IR 05000313/2017002

NRC Integrated Inspection Report 05000313/2017002 and 05000368/2017002

ML17220A351
Person / Time
Site:	Arkansas Nuclear
Issue date:	08/03/2017
From:	O'Keefe N NRC/RGN-IV/DRP/RPB-E
To:	Richard Anderson Entergy Operations
Neil OKeefe
References
EA-16-143 IR 2017002
Download: ML17220A351 (67)

Text

UNITED STATES ust 3, 2017

SUBJECT:

ARKANSAS NUCLEAR ONE - NRC INSPECTION REPORT 05000312017002 and 05000368/2017002

Dear Mr. Anderson:

On June 30, 2017, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Arkansas Nuclear One facility, Units 1 and 2. On July 10, 2017, the NRC inspectors discussed the results of this inspection with you and other members of your staff. The results of this inspection are documented in the enclosed report.

NRC inspectors documented three findings of very low safety significance (Green) in this report.

All of these findings involved violations of NRC requirements. Further, inspectors documented a licensee-identified violation which was determined to be of very low safety significance in this report. The NRC is treating these violations as non-cited violations (NCVs) consistent with Section 2.3.2.a of the NRC Enforcement Policy.

If you contest the violations or significance of these NCVs, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001; with copies to the Regional Administrator, Region IV; the Director, Office of Enforcement; and the NRC resident inspector at Arkansas Nuclear One.

If you disagree with a cross-cutting aspect assignment in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your disagreement, to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001; with copies to the Regional Administrator, Region IV; and the NRC resident inspector at Arkansas Nuclear One.

Also, a violation of the licensees current site-specific licensing basis for tornado-generated missile protection was identified. Because this violation was identified during the discretion period discussed in Enforcement Guidance Memorandum 15-002, Enforcement Discretion for Tornado Missile Protection Noncompliance, Revision 1, and because the licensee implemented compensatory measures, the NRC is exercising enforcement discretion by not issuing an enforcement action for the violation and is allowing continued reactor operation. (EA-16-143) In accordance with Title 10 of the Code of Federal Regulations (10 CFR) 2.390, Public Inspections, Exemptions, Requests for Withholding, a copy of this letter, its enclosure, and your response (if any) will be made available electronically for public inspection in the NRCs Public Document Room or the NRC's Agencywide Documents Access and Management System (ADAMS), accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html. To the extent possible, your response, if any, should not include any personal privacy, proprietary, or safeguards information so that it can be made available to the public without redaction.

Sincerely,

/RA/

Neil OKeefe, Branch Chief Project Branch E Division of Reactor Projects Docket Nos. 50-313 and 50-368 License Nos. DRP-51 and NPF-6

Enclosures:

Inspection Report 05000313/2017002 and 05000368/2017002 w/ Attachments:

1. Supplemental Information 2. O

REGION IV==

Docket: 05000313; 05000368 License: DPR-51; NPF-6 Report: 05000313/2017002; 05000368/2017002 Licensee: Entergy Operations, Inc.

Facility: Arkansas Nuclear One, Units 1 and 2 Location: Junction of Highway 64 West and Highway 333 South Russellville, Arkansas Dates: April 1 through June 30, 2017 Inspectors: B. Tindell, Senior Resident Inspector T. Sullivan, Resident Inspector M. Tobin, Resident Inspector J. Choate, Project Engineer J. Drake, Senior Reactor Inspector N. Greene, PhD, Health Physicist M. Phalen, Senior Health Physicist Approved Neil OKeefe By: Chief, Project Branch E Division of Reactor Projects 1 Enclosure

SUMMARY

IR 05000313/2017002; 05000368/2017002; 04/01/2017 - 06/30/2017; Arkansas Nuclear One,

Units 1 and 2; Integrated Inspection Report; Fire Protection, Operability Determinations and Functionality Assessments, Post-Maintenance Testing.

The inspection activities described in this report were performed between April 1 and June 30, 2017, by the resident inspectors at Arkansas Nuclear One and inspectors from the NRCs Region IV office. Three findings of very low safety significance (Green) are documented in this report. All of these findings involved violations of NRC requirements. Additionally, NRC inspectors documented in this report one licensee-identified violation of very low safety significance. 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.

