 1/2" to 1 1/2" in diameter. The largest void canceled due to it being non-is 3/4" with a singular exposed aggregate economically feasible.

inside. The voided area is adjacent to a 2ft long degraded grout patch.

IO No change to the previously noted degraded grout patch of the construction joint s.

There're cracking pop outs, and some grout is separating from the wall.

IO No change to rust staining in this zone due to ADV steam release.

IWL-2016-2079 VT-3C YES IO No Change to previously recorded data from No change in conditions.

14 111-E5 Remote 2012 and earlier.

IO Bug holes throughout the zone, small surface voids, and several very fine shrinkage cracks noted.

IO Additional Shrinkage cracks noted. Most severe documented on zone sketch. All less than 0.005" wide.

IO Degraded grout work at the 176" construction joint. Grout has popped out in several sections and is separating from the wall.

RI No change to the 2" diameter pop out at she-bolt location. Previously recorded in 2012 and earlier. There is exposed aggregate and approximately 3/4" deep. Program owner has described the condition as non-structural, and less than tier 1 criteria.

27



Enclosure Attachment 6 Evaluation of the Proposed Change

Table 3.5.5-8, PVNGS Unit 2 IWL Concrete Examination, 2016 - 2017 Report Number Type of Acceptable Indication Description of Conditions Notes Zone Drawing Examination Category IWL-2016-2080 VT-3C YES IO Bug holes noted throughout this zone. 3" diameter void appears to be 14 111-E6 Remote IO Poor surface finish especially around she- honey combing with no signs of bolts. degradation.

IO 176ft construction joint grout work is degraded. A 6ft section has popped out in this zone.

IO Several vertical and horizontal shrinkage cracks noted. All less than 0.005" wide. The most severe are documented on the boundary sketch for this zone.

IO One 6" abrasion noted, less than 1/4" deep.

Located in the upper center of this zone IO One 4" abrasion noted, less than 1/4" deep.

Located in the bottom right quadrant of this zone.

RI 3" diameter void noted in the top right quadrant of this zone. It is between she-bolt locations. It is approximately 1/2". There is exposed aggregate. The surrounding area has poor surface finish.

IWL-2016-2085 VT-3C YES IO Rough surface finish throughout this zone. Abrasion area is less than 13 111-F3 Remote IO Degraded grout patches of construction acceptable depth for scaling.

joints.

IO 2 vertical shrinkage cracks extend through the zone. Less than 0.005" wide RI There is a 3ft area of abrasion and erosion, center bottom in the zone, parallel to the vertical construction joint. There is small voids present. The surface appears to be flaking and peeling. The area is rust stained, probably due to ADV steam release. There is 28



Enclosure Attachment 6 Evaluation of the Proposed Change

Table 3.5.5-8, PVNGS Unit 2 IWL Concrete Examination, 2016 - 2017 Report Number Type of Acceptable Indication Description of Conditions Notes Zone Drawing Examination Category no exposed aggregate at this time, but there is a loss of surface material. Approximately 1/4" deep.

IWL-2016-2087 VT-3C YES IO No change to previously reported general Rough surface finish is acceptable.

14 111-F5 Remote area conditions from 2012; bug holes throughout the zone with small voids. Poor surface finish at she-bolt locations. Degraded grout patches at the construction joints.

IO 2 additional shrinkage cracks noted. Each is very fine, less than 0.005" wide.

Documented on the zone sketch.

IO 176ft construction joint grout work has further degraded since the last inspection. At least a 20ft section of grout has popped out and extends into zone F4.

RI There is a 2" diameter pop out at a she-bolt location. The surrounding surface finish is rough. Exposed aggregate and light rust stains are protruding from center.

IWL-2016-2088 VT-3C YES IO No change to previously reported general Abrasion is less than 1/4" deep.

14 111-F6 Remote area conditions noted as: Bug holes, small This meets acceptance criteria for voids, poor surface finish around she-bolts, allowable scaling.

and construction joint grout patches are degraded, with some areas popping out.

