IR 05000368/2018010

Post-Approval Site Inspection for Licensee Renewal Inspection Report 05000368/2018010

ML18221A507
Person / Time
Site:	Arkansas Nuclear
Issue date:	08/09/2018
From:	Greg Werner NRC/RGN-IV/DRS/EB-2
To:	Richard Anderson Entergy Operations
References
IR 2018010
Download: ML18221A507 (46)

Text

ust 9, 2018

SUBJECT:

ARKANSAS NUCLEAR ONE, UNIT 2 - POST-APPROVAL SITE INSPECTION FOR LICENSE RENEWAL INSPECTION REPORT 05000368/2018010

Dear Mr. Anderson:

On July 27, 2018, a U.S. Nuclear Regulatory Commission (NRC) inspection team completed a post-approval site inspection for license renewal at Arkansas Nuclear One, Unit 2. The enclosed report documents the inspection results, which were discussed on July 27, 2018, with Mr. B. Daiber, Design Engineering Manager, and other members of your staff.

The inspection examined activities conducted under your license as they relate to safety and compliance with the Commissions rules and regulations, and with the conditions of your license. The team reviewed selected procedures and records, observed activities, and interviewed personnel.

The NRC inspectors did not identify any finding or violation of more than minor significance.

This letter, its enclosure, and your response (if any) will be made available for public inspection and copying at http://www.nrc.gov/reading-rm/adams.html and at the NRC Public Document Room in accordance with 10 CFR 2.390, Public Inspections, Exemptions, Requests for Withholding.

Sincerely,

/RA/

Gregory E. Werner, Chief Engineering Branch 2 Division of Reactor Safety Docket: 50-368 License: NPF-6 Enclosure:

Inspection Report 05000368/2018010

U.S. NUCLEAR REGULATORY COMMISSION

Inspection Report

Docket Number: 05000368 License Number: NPF-6 Report Number: 05000368/2018010 Enterprise Identifier: I-2018-010-0039 Licensee: Entergy Operations, Inc.

Facility: Arkansas Nuclear One, Unit 2 Location: Russellville, Arkansas Inspection Dates: May 21, 2018, to July 27, 2018 Inspectors: G. Pick, Senior Reactor Inspector S. Alferink, Reactor Inspector I. Anchondo, Reactor Inspector S. Makor, Reactor Inspector Approved By: Gregory E. Werner, Chief Engineering Branch 2 Division of Reactor Safety Enclosure

SUMMARY

IR 05000368/2018010; 05/21/2018 - 07/27/2018; Arkansas Nuclear One, Unit 2, Post-Approval

Site Inspection for License Renewal The significance of inspection findings is indicated by their color (i.e., Green, greater than Green, White, Yellow, or Red), determined using Inspection Manual Chapter 0609, Significance Determination Process, dated April 29, 2015. Their cross-cutting aspects are determined using Inspection Manual Chapter 0310, Aspects within the Cross-Cutting Areas, dated December 4, 2014. Violations of NRC requirements are dispositioned in accordance with the NRC Enforcement Policy. The NRCs program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process, dated July 2016.

NRC-Identified Findings and Self-Revealing Findings

None

Licensee-Identified Violations

None

REPORT DETAILS

4OA5 Other - Post-Approval Site Inspection for License Renewal (Phase 2) - IP 71003

Phase 2 Inspection Activities Inspection Procedure 71003, Post-Approval Site Inspection for License Renewal, recommended that the inspection be conducted shortly before the period of extended operation. The period of extended operation is the additional 20 years beyond the original 40-year licensed term. The period of extended operation for Arkansas Nuclear One, Unit 2 began after midnight on July 17, 2018.

The team evaluated whether the licensee:

(1) completed actions required to comply with the license renewal license condition and commitments;

(2) implemented the aging management programs that agreed with those approved in the safety evaluation report and described in the safety analysis report;

(3) followed the guidance in Nuclear Energy Institute (NEI) 99-04, Guidelines for Managing NRC Commitment Changes, for changing license renewal commitments and followed the guidance in 10 CFR 50.59 when making changes to the license renewal supplement;

(4) identified, evaluated, and incorporated newly identified structures, systems, and components into their aging management programs; and

(5) implemented operating experience review and corrective action programs that account for aging effects.

NUREG-1828, Safety Evaluation Report (SER) Related to the License Renewal of Arkansas Nuclear One, Unit 2, Appendix A listed 40 commitments. The team reviewed 37 of the 40 commitments and closed 37 commitments. The NRC had previously closed two commitments and evaluated implementation of four aging management programs during the Phase 1 inspection documented in NRC Inspection Report 05000368/2017009 [ML17153A123]. The team did not close Commitment 17940. The team reviewed 32 aging management programs.

The team closed 37 commitments and 1 commitment remains open.