Cornerstone: Initiating Events

Green.

The inspectors identified a finding and associated non-cited violation of License Conditions 2.C.(3)(b), Fire Protection, for Arkansas Nuclear One Unit 2, associated with the failure to adequately implement the fire protection program. Specifically, the licensee failed to follow the requirements for control of flammable liquid lockers and compressed hydrogen gas cylinders. The licensee immediately removed the hydrogen cylinders and stored them in an approved location and began processing the flammable liquid lockers through the design change process. The licensee entered these issues into their corrective action program as Condition Reports CR-ANO-2-2017-01525 and CR-ANO-C-2017-01508.

The failure to properly control transient combustible material in accordance with the approved fire protection program was a performance deficiency. The finding was considered more than minor because storing unanalyzed flammable material could result in the potential to exceed combustible material limits, and is associated with the protection against external factors attribute of the Initiating Events Cornerstone and adversely affected the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during power operations. Specifically, the failure to follow procedures resulted in conditions that increased the risk of fire which could upset plant stability and challenge critical safety functions. The inspectors evaluated the finding using Inspection Manual Chapter 0609, Appendix F, Fire Protection Significance Determination Process, and assigned the finding to the Fire Prevention and Administrative Controls category; because it affected the licensees combustible materials control. The finding was determined to be Green, or very low safety significance, in accordance with Inspection Manual Chapter 0609, Appendix F, Question 1.3.1, because the reactor would have been able to reach and maintain safe shutdown since the postulated fires would not have affected both trains of safe shutdown equipment. This finding had a cross-cutting aspect associated with teamwork within the human performance area since multiple groups in the licensee staff were involved in the decisions that resulted in the improper introduction of the flammable liquids lockers and the improper storage of the hydrogen cylinders [H.4]. (Section 1R05)

Cornerstone: Mitigating Systems

Green.

The inspectors documented a Green self-revealing finding and associated non-cited violation of Unit 2 Technical Specification 6.4.1.a, for failure to properly pre-plan and perform maintenance on the Unit 2 containment spray pump B breaker in accordance with written procedures. Specifically, the licensee failed to install a cam shaft set screw during the breakers last overhaul. The cam eventually became displaced on the shaft, and the breaker failed to close. To correct the issue, the licensee replaced the breaker and installed a cam shaft set screw in the failed breaker. The licensee also inspected all other similar breakers to verify the cams were properly secured. The licensee entered the issue into their corrective action program as Condition Report CR-ANO-2-2017-03168.

The failure to install a cam shaft set screw during the overhaul of the Unit 2 containment spray pump B breaker is a performance deficiency. The performance deficiency is more than minor because it was associated with the equipment performance attribute of the mitigating systems cornerstone and adversely affected the cornerstone objective to ensure the reliability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the performance deficiency resulted in the failure of a Unit 2 containment spray pump breaker. Using Inspection Manual Chapter 0609, Appendix A,

The Significance Determination Process (SDP) for Findings At-Power, dated June 19, 2012, Exhibit 2, Mitigating Systems Screening Questions, the issue screened as having very low safety significance (Green) because it was not a design or qualification deficiency; did not represent a loss of system; did not result in the actual loss of function of a train of technical specification equipment for greater than its allowed outage time; and did not screen as potentially risk significant due to seismic, flooding, or severe weather events. The inspectors determined this finding did not have a cross-cutting aspect because the most significant contributor did not reflect current licensee performance. Specifically, the error occurred during the breakers last overhaul, which occurred in 2011. (Section 1R15)

Green.

The inspectors reviewed a Green self-revealing finding and associated non-cited violation of Unit 1 Technical Specification 3.5.2, Emergency Core Cooling System (ECCS) -

Operating, for the licensees failure to ensure the operability of the P36A high pressure injection pump after reinstalling its feeder breaker during a unit outage. A violation of Unit 1 Technical Specification 3.0.4 was also identified for making a mode change without meeting the requirements to do so. Following unit restart, the pump failed to start during routine equipment rotation, resulting in one train of emergency core cooling system being inoperable for longer than allowed by Unit 1 Technical Specifications. The licensee subsequently identified that the feeder breaker had not been fully racked into position.