IO Two additional 10ft vertical shrinkage cracks noted in the bottom half of this zone. Less than 0.005" wide.

RI 10" abrasion noted, less than 1/4" deep with no exposed aggregate. Probably due to construction form removal.

IWL-2016-2089 VT-3C YES IO No change to previously reported general Abrasion meets Tier 1 acceptance 29



Enclosure Attachment 6 Evaluation of the Proposed Change

Table 3.5.5-8, PVNGS Unit 2 IWL Concrete Examination, 2016 - 2017 Report Number Type of Acceptable Indication Description of Conditions Notes Zone Drawing Examination Category 14 111-F7 Remote area conditions noted as; bug holes, small criteria.

voids, poor surface finish around she-boIts, and construction joint grout patches are degraded, with some areas popping out.

RI 1 ft abrasion noted in the bottom right quadrant of this zone. No exposed aggregate.

Less than 1/4" deep. Suspected to be from construction form removal.

IO Multiple Horizontal and vertical shrinkage cracks noted and documented on the attached zone boundary sketch. All are fine and less than 0.005" wide.

IWL-2016-2090 VT-3C YES IO Previously reported condition of very fine Grease leaks are minor. Grease 14 111-F8 Remote shrinkage cracks, less than 0.005" wide, but caps will be inspected and bolts no sketch of their location on the zone tightened during the next Unit 2 boundary sketch. tendon test.

IO Previously reported rust on Alimak rails, but program owner states that Alimak lift is no longer in use.

RI There is evidence of inactive grease leaks from behind the flange of 5 grease caps.

H21-033, H21-034, H21-035, H21-036, H21-037.

IO Light rust stains in this zone run down the wall from above. They appear to originate from the 210ft construction joint.

IO 1 additional vertical shrinkage crack extends greater than 20ft through this zone and into the zone above. Less than 0.005" wide IO 1 additional horizontal shrinkage crack approximately 12ft long in the bottom half of 30



Enclosure Attachment 6 Evaluation of the Proposed Change

Table 3.5.5-8, PVNGS Unit 2 IWL Concrete Examination, 2016 - 2017 Report Number Type of Acceptable Indication Description of Conditions Notes Zone Drawing Examination Category the zone. Less than 0.005" wide.

IWL-2016-2091 VT-3C YES RI There is a 2.5ft section of "Honeycombing" at Stains are not corrosion. Rather 13 111-G1 Remote the 213ft construction joint. Exposed they appear to be wet spots. No aggregate is present. signs of degradation are present.

RI There are halo like light and dark stain patterns that seem to form around areas where chalk line grids are present.

IO Bug holes are present throughout the zone and poor surface finish noted around she-bolts.

IWL-2016-2093 VT-3C YES RI There is a 10ft long and 3ft wide area just Poor surface finish and surface 13 111-G3 Remote below the 206ft Construction joint that has voids were reported in 2001. No very poor surface finish, and random 1" signs of degradation present.

diameter X 1/2" deep voids.

IO Not able to locate previously recorded passive shrinkage crack between she-bolts, in the lower half of the zone.

IO Light surface rust stains, probably due to ADV steam release.

IO The grout patches on the 196ft construction joint are degraded. Some areas are popped out, cracked, or separating from the wall.

IWL-2016-2098 VT-3C YES IO Previous data from 2012 records an inactive Grease leaks are minor. Grease 14 111-G8 Remote grease leak from H21-027. This tendon caps will be inspected, and bolts grease cap is not in this zone. tightened during the next tendon IO 2ft X 2ft area of very fine crazed cracking test.

above the 210ft elevation. All less than 0.005 "wide.

IO Light rust stains in this zone run down the wall.