Review of Aging Management Programs

a. Inspection Scope

The team evaluated whether the licensee implemented the aging management programs and commitments described in NUREG-1828. For each aging management program reviewed, the team reviewed program documents, license renewal documents, the safety analysis report, and the safety evaluation report. Supporting documents reviewed included implementing procedures, work orders, inspection reports, engineering evaluations, calculations, database entries, and condition reports. The team interviewed program owners and license renewal program personnel.

The team determined that the licensee had translated their license renewal application into Chapter 18 of their safety analysis report. The team listed specific documents reviewed in the attachment.

.1 B.1.1 Alloy 600 Program

This program managed aging effects related to primary water stress corrosion cracking on Alloy 600/690 items, and Alloy 52/152 and 82/182 welds in the reactor coolant system. The licensee implemented the examination and inspection requirements of American Society of Mechanical Engineers (ASME) Section XI, as augmented by the commitments made to the NRC.

The licensee had three commitments related to this program. Specifically, the licensee committed to:

(1) submit a description of the Alloy 600 aging management program, which includes the inspection plan, to the NRC staff for review and approval;

(2) revise the supplement to identify the specific purpose of the program; and

(3) provide the Alloy 600 inspection plan and program at least 24-months prior to entering the period of extended operation.

The team verified that the licensee had submitted their Alloy 600 aging management program as specified and determined that NRC had no concerns with the submittal. The team determined that the licensee had scheduled these inspections as part of their inservice inspection program.

The team identified no concerns with this program.

.2 B.1.4 Buried Piping Inspection Program

This program managed aging effects related to loss of material caused by corrosion.

The licensee developed preventive measures to mitigate corrosion and conducted periodic inspection to manage the effects of corrosion on buried carbon steel piping, valve bodies, and bolting. The licensee established preventive measures that met the standard industry practice for maintaining external coatings and wrappings. The licensee provided guidance to inspect buried pipe coatings and wrappings when they were excavated during maintenance. The licensee included the fire water system, service water system, and fuel oil system piping.

The licensee identified one commitment related to this program, which specified implementing the program described in their safety analysis report.

The team reviewed the buried pipe program established to meet the guidance in NEI 09-14, Guideline for The Management of Buried Piping Integrity, dated January 2010. The team verified that the licensee revised the program procedures to identify the need to conduct opportunistic inspections of buried piping and components. The team determined that the program being implemented exceeded the license renewal commitments. The team confirmed that the licensee had performed scheduled inspections based on risk ranking. The team determined that the licensee maintained their cathodic protection system using scheduled preventive maintenance tasks to monitor the rectifiers. From 2014-2017 the licensee replaced anodes identified during testing that produced marginal current levels.

The team identified no concerns with this program.

.3 B.1.5 Cast Austenitic Stainless Steel Evaluation Program

This program managed the aging effects related to loss of fracture toughness in reactor coolant system cast austenitic stainless steel components susceptible to thermal aging embrittlement using additional inspections and a component-specific flaw tolerance evaluation. The team determined that the licensee used their flaw tolerance evaluations to demonstrate that no inspections would be needed.

The licensee identified one commitment related to this program, which specified implementing the program described in their supplement and listed in Appendix A of the safety evaluation report. The team challenged the licensees methodology used to perform the programs flaw tolerance evaluation given the fact that they had decided that no inspections of cast austenitic stainless steel components would be necessary. The methodology was probabilistic in nature demonstrating that no inspections would be needed.

Upon further discussions, the team determined that the licensee had met the requirements specified in the underlying analysis requirements as described in the acceptance criteria section of Generic Aging Lessons Learned Report Section XI.M12, Thermal Aging Embrittlement of Cast Austenitic Stainless Steel (CASS), Revision 0.

The licensee had performed both deterministic and probabilistic fracture mechanics calculations for cast components that contained up to 25 percent delta ferrite. The methodology outlined in Section XI.M12 is deterministic in nature for components containing up to 25 percent delta ferrite while those with greater percentage required a case-by-case analysis. The team determined that the licensee met the commitment for components that exceeded 25 percent delta ferrite by completing a flaw tolerance evaluation using only the probabilistic fracture mechanics methodology that had been approved by the ASME for use in August 2015.

Specifically, the team determined that the licensee used the guidance in Materials Reliability Project MRP-362, Technical Basis for ASME Section XI Code Case N-838 -

Flaw Tolerance Evaluation of Cast Austenitic Stainless Steel (CASS) Piping Components, Revision 1, to determine whether the material had sufficient toughness to withstand fractures from critical flaw sizes. Calculation CALC-ANO2 -EP-17-00100-02, CASS Aging Management Program Final Report at ANO-2, Revision 0, documented that reactor coolant system components with ferrite that exceeded 25 percent ferrite would not fail and did not require inspecting. The team requested assistance from agency technical experts who confirmed that the probabilistic fracture mechanics methodology demonstrated that a tolerable flaw, if it existed, would not propagate and cause component failure through the end of the period of extended operation.