Inspectors also noted that the breaker had been racked in manually rather than using the normal electric racking tool, and no special precautions had been taken to ensure this infrequently-used method was successful. When the breaker was correctly racked in, the pump was satisfactorily tested. The licensee subsequently verified that all similar breakers were correctly racked into position. The licensee entered this issue into their corrective action program as Condition Report CR-ANO-1-2017-01764.

The inspectors determined that the failure to verify that the P36A high pressure injection pump was operable after racking its feeder breaker into the switchgear cubicle was a performance deficiency. The performance deficiency was more than minor because it was associated with the human performance attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences.

The inspectors performed the initial significance determination for the performance deficiency using NRC Inspection Manual 0609, Appendix A, Exhibit 2, Mitigating Systems Screening Questions, dated June 19, 2012, and concluded that it required a detailed risk evaluation because it involved the loss of a single train of mitigating equipment for longer than the technical specification allowed outage time. Therefore, a Region IV senior reactor analyst performed a bounding detailed risk evaluation. The estimate in the increase in core damage frequency is 4.4E-8 per year, or of very low safety significance (Green). This finding had a cross-cutting aspect in the area of Human Performance, Avoid Complacency, because the licensee failed to ensure that individuals recognize and plan for the possibility of mistakes, latent issues, and inherent risk, even while expecting successful outcomes.

Specifically, the licensee failed to verify that the pump was operable after its breaker was reinstalled, even though an infrequently-used method was employed [H.12]. (Section 1R19)

Licensee Identified Violations

A violation of very low safety significance that was identified by the licensee has been reviewed by the inspectors. Corrective actions taken or planned by the licensee have been entered into the licensees corrective action program. This violation and associated corrective action tracking numbers are listed in Section 4OA7 of this report.

PLANT STATUS

Unit 1 began the inspection period at full power. On April 26, 2017, high winds damaged offsite power transmission lines approximately 16 miles from the plant, which caused a main generator trip and reactor trip. See Section 40A3.1 of this report for details. During the unplanned outage, operators cooled down the reactor coolant system (RCS) in order to replace a reactor coolant pump seal. After the transmission lines and pump seal were repaired, operators restarted the reactor on May 17, 2017. On May 18, 2017, while the plant was at 25 percent power, operators noted turbine oscillations and tripped the turbine, while the reactor remained in service. See Section 4OA3.1 of this report for details. After the cause of the oscillations was repaired, operators placed the turbine generator in service and raised reactor power. The unit reached full power on May 22, 2017, and remained there for the remainder of the inspection period.

Unit 2 remained in refueling outage 2R25 for the entire inspection period. On April 26, 2017, while the reactor fuel was fully offloaded to the spent fuel pool, high winds damaged offsite power transmission lines and power was momentarily lost and restored. See Section 4OA3.1 of this report for details.

REPORT DETAILS

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R01 Adverse Weather Protection

.1 Summer Readiness for Offsite and Alternate AC Power Systems

a. Inspection Scope

On April 20, 2017, the inspectors completed an inspection of the stations off-site and alternate-ac power systems. The inspectors inspected the material condition of these systems, including transformers and other switchyard equipment, to verify that plant features and procedures were appropriate for operation and continued availability of off-site and alternate-ac power systems. The inspectors reviewed outstanding work orders and open condition reports for these systems. The inspectors walked down the switchyard to observe the material condition of equipment providing off-site power sources. The inspectors assessed corrective actions for identified degraded conditions and verified that the licensee had considered the degraded conditions in its risk evaluations and had established appropriate compensatory measures. The inspectors verified that the licensees procedures included appropriate measures to monitor and maintain availability and reliability of the off-site and alternate-ac power systems.

These activities constituted one sample of summer readiness of off-site and alternate-ac power systems, as defined in Inspection Procedure 71111.01.

b. Findings

No findings were identified.