RI There is evidence of inactive grease leaks 31



Enclosure Attachment 6 Evaluation of the Proposed Change

Table 3.5.5-8, PVNGS Unit 2 IWL Concrete Examination, 2016 - 2017 Report Number Type of Acceptable Indication Description of Conditions Notes Zone Drawing Examination Category from behind the flange of 5 grease caps.

H21-033, H21-034, H21-035, H21-036, H21-037 (Same condition reported for zone 14 111-F8)

IO Two areas below the 206ft and the 210ft construction joints are noted as having poor surface finish and abrasion. Probably due to form removal. The areas are approximately 2ft square.

IO 1 vertical shrinkage crack noted above the 210ft elevation and is less 0.005" wide.

IWL-2016-2108 VT-3C YES IO Penetrations 9, 10, 11, 12, 13, 14, 16, no Conditions surrounding insulation 15 112-B4 Remote indications noted in area. do not indicate area under RI Pen 15 containment wall masked by insulation is degraded. No follow insulation covering entire penetration area. up actions required.

Requires review by RPE.

IWL-2016-2111 VT-3C YES IO Data recorded in 2012 includes: Bug holes WO to repair corner spall was 16 112-B8 Remote and small voids throughout the zone. Poor cancelled due to not being surface, minor abrasions, 1 very fine vertical economically feasible. Previous shrinkage crack, and 1 edge spall. None of reports were missing a dimension the findings were recorded on a zone map. on the report so the spall may not IO Additionally, there are 2 more 20ft shrinkage have changed size. Spall is on cracks that are less than 0.005" wide and buttress, not on containment wall.

extend through the zone.

RI Previously recorded edge spall still exists, but the size is greater than previously recorded.

It is 6" X 4" and 3/4" deep.

IO The bottom 4ft of this zone was not accessible for exam at this time. Crane and scaffold support is required to be worked from below grade tunnel.

32



Enclosure Attachment 6 Evaluation of the Proposed Change

Table 3.5.5-8, PVNGS Unit 2 IWL Concrete Examination, 2016 - 2017 Report Number Type of Acceptable Indication Description of Conditions Notes Zone Drawing Examination Category IO It should be noted that grout debris is on the ground falling from higher elevations.

IWL-2016-2117 VT-3C YES IO No change to general surface conditions in WO 2417436 to repair exposed 16 112-C6 Remote this zone recorded in 2012: Poor surface she-bolt was cancelled. No rust finish, bug holes and minor abrasions. was noted.

RI Previously recorded spall still exists with exposed she-bolt. The she-bolt has started to rust and corrode. The hole is 5" wide and 2" deep. It was not previously recorded on a zone map.

IWL-2016-2118 VT-3C YES IO General surface conditions in this zone Rough surface is less than Tier 1 16 112-C7 Remote recorded in 2012: Poor surface finish, criteria.

bugholes, abrasions due to impacts. Not recorded on zone map.

RI One area of surface erosion noted. Area is 1 ft wide and 18" Tall. It has a pitted appearance and pattern cracking is present.

IWL-2016-2122 VT-3C YES IO Previously reported area conditions have not Change in void size appears to be 15 112-D3 Remote changed. Bugholes. inspector measuring technique as IO Three horizontal shrinkage cracks (Not the large void is only approx. 1" previously reported) wide. No signs of degradation.

IO 1 crack is 7' long x < .015" wide.

IO 2 cracks 1-1 /2' long x < .015" wide. Cracks are on each side of Penetration 56.

RI Small Void/Pop Out with exposed aggregate 3" wide x 1 3/4" long x 1/4" deep. Note:

Previously recorded as a small void area 1" wide x 2" long x 1/4" deep. This condition requires review by RPE.

IWL-2016-2131 VT-3C YES IO Previously reported area conditions have not A ladder was used by Program 15 112-E4 Remote changed. Owner to examine 3' 8" crack.