The team identified no concerns with this program.

.4 B.1.6 Containment Leak Rate Testing

This program managed aging effects related to loss of material and cracking for equipment constituting the containment pressure boundary. The licensee implemented their existing 10 CFR Part 50, Appendix J program. The licensee performed their containment integrated leak rate test every 15 years and had adopted the performance-based option for leak rate testing. This program assured that

(1) leakage through the primary reactor containment and systems and components penetrating primary containment do not exceed allowable values, and

(2) periodic surveillance of reactor containment penetrations and isolation valves is performed so that proper maintenance and repairs are made during the service life of the containment.

The team identified no concerns with this program.

.5 B.1.7 Diesel Fuel Monitoring Program

This program managed aging effects related to loss of material and cracking on the internal surfaces of fuel oil system components. The licensee performed maintenance tasks to monitor fuel oil quality and the levels of water and microbiological organisms to prevent plugging of filters, fouling of injectors, and corrosion of fuel systems. The program included the bulk fuel oil tank, emergency diesel tanks, emergency diesel day tanks, diesel fire pump day tank, and the alternate ac diesel day tank.

The team identified no concerns with this program.

.6 B.1.9 Fatigue Monitoring Program

This program managed aging effects related to fatigue cracking. The licensee tracked the number of critical thermal and pressure transients for selected reactor coolant system components in order not to exceed the design limit on fatigue usage. The program ensured the validity of analyses containing explicit cycle count assumptions.

The components managed by this program were those shown to be acceptable by analyses that explicitly addressed thermal and pressure fatigue transient limits.

The team identified no concerns with this program.

.7 B.1.10.1 Fire Protection Program

This program managed aging effects related to loss of material, cracking, and change in material properties. The licensee performed periodic visual inspection of fire barrier penetration seals, fire barrier walls, ceilings, and floors, and periodic visual inspection and functional tests of fire rated doors. The licensee periodically tested the fuel supply line to ensure that diesel-driven fire pump inspection continued to perform its design function.

The team identified no concerns with this program.

.8 B.1.10.2 Fire Water System Program

This program managed aging effects related to loss of material, cracking, and corrosion in fire protection system components exposed to water. The licensee tested water-based fire protection systems that included sprinklers, nozzles, fittings, valves, hydrants, hose stations, standpipes, water storage tanks, and aboveground and underground piping and components according to the applicable National Fire Protection Association codes and standards. The licensee monitored the diesel fire pump jacket cooling water chemistry. These systems were normally maintained at required operating pressure and monitored such that the licensee would immediately detect leakage resulting in loss of system pressure and corrective actions initiated.

The licensee made a single commitment that specified that the licensee will enhance the program to inspect a sample of sprinkler heads in accordance with National Fire Protection Association 25, Standard for the Inspection, Testing, and Maintenance of Water-Based Fire Protection Systems. The team determined that the licensee planned to implement the option of replacing the sprinkler heads at 50 years from original installation rather than establishing a sampling program as allowed by the code.

The team identified no concerns with this program.

.9 B.1.11 Flow-Accelerated Corrosion Program

This program managed aging effects related to loss of material caused by flow-accelerated corrosion. The licensee performed the following activities:

(a) an analysis to determine critical locations,

(b) limited baseline inspections to determine the extent of thinning at these locations, and

(c) follow-up inspections to confirm the predictions, or component repair or replacement as necessary.

The team determined that the licensee also monitored for erosion aging mechanisms caused by cavitation, flashing, droplet impingement, and solid particles using their flow-accelerated corrosion management program.

The team identified no concerns with this program.

.10 B.1.12 Heat Exchanger Monitoring Program

This program managed aging effects related to loss of material, fouling and cracking for the specified heat exchangers. The licensee conducted visual and nondestructive examination techniques, such as eddy-current testing to monitor for degradation. If degradation was found, the licensee would evaluate the effects of the degradation on the design function of the heat exchanger. The licensee included the following heat exchangers in this program:

(a) shutdown cooling heat exchangers 2E-35A/B,

(b) emergency diesel generator jacket water heat exchangers 2E-20A/B,

(c) emergency diesel generator lubricating oil heat exchangers 2E-63A/B,

(d) emergency diesel generator air cooling water heat exchangers 2E-64A/B, and

(e) the containment spray pump seal coolers 2E-47A/B.

The licensee identified two commitments related to this program. Specifically, the licensee committed to:

(1) establish the program as described above with an acceptance criterion of less than 60 percent wall loss for eddy-current inspections and ensuring that the ferritic stainless steel tubes of the shutdown cooling heat exchangers will be monitored using appropriate nondestructive examination techniques, and

(2) complete a fatigue evaluation showing the acceptability of the regenerative heat exchanger for the period of extended operation. The team confirmed that the licensee established requirements in their program to perform eddy-current inspections and established appropriate criteria. In addition, the team confirmed that the licensee demonstrated the acceptability of the regenerative heat exchanger to meet the fatigue life requirements.