.2 Readiness for Impending Adverse Weather Conditions

a. Inspection Scope

On April 11, 2017, the inspectors completed an inspection of the stations readiness for impending adverse weather conditions. The inspectors reviewed plant design features, the licensees procedures to respond to tornadoes and high winds, and the licensees implementation of these procedures. The inspectors evaluated operator staffing and accessibility of controls and indications for those systems required to control the plant.

These activities constituted one sample of readiness for impending adverse weather conditions, as defined in Inspection Procedure 71111.01.

b. Findings

No findings were identified.

1R04 Equipment Alignment

Partial Walk-Down

a. Inspection Scope

The inspectors performed partial system walk-downs of the following risk-significant systems:

• April 2, 2017, Unit 2, reactor coolant system vent for emergency makeup capability while in lowered inventory

• April 2, 2017, Unit 2, reactor coolant system level instruments while draining to lowered inventory

• April 20, 2017, Unit 2, spent fuel pool cooling system during full core offload

• May 5, 2017, Unit 1, reactor coolant system level instruments during lowered inventory The inspectors reviewed the licensees procedures and system design information to determine the correct lineup for the systems. They visually verified that critical portions of the systems were correctly aligned for the existing plant configuration.

These activities constituted four partial system walk-down samples as defined in Inspection Procedure 71111.04.

b. Findings

No findings were identified.

1R05 Fire Protection

Quarterly Inspection

a. Inspection Scope

The inspectors evaluated the licensees fire protection program for operational status and material condition. The inspectors focused their inspection on six plant areas important to safety:

• April 14, 2017, Units 1 and 2, storage of transient combustibles in various areas of the plant

• April 18, 2017, Unit 1, Fire Zone 159-B, spent fuel pool area

• April 18, 2017, Unit 2, Fire Zone 2151-A, spent fuel pool area

• April 18, 2017, Unit 2, Fire Zone 4-EE,317 elevation general access area

• April 19, 2017, Unit 2, Fire Zones 2032-K, 2033-K, containment building

• June 30, 2017, Unit 1, Fire Zone 160-B, Turbine Building Computer Room For each area, the inspectors evaluated the fire plan against defined hazards and defense-in-depth features in the licensees fire protection program. The inspectors evaluated control of transient combustibles and ignition sources, fire detection and suppression systems, manual firefighting equipment and capability, passive fire protection features, and compensatory measures for degraded conditions.

These activities constituted six quarterly inspection samples, as defined in Inspection Procedure 71111.05.

b. Findings

Introduction.

The inspectors identified two examples of a Green finding and associated non-cited violation of License Condition 2.C.(3)(b), Fire Protection, for Unit 2 for the failure to follow approved fire protection program procedures for the control of flammable liquid lockers and combustible gas cylinders.

Description.

Example 1: Control of Flammable Liquid Lockers During plant walkdowns between April 10, 2017, and April 16, 2017, the inspectors identified 11 permanent flammable liquid lockers that had been installed using the wrong process. The inspectors determined that the licensee was required to install and maintain flammable storage lockers using Procedure EN-DC-115, Engineering Change Process, but these lockers were installed using Procedure 1000.034, Control of Temporary Services and Equipment, Revision 8.

Procedure EN-DC-330, Fire Protection Program, Revision 4, Section 2, Fire Prevention and Protection, Item

(a) stated that, Control of transient combustibles shall be implemented by administrative controls to govern the handling, storage, and limitations for use of ordinary combustible materials, combustible and flammable gases and liquids, and other combustible supplies in accordance with EN-DC-161.

Procedure EN-DC-161, Control of Combustibles, Revision 16, required that Installation or long-term storage of combustible material is controlled through the design change process via EN-DC-115 and is not controlled by this procedure. Section 5.1, Item 2 of EN-DC-161 stated, Where it is desired to permanently store combustible materials in any plant area, request a new designated storage area, or when a revision or an extension is required to a previously approved storage area, an engineering change should be initiated in accordance with Procedure EN-DC-115. The inspectors determined that the licensee had installed 11 flammable liquid lockers, starting in 2000, in various locations in the plant using Procedure 1000.034, Control of Temporary Services and Equipment, Revision 8. Some of these lockers were found with the doors open, doors that did not self-close as required by the manufacturer, or contained both solid and liquid combustibles, contrary to procedures and manufacturers guidance. The combustible loading in these lockers was not accounted for in the calculations for the affected fire areas.