33



Enclosure Attachment 6 Evaluation of the Proposed Change

Table 3.5.5-8, PVNGS Unit 2 IWL Concrete Examination, 2016 - 2017 Report Number Type of Acceptable Indication Description of Conditions Notes Zone Drawing Examination Category IO Bugholes. The crack has surface widening IO Small surface voids, Popouts, and areas of which makes it appear wider when grout degradation. viewed from bellow. Crack is a IO Poor surface finish around all she bolts small hairline crack below impressions widening.

IO Abrasions and rough surface finish.

IO The lower zone has developed substantial vertical, horizontal, pattern cracking. These cracks are very fine and are < .015" wide.

(Not previously reported.)

RI The upper zone has crack which is orientated horizontal and diagonal 3' - 8" and is greater than .130" wide. The cracks also propagate into zone E3.

IWL-2016-2133 VT-3C YES IO Previously reported area conditions have not Pop outs meet Tier 1 criteria. Poor 16 112-E6 Remote changed: Bug holes, small voids, pop outs, surface finish around she-bolt does poor surface finish around she-bolt not show any signs of continued impressions and areas of degraded grout. degradation.

IO Rust colored dispersed stains in this zone.

IO Vertical shrinkage crack 20' long and less than 0.015" wide.

RI Previously reported pop out conditions require review.

IWL-2016-2136 VT-3C YES IO Previously reported condition: Bug holes. 18" section of spalling appears to 15 112-F1 Remote New Condition: be poor surface finish on the IO Upper half of the zone has 2 vertical buttress wall interface. Poor shrinkage cracks 7' long and less than 0.015" surface finish in this area is not wide. unusual. There are no signs of IO Lower half of the zone has 2 vertical degradation, other than poor shrinkage cracks 10' long and less than surface finish, in this area.

0.015" wide.

34



Enclosure Attachment 6 Evaluation of the Proposed Change

Table 3.5.5-8, PVNGS Unit 2 IWL Concrete Examination, 2016 - 2017 Report Number Type of Acceptable Indication Description of Conditions Notes Zone Drawing Examination Category IO Lower half of the zone has 1 horizontal shrinkage crack 15' long and less than 0.015" wide.

RI Approximately 18" of the inner corner of the buttress has spalled out or is degraded.

There is evidence of surface material loss.

Depth could not be determined.

IWL-2016-2137 VT-3C YES IO No change in previously reported area All cracks are still less than 0.015" 15 112-F2 Remote conditions: Bugholes and small voids in the in width.

entire zone. Poor surface finish at she bolt locations.

IO Continuation of vertical shrinkage crack from zone E2. 9' long and less than 0.015" wide.

RI Horizontal shrinkage cracks in lower section previously recorded have propagated. These cracks now extend through the entire zone.

IWL-2016-2155 VT-3C YES IO No change in previously reported general CMWO has been generated to 20, Sheet 1 of 3 Remote area conditions: Bugholes, Voids, Poor repair the patch.

surface finish, Fine vertical shrinkage cracks.

Cracks run from the springline up towards the dome crest. Cracks are 15' to 40' long but <0.010" wide.

RI The round grout patch continues to slowly degrade. Portions of the patch have spalled off and the metal plate below the patch is corroding. There is no change to the shrinkage cracks extending outward from the round patch.

IWL-2016-2157 VT-3C YES IO No change in previously reported general CMWO was generated to repair the 20, Sheet 3 of 3 Remote area conditions: Bugholes, Voids, Poor degraded grout patch.

surface finish, Fine vertical shrinkage cracks.

35



Enclosure Attachment 6 Evaluation of the Proposed Change

Table 3.5.5-8, PVNGS Unit 2 IWL Concrete Examination, 2016 - 2017 Report Number Type of Acceptable Indication Description of Conditions Notes Zone Drawing Examination Category Cracks run from the springline up towards the dome crest. Cracks are 15' to 40' long but <0.010" wide.

IO No change to 6' long, 0.020" wide crack on the corner of buttress 3.

IO No change to spider cracks on the face of buttress 3.