The team identified no concerns with this program.

.11 B.1.13 Inservice Inspection - Containment Inservice Inspection Program

This program managed aging effects related to loss of material from the containment steel liner and integral attachments. The licensee implemented the applicable requirements of their ASME Section XI, Subsections IWE and IWL as modified by 10 CFR 50.55a.

The team identified no concerns with this program.

.12 B.1.14 Inservice Inspection Program

This program managed aging effects related to cracking, wear, loss of mechanical closure integrity, and loss of material from reactor coolant system piping and components. The licensee implemented the requirements of ASME Section XI, Subsections IWB, IWC, IWD, and IWF and other requirements specified in 10 CFR 50.55a with approved NRC alternatives and relief requests.

The team identified no concerns with this program.

.13 B.1.15 Non-Environmentally Qualified Inaccessible Medium-Voltage Cable

Program (17922)

This program managed aging effects related to insulation breakdown in non-environmentally qualified inaccessible (buried or in conduit) medium voltage cables exposed to significant moisture. The licensee selected tan-delta testing to provide an indication of the condition of the conductor insulation. The team verified that the licensee performed tan-delta testing every 6 years and installed sump pumps. The in-scope components include the service water pumps, startup transformer 3 voltage regulator, and the voltage regulator for a switchyard breaker related to station blackout.

The licensee identified one commitment that specified that they would implement testing of the cables. The team verified that the licensee performed tan-delta testing for the in-scope cables.

The team identified no concerns with this program.

.14 B.1.16 Non-Environmentally Qualified Insulated Cables and Connections

Program (17923)

This program managed aging effects related to discoloration, swelling, blistering, melting, cracking, splitting, and crazing. The adverse localized environments resulted from severe environments caused by heat, radiation, and moisture for non-environmentally qualified cables and connections. The licensee visually inspected a representative sample of accessible insulated cables and connections for cable and connection jacket surface anomalies.

The licensee had committed to implement this program. The team verified that the licensee had implemented this program as described in the licensing documents.

The team identified no concerns with this program.

.15 B.1.17 Oil Analysis Program

This program managed aging effects related to cracking, fouling, and loss of material.

The licensee ensured the oil environment in the mechanical systems was maintained to the required quality. Periodically, the licensee sampled lubricating oil from plant components subject to aging management review.

The team identified no concerns with this program.

.16 B.1.18 Periodic Surveillance and Preventive Maintenance Program

This program managed aging effects related to change in material properties, cracking, heat exchanger fouling, loss of material, and loss of form. The license identified specific components included in this program because the other aging management programs did not monitor for the identified effects.

The team verified that the licensee created preventive maintenance tasks or identified routine monitoring actions and surveillance testing activities to monitor aging effects for specific components in selected systems. The systems included:

• Emergency feedwater

• Station battery racks

• Emergency core cooling system

• Containment spray, chemical volume control

• Containment cooling, auxiliary building ventilation, control room ventilation

• Emergency diesel generator, alternate ac diesel generator, fuel oil

• Halon and reactor coolant pump, and

• Service water, emergency cooling pond The licensee identified two commitments related to this program. Specifically, the licensee committed to:

(1) manage aging effects related to cracking, loss of flexibility, and embrittlement of flexible hoses in the emergency diesel generator, fuel oil, alternate ac diesel generator, and nitrogen systems through visual inspection and physical manipulation of internal and external surfaces or replacement every 10 years; and

(2) enhance this program, as well as the service water integrity program, to look for selective leaching.

The team determined that the licensee had revised the second commitment through development of a specific aging management program created to monitor for selective leaching (refer to Section 32 for more details). In addition, the team determined that Letter 2CAN04180, Notification of Revised License Renewal Commitments, dated April 30, 2018, eliminated or modified several inspection requirements.

Specifically, the licensee:

• Eliminated the requirement to inspect high pressure safety injection pumps in accordance with this program since both the service water integrity program and the oil analysis programs managed the aging for both the internal and external environments for the heat exchangers associated with these pumps.

• Revised the requirement to ultrasonically test the metal expansion boots for the emergency and alternate ac diesel generators to visually inspect and to dye penetrant test as needed because the boot configuration prevented ultrasonic testing.

• Revised monitoring of dew points for the alternate ac diesel generator air system to routine maintenance to look for moisture since the replacement air compressor units did not have that ability.

The team identified no concerns with this program.

.17 B.1.19 Pressurizer Examination Program

This program managed aging effects related to cracking of the stainless steel and nickel-based alloy cladding, and attachment welds that may propagate into the underlying ferritic steel. The licensee performed volumetric examinations, required by ASME Section XI, of the circumferential shell-to-head weld and the weld metal between the surge nozzle and the vessel lower head each inspection interval.