Example 2: Control of Combustible Gas Cylinders The inspectors noted 15 hydrogen gas bottles that were not stored in accordance with Procedure EN-IS-109, Compressed Gas Cylinder Handling and Storage, Revision 7.

Procedure EN-IS-109 required, in part, that the cylinders be stored such that they are protected from environmental and physical damage and that there are no combustibles within 20 feet of the storage area. During a Unit 2 plant tour on April 13, 2017, the inspectors identified that the hydrogen gas bottles were stored in direct sunlight and exposed to potential physical damage. The cylinders had been placed inside a scaffolding frame adjacent to the entrance to the Unit 1 Auxiliary Building that was being used to access cable raceways above the cylinders. The scaffold did not have toe boards installed and the workers were not using restraints on their tools, so the hydrogen bottles were not adequately protected from damage from falling objects. In addition, there were combustible materials within 20 feet of the compressed gas cylinders.

Analysis.

The failure to properly control transient combustible material in accordance with the approved fire protection program was a performance deficiency. The finding was considered more than minor because storing unanalyzed material could result in the potential to exceed combustible limits. It is associated with the protection against external factors attribute of the Initiating Events Cornerstone and adversely affected the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during power operations. Specifically, the failure to follow procedures resulted in conditions that increased the risk of fire which could upset plant stability and challenge critical safety functions. The inspectors evaluated the finding using Inspection Manual Chapter 0609, Appendix F, Fire Protection Significance Determination Process, and assigned the finding to the Fire Prevention and Administrative Controls category; in that, it affected the licensees combustible materials control. The finding was determined to be Green, or very low safety significance, in accordance with Inspection Manual Chapter 0609, Appendix F, Question 1.3.1, because the reactor would be able to reach and maintain safe shutdown since the fire would not have affected both trains of safe shutdown equipment. This finding had a cross-cutting aspect associated with teamwork within the human performance area since multiple groups in the licensee staff were involved in the decisions that resulted in the improper introduction of the flammable liquids lockers and the improper storage of the hydrogen cylinders [H.4].

Enforcement.

Unit 2 License Condition 2.C (3)(b), Fire Protection, requires that written procedures be established, implemented, and maintained covering fire protection program implementation.

Procedure EN-DC-330, Fire Protection Program, Revision 4, Section 2, Fire Prevention and Protection, requires that control of transient combustibles shall be implemented by administrative controls to govern the handling, storage, and limitations for use of ordinary combustible materials, combustible and flammable gases and liquids, and other combustible supplies in accordance with Procedure EN-DC-161, Control of Combustibles. Procedure EN-DC-161, Revision 16, requires that the installation or long-term storage of combustible material be controlled through the design change process in accordance with Procedure EN-DC-115.

Procedure EN-DC-161, Revision 16, Step 5.5[1](c), requires, in part, that flammable gases be stored in accordance with Procedure EN-IS-109. Procedure EN-IS-109, Compressed Gas Cylinder Handling and Storage, Revision 7, Steps 5.2 and 5.3 require, in part, that the cylinders be stored such that they are protected from environmental and physical damage, including protecting gas cylinders from any object that could produce a harmful cut, and that there are no combustibles within 20 feet of storage area.

Contrary to the above requirements, the license failed to implement written procedures covering the fire protection program as evidenced by the following two examples:

1. From approximately March 2000 until April 2017, the licensee failed to follow the requirements of Procedure EN-DC-161, Control of Combustibles, Revision 16, that required flammable liquid storage lockers to be installed in the plant in accordance with the design change process Procedure EN-DC-115. Instead, the flammable liquid storage lockers were installed in the plant using Procedure 1000.034, Control of Temporary Services and Equipment, Revision 8. As a result of using the wrong process, storage lockers were observed to be in disrepair and transient combustibles contained in