RI The round grout patch continues to degrade.

The outer 3inches appear to be spalling.

There are rust stains extending down below the patch.

IWL-2016-2158 VT-3C YES IO No change in previously reported general CMWO was generated to repair the 21, Sheet 1 of 3 Remote area conditions: Bugholes, voids, poor degraded grout patch.

surface finish, fine vertical shrinkage cracks.

Cracks run from the springline up towards the dome crest. Cracks are 15' to 40' long but <0.010" wide.

RI The round grout patch has degraded further.

There is still a crack ~3" in from the edge of the crack; however, there is an additional crack in the bottom portion of the patch which appears to be starting to spall. There is a small rust stain below the patch as well IO No change to the inactive grease leak stain.

IO No change to the shrinkage cracks running between the tendon vent grout patch IO No change to the spall at the corner of buttress 3. Spall is 12" long x 6" wide x 1/2" deep IO No change to light rust stains around Alimak embeds.

36



Enclosure Attachment 6 Evaluation of the Proposed Change

Table 3.5.5-8, PVNGS Unit 2 IWL Concrete Examination, 2016 - 2017 Report Number Type of Acceptable Indication Description of Conditions Notes Zone Drawing Examination Category IWL-2016-2160 VT-3C YES IO No change in previously reported general CMWO was generated to repair the 21, Sheet 3 of 3 Remote area conditions: Bugholes, voids, poor degraded grout patch.

surface finish, fine vertical shrinkage cracks run from springline up to dome crest, ~40 '

long, <0.010" wide IO No change to shrinkage cracks running between the tendon vent grout patches.

RI The round grout patch continues to degrade.

There is a crack 3" in from the edge of the patch. The bottom portion of the patch is spalling, and a rust stain extends below the patch 37



Enclosure Attachment 6 Evaluation of the Proposed Change

Table 3.5.5-9, PVNGS Unit 3 IWL Concrete Examination, 2016 - 2017 Report Number Type of Acceptable Indication Description of Conditions Notes Zone Drawing Examination Category IWL-2016-3003 VT-3C YES IO No change in previously reported area Crack is within tier 2 acceptance 17 110-B1 Remote conditions: bugholes and small voids, poor criteria. Portions of the crack surface finish at she bolt locations. Light appear wider due to surface surface abrasions, and very fine shrinkage widening.

cracks.

RI Horizontal crack 3" on each side of she-bolt grout patch (6' total length) x .035" wide.

(Not previously reported). This indication requires RPE review.

IWL-2016-3007 VT-3C YES IO Previously reported conditions are unchanged Grease leak is minor. CR was 18 110-B5 Remote listed below: bugholes and surface voids, written by Operations in April poor surface finish at she-bolt locations, and 2017. Grease leaks have been dried tape over she bolts. evaluated and determined not to RI Grease leak between 110 B5 and 110 B6. be adverse for containment walls.

Length is approx. 9' x 8" at widest area. RPE Review Required.

IWL-2016-3008 VT-3C YES IO Previously reported conditions are unchanged CR was written by Operations in 18 110-B6 Remote listed below. Exam area limited in this zone April 2017. Grease leaks have due to personnel hatch enclosure. No change been evaluated and determined in bugholes, and small voids. not to be adverse for containment RI Grease leaks cascades down vertical walls.

construction joint at Zone 6 to Zone 5.

Length of leak is approx. 9' long x 8" at widest area. RPE Review required.

IWL-2016-3009 VT-3C YES IO No change in previously reported conditions: Area reported as spalling appears 18 110-B7 Remote bug holes, voids, shrinkage cracks, poor to be poor surface finish.

surface conditions in this zone, and spalling Condition is acceptable.

all around penetration 58.

IO Bead like grout repair 31" Length x 1" Width.

RI Spalling 1' length x 6" width x 1/2" depth.