The licensee made two commitments related to this program. Specifically, the licensee committed to:

(1) manage aging effects using the volumetric examinations described above and carry forward the existing risk-informed inservice inspection of the pressurizer surge line piping welds; and

(2) revise the safety analysis report supplement to indicate this program was an existing program. The team verified the licensee managed the aging effects with volumetric examinations and had revised the safety analysis report to indicate this program was an existing program. In addition, the team noted that the licensee replaced the pressurizer in 2006.

The team identified no concerns with this program.

.18 B.1.20 Reactor Vessel Head Penetration Program

This program managed aging effects related to cracking of nickel-based alloy reactor vessel head penetrations exposed to borated water to assure that the pressure boundary function was maintained. The licensee performed visual and volumetric inspections as required by 10 CFR 50.55a to manage the effects of aging.

Letter 2CAN041801 deleted the program since the referenced NRC order no longer applied and 10 CFR 50.55a specified inspection requirements for the reactor vessel head penetrations. The team determined that the licensee should have revised the program to meet the inspection requirements described in 10 CFR 50.55a similar to their other inservice inspection aging management programs rather than deleting the program. The licensee documented this deficiency in Condition Report 2-2018-01275.

Letter 2CAN061801, Notification of Revised License Renewal Commitment, dated June 28, 2018, reinstated the aging management program.

The team reviewed the procedure and work order instructions used to perform the reactor vessel head penetration examinations and identified a violation of minor significance. The team identified that the procedural steps to address a relevant condition indicative of possible nozzle leakage did not implement the requirements of Code Case N-729-4, Alternative Examination Requirements for PWR Vessel Upper Heads with Nozzles Having Pressure-Retaining Partial-Penetrations Welds.

Specifically, the team identified a weakness in the way the licensee dispositions boric acid indications in the annulus of the head penetrations. This lack of guidance could result in the licensee failing to identify leakage from the annulus. The licensee documented this performance deficiency in Condition Report C-2018-02215.

The team did not identified any further concerns with this program.

.19 B.1.21 Reactor Vessel Integrity Program

This program managed aging effects related to reduction in fracture toughness of reactor vessel beltline materials. The licensee assured that they maintained the pressure boundary function by evaluating the radiation damage through comparison of pre-irradiation and post-irradiation testing of Charpy V-notch and tensile specimens.

The licensee implemented ASTM E-185-82, Standard Recommended Practice for Surveillance Tests for Nuclear Reactor Vessels, to meet the requirements of 10 CFR Part 50, Appendices G and H.

The licensee identified one commitment that required revising safety analysis report, Table 5.2-12, Capsule Removal Schedule, to require withdrawing and testing one standby capsule to cover the peak fluence expected through the end of the period of extended operation. The team verified that the licensee implemented this commitment.

The licensee submitted a license amendment request per Letter 2CAN111702, dated November 20, 2017, to revise the reactor coolant system pressure-temperature limits applicable to the period of extended operation. The team determined that the licensee was responding to a request for additional information associated with this submittal.

The team identified no concerns with this program.

.20 B.1.22 Reactor Vessel Internals Cast Austenitic Stainless Steel Program

This program managed aging effects related to cracking, reduction of fracture toughness, and dimensional change using inspections of applicable components, which will be determined based on the neutron fluence and thermal embrittlement susceptibility of the component. This program supplemented the reactor vessel internals inspections required by the ASME Section XI Inservice Inspection Program.

The licensee identified three commitments related to this program. Specifically, the licensee will:

(1) develop this aging management program and submit to the NRC for review and approval;

(2) begin the inspections during the fifth inspection interval after entering the period of extended operation; and

(3) require that enhanced VT-1 examinations be performed one time during the period of extended operation. The team confirmed that the licensee submitted their reactor vessel internals aging management program plan to the NRC. This program plan implements the guidance of MRP-227-A, Reactor Internals Inspection and Evaluation Guidelines, to address aging effects of cast austenitic stainless steel components.

Letter 2CAN041801 moved the requirement to inspect the cast austenitic stainless steel control element assembly shroud tubes from this program into the existing reactor vessel internals inspection program. The team determined that the control element assembly shroud tubes would not be required to be inspected per the classification guidance of MRP-227-A. The team identified no concerns with deleting this aging management program after including the component that required aging management to a different aging management program The team identified no concerns with this program.

.21 B.1.23 Reactor Vessel Internals Stainless Steel Plates, Forgings, Welds, and Bolting

Program (17930)

This program managed aging effects related to crack initiation and growth, loss of fracture toughness, and distortion. The aging mechanisms included stress corrosion cracking or irradiation assisted stress corrosion cracking, neutron irradiation embrittlement, and void swelling. This program supplements the reactor vessel internals inspections required by the ASME Section XI Inservice Inspection Program.