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Enclosure Attachment 6 Evaluation of the Proposed Change

Table 3.5.5-9, PVNGS Unit 3 IWL Concrete Examination, 2016 - 2017 Report Number Type of Acceptable Indication Description of Conditions Notes Zone Drawing Examination Category IO Spalling at horizontal seam 106' elevation for 6'-1/2" length.

IWL-2016-3010 VT-3C YES IO No change in previously reported conditions: Grease leakage is minor. Vent cap 18 110-B8 Remote bug holes, voids, stress cracks, and poor can be tightened during the next surface conditions in this zone. tendon test.

IO Corner edge spall previously reported is repaired.

IO Repair grout patch exhibits shrinkage cracks around perimeter of patch.

IO Horizontal grout patch 4.000" length x .250" width x .250 depth section is missing. Note:

this missing patch transits through B8 and B7.

RI Grease Cap leakage from H13-011.

IWL-2016-3016 VT-3C YES IO Previously reported conditions are unchanged CR evaluated the grease leak 18 110-C6 Remote listed below. Exam area limited in this zone which was originally identified in due to personnel hatch enclosure. No change 2001. Grease leak is minor and in bugholes, and small voids. does not have an adverse effect RI Grease leaks cascades down vertical on the concrete.

construction joint into Zone 6 to Zone 5.

Length of leak is approx. 9' long x 8" at widest area. RPE Review required.

IWL-2016-3022 VT-3C YES IO This zone is partially in accessible due to Grease leak was evaluated in CR.

17 110-D4 Remote equipment hatch missile shield. Growth is minimal and may be due RI Previously reported through wall grease leak to change in inspectors since has grown in area. Leak is now 1.5' X 6" 2001.

wide.

IO The diagonal crack that transits through grease leak is 4' 7" and less than 0.015" wide. The diagonal crack has not 39



Enclosure Attachment 6 Evaluation of the Proposed Change

Table 3.5.5-9, PVNGS Unit 3 IWL Concrete Examination, 2016 - 2017 Report Number Type of Acceptable Indication Description of Conditions Notes Zone Drawing Examination Category propagated.

IO Additional shrinkage crack not previously recorded. 2' 6" and less than 0.015" wide.

IWL-2016-3034 VT-3C YES IO No change in previously reported area Grease leak is minor. Bolts will be 18 110-E8 Remote conditions such as bug holes, and poor tightened during next tendon test.

surface finish conditions at she bolt locations.

RI Evidence of grease leak from Tendon Cap Retention Plate H13-026 at Elevation 165'.

IWL-2016-3057 VT-3C YES IO No change in previously reported area Area around H21-007 were 13 111-B1 Remote conditions such as bugholes, poor surface inspected by Program Owner.

finish conditions at she bolt locations, surface Cracks are 0.015" wide below rust conditions reported remain, are surface widening. This meet Tier characterized as very light in color with no 1 criteria.

evidence of structural degradation at this inspection interval.

IO White stain at 112' elevation joint flows down 31" to stainless cover plate on Alimak work platform.

RI Zone 111 Buttress # 1 east side exhibits stress cracking at Tendon Cap H21.007 Bearing Plate edges and corners. The lower right corner (looking plant west) crack dimension is 2 l/2" length x .025" to .035" width. The are other numerous cracks at this tendon cap locations IO Areas of Pattern cracking with widths less than .015", and Stress cracks varying from 24" to 60" in length but less than .015".

IWL-2016-3120 VT-3C YES IO No change in previously reported area Grease leak is minor. Bolts can be 15 112-D1 Remote conditions such as bugholes, poor surface tightened during the next tendon finish conditions at she bolt locations, surface test.

40



Enclosure Attachment 6 Evaluation of the Proposed Change

Table 3.5.5-9, PVNGS Unit 3 IWL Concrete Examination, 2016 - 2017 Report Number Type of Acceptable Indication Description of Conditions Notes Zone Drawing Examination Category rust conditions.

RI Evidence of grease leak from behind flange at H32-027.

41