The licensee identified two commitments related to this program. Specifically, the licensee:

(1) committed to implement the program described in the supplement and the safety evaluation report, and submit to the NRC for review and approval; and

(2) evaluate relevant indications in accordance with ASME Section XI.

The team reviewed the reactor vessel internals aging management program plan that the licensee submitted by Letter 2CAN071603, Reactor Vessel Internals Aging Management Program Plan Arkansas Nuclear One - Unit 2, dated July 18, 2016. The team verified that the program provided reasonable assurance for addressing the applicable aging mechanisms. The team also verified that the licensee included the applicable Section XI evaluation criteria in this program.

The team identified no concerns with this program.

.22 B.1.24 Service Water Integrity Program

This program managed aging effects related to loss of material, fouling and cracking resulting from biofouling, corrosion, erosion, protective coating failures, and silting. The licensee performed surveillance testing and chemistry control techniques to manage aging effects in the service water system and components cooled by service water. The licensee implemented this program to meet the requirements of Generic Letter 89-13, Service Water System Problems Affecting Safety-Related Systems.

This program had a single commitment specifying that licensee will enhance the program to inspect for evidence of selective leaching. The team determined that the licensee revised this commitment by Letter 2CAN041801 to develop an independent selective leaching aging management program (refer to Section 32).

The team identified no concerns with this program.

.23 B.1.25 Steam Generator Integrity Program

This program managed aging effects related to cracking and loss of material from steam generator internal components. The licensee performed nondestructive examination techniques to identify defective tubes that needed removal from service or repaired in accordance with the guidelines of the technical specifications. In addition, the licensee used nondestructive examination techniques to manage the aging effects on secondary side internals needed to maintain steam generator integrity.

The licensee made one commitment related to performing visual inspections of the steam generator upper and lower internals at least once every 5 years. This visual inspection checked for loose parts as well as corrosion. The licensee also committed to perform an integrity assessment after each steam generator inspection which addresses all known degradation mechanisms. Letter 2CAN041801 clarified that the licensee did not perform specialized inspections of several components during inspection of the lower internals since these components were not visible and were not required by the industry standard.

The team verified the licensee managed the aging effects with nondestructive examination techniques and visual inspections. In addition, the team noted that the licensee replaced the steam generators in 2000.

The team identified no concerns with this program.

.24 B.1.26 Structures Monitoring - Masonry Wall Program

This program managed aging effects related to cracking of the Category 1 masonry block walls. The licensee performed visual inspections to monitor for cracking in joints and blocks that could potentially affect wall qualification.

The licensee had committed to manage cracking of masonry walls within the scope of license renewal as part of their maintenance rule program. The team verified the licensee managed the aging effects with visual inspections as part of the maintenance rule program.

The team identified no concerns with this program.

.25 B.1.27 Structures Monitoring - Structures Monitoring Program

This program managed aging effects related to loss of material for component supports and aging effects related to concrete. The program included loss of material for cranes, rails, and supports. Although no aging effects requiring management were identified, this program also included the intake canal and concrete subject to aging management review.

The licensee had committed to periodically inspect concrete exposed to groundwater to confirm the absence of aging effects. The licensee also committed to inspect inaccessible concrete exposed to groundwater when excavated for maintenance activities. The licensee made these commitments because wells were not available for sampling groundwater at the time of the license renewal application. Subsequently, wells became available for sampling groundwater, and the licensee revised this program to periodically perform groundwater sampling. The licensee determined that they had developed a process to take the ground water readings every 5 years, but had failed to take the samples as expected. The licensee documented their failure to take the samples in Condition Report C-2018-02365. Subsequently, the licensee took samples and determined that the groundwater remained nonaggressive and within the specified limits.

The team identified no concerns with this program.

.26 B.1.28 System Walkdown Program

This program managed aging effects related to loss of material, loss of mechanical closure integrity, and cracking, as applicable, for systems and components within the scope of license renewal. The licensee performed visual inspections of readily accessible system and component surfaces during system walkdowns.

The licensee had committed to include visual inspections in the program to manage the aging effects listed above. The team verified the licensee included visual inspections in this program to manage loss of material, loss of mechanical closure integrity, and cracking, as applicable, for systems and components within the scope of license renewal.

The team identified no concerns with this program.

.27 B.1.29 Wall Thinning Monitoring Program

This program managed aging effects related to loss of material caused by erosion mechanisms. The licensee established visual inspections and nondestructive examinations to monitor wall thickness. The licensee included the emergency diesel generator exhaust piping and silencers, the diesel starting air receivers, and the alternate ac diesel generator exhaust piping and silencer.

The licensee identified two commitments related to this program. Specifically, the licensee committed to:

(1) conduct ultrasonic examination of the alternate ac diesel generator stainless steel expansion joints in lieu of disassembling the component and

(2) utilize industry accepted methods to conduct the wall thinning examinations.

Letter 2CAN041801 revised the commitment to monitor the thickness of the alternate ac diesel generator expansion joints from ultrasonic examination to conducting dye penetrant testing and visual examinations of the expansion joints every 18 months as part of the Periodic Surveillance and Periodic Maintenance Program.

The team determined that the licensee had developed specific monitoring locations identified on plant isometric drawings. The licensee recently replaced and repaired portions of the train A diesel generator exhaust piping and silencer, and had plans to replace the same components on train B during their upcoming refueling outage.

The team identified no concerns with this program.

.28 B.1.30.1 Water Chemistry Control - Auxiliary Systems

This program managed aging effects related to loss of material, cracking, and fouling of components exposed to treated water environments. The licensee monitored and maintained chemistry parameters that included pH, conductivity, solids, hardness, nitrite freeze point, and biological count. The licensee added sodium nitrite or sodium molybdate as corrosion inhibitors. The licensee performed visual inspections to detect visible corrosion, deposits, and biological growth. This program included the emergency diesel generator jacket water, alternate ac diesel generator cooling water, plant boilers, closed cooling water systems, cooling towers, and chilled water systems.

The team identified no concerns with this program.

.29 B.1.30.2 Water Chemistry Control - Closed Cooling

This program managed aging effects related to loss of material, cracking, and fouling for closed cooling water system components. The licensee monitored and controlled closed cooling water chemistry within acceptable limits using procedures and processes based on Electric Power Research Institute TR-107396, Closed Cooling Water Chemistry Guidelines. The implementation activities included visual inspections of systems/components. The licensee added corrosion inhibitors to manage general, crevice, and pitting corrosion. This program included the emergency diesel generator jacket water, alternate ac diesel generator cooling water, plant boilers, closed cooling water systems, cooling towers, and chilled water systems.

The team identified no concerns with this program.

.30 B.1.31 One Time Inspection Program (18175, 18207)

This program managed aging effects related to loss of material for the following systems:

(1) auxiliary building heating and ventilation,

(2) auxiliary building sump,

(3) drain collection header,

(4) liquid radwaste management,

(5) resin transfer,

(6) regenerative waste, and

(7) spent resin. The licensee performed nondestructive examination methods to determine whether degradation, as a result of loss of material, was occurring at a rate slow enough to ensure that the intended functions of the components will be maintained during the extended period of operation.

The licensee made two commitments related to this program. Specifically, the licensee committed to:

(1) implement a one-time inspection program for the identified systems that was consistent with the generic aging lessons learned report and

(2) revise the safety analysis report supplement to describe this program.

The original commitments included the post-accident sampling system in the list of systems managed by this program. Letter 2CAN041801 revised the commitment to remove the post-accident sampling system from this program since the licensee removed this system from serve.

The team verified the licensee implemented a one-time inspection program for the remaining seven systems consistent with the generic aging lessons learned report and revised the safety analysis report to describe this program.

During the performance of the inspections, the licensee identified four samples where the measured wall thickness was less than the acceptance criteria. The team identified that the licensee failed to consider scope expansion for the copper piping for the auxiliary building heating and ventilation system, as required by the one-time inspection program. The licensee documented this concern in Condition Report 2-2018-01107.

Subsequently, the licensee expanded the scope and performed four additional inspections on the population of copper piping. Since these inspections were performed prior to the period of extended operation, there was no performance deficiency. The licensee determined that the other copper piping samples had no aging effects present.

The team identified no additional concerns with this program.

.31 Selective Leaching Program (B.1.10.2, B.1.18, B.1.24)

This program managed aging effects related to loss of material resulting from selective leaching in components made of susceptible materials in aggressive environments. The susceptible materials included gray cast iron and copper alloys containing greater than 15 percent zinc or 8 percent aluminum, respectively. The aggressive environments included raw water, ground water, and waste water.

This program credited the water chemistry and closed treated water systems programs to control pH and concentration of corrosive contaminants to minimize selective leaching.

In the license renewal application process, the licensee credited the fire water system, periodic surveillance and preventive maintenance, and service water integrity programs with managing loss of material caused by selective leaching. Subsequently, the licensee committed to implement a standalone program to monitor for selective leaching.

The licensee established this as an independent aging management program. This program planned to use visual inspections and mechanical examination techniques (e.g., chipping or scraping) when opportunities arise as well as periodic destructive examinations to monitor for selective leaching. At a minimum, a sample of 3 percent of each material/environment population up to a maximum of 10 components per population will be inspected in each 10-year period during the period of extended operation.

The team verified that the licensee implemented the selective leaching program. The team concluded that this program provided reasonable assurance that the licensee will detect loss of material caused by selective leaching. The team based this conclusion, in part, on

(1) the use of laser-induced breakdown spectroscopy to accurately identify the population of components susceptible to selective leaching,

(2) the use of destructive examinations to identify selective leaching, and

(3) spreading out the inspections over each 10-year period allowed a longer period for this aging mechanism to manifest itself and be positively identified.

The team identified no concerns with this program.

.32 Implement the Environmentally Assisted Fatigue Option Program (Section 4.3.3.1)

(17940)

This program managed aging effects related to environmentally assisted fatigue. Prior to entering the period of extended operation, the safety evaluation report required the licensee to address the effects of environmentally assisted fatigue for several fatigue-sensitive locations, which included:

• Reactor vessel shell and lower head

• Reactor vessel inlet and outlet nozzles

• Surge line

• Charging nozzle

• Safety injection nozzle

• Shutdown cooling system Class 1 piping The licensee elected to perform the inspection option as allowed by their safety analysis report Section 4.3.3.1. The licensee identified two locations that would be inspected in accordance with ASME Section XI, Appendix L, Operating Plant Fatigue Assessment, and submitted that to the NRC for review. The licensee had preliminarily calculated that the cumulative usage factor for the other monitored locations remained less than one (1.0) and did not require inspection. Since the calculations were not available for review at the time of this inspection, this commitment will remain open.

This commitment and item remain open pending review during a future inspection.

c. Conclusions

Based on review of the actions implemented, inspection results reviewed, and interviews with program owners, the team determined that the licensee provided reasonable assurance and demonstrated that they would implement actions to effectively manage the effects of aging for each respective program. The team determined that the licensee met the commitments described prior to the period of extended operation. The team will need to review two additional commitments and associated aging management programs during a future inspection.

40A6 Meetings, Including Exit The team presented the inspection results to Mr. B. Daiber, Design Engineering Manager, and other members of the licensee staff during an exit meeting conducted on July 27, 2018. The licensee acknowledged the NRC inspection observations. The team retained no proprietary information and verified that no proprietary information was documented in this report.

SUPPLEMENTAL INFORMATION

PERSONNEL CONTACTED

Licensee Personnel

R. Anderson, Site Vice President

D. Bauman, License Renewal Project Manager

J. Beldin, Programs Engineer

D. Bice, Regulatory Assurance Specialist

M. Bradley, Programs Engineer

A. Bratton, Programs Engineer

K. Campbell, Design Engineer

B. Clark, Regulatory Assurance Specialist

C. Coffman, Systems Engineer

S. Creel, Programs Engineer

K. Ellis, Programs Engineer

K. Fresneda, Systems Engineer

D. Fromaberger, Licensing Engineer

R. Fougerousse, Contractor, Engineering Support

T. Hatfield, Engineering Programs Supervisor

C. Heinzen, Fire Protection Specialist

M. Hossain, Senior Engineer

A. Lamb, Electrical Engineer

J. Loving, Systems Engineer

T. Lunger, Containment Inservice Inspection Program Engineer

A. Osborne, Programs Engineer

N. Mosher, Licensing Specialist

M. Prock, Chemistry Supervisor

S. Pyle, Regulatory Assurance Manager

J. Rodan, Chemistry

S. Shelton, Fix-it-Now Engineer

B. Smith, Programs Engineer

R. Smith, Programs Engineer

D. Stringer, Inservice Inspection Contractor

S. Taylor, Inservice Inspection Program Engineer

B. Wayne, Senior Engineer

J. Wesselhoft, Civil Engineer

B. Whipple, Senior Engineer

J. Young, Electrical Engineer

NRC Personnel

C. Henderson, Senior Resident Inspector

COMMITMENTS REVIEWED

NRC closed Commitments 17908, 17909, 17914, and 17939 in Inspection Report : 05000368/2017009, which included NUREG-1828, Safety Evaluation Report Related to the License Renewal of Arkansas Nuclear One, Unit 2, Appendix A items 6 and 28.

The team closed the following tracking commitments in this inspection report during review of the aging management program implementation:

17905, 17910, 17911, 17912, 17913, 17915, 17916, 17917, 17918, 17919, 17920, 17921, 17922, 17923, 17924, 17925, 17926, 17927, 17928, 17929, 17930, 17931, 17932, 17933, 17934, 17935, 17936, 17937, 17938, 18175, 18207, and 20017.

During review of these commitments the team confirmed that the licensee had met the conditions for safety evaluation report, Appendix A, Items 1, 2, 3, 4, 5, 7, 8, 9,10, 11, 12, 13, 14, 15, 16, 17, 18, 19, 20, 21, 22, 23, 24, 25, 26, 27, 29, 30, 31, 32, 33, 34, 35, 36, 37, 38, and 40.

As described in the report, the team did not complete review of the aging management program and associated tracking commitments related to environmentally assisted fatigue (17940, safety evaluation report, Appendix A, Item 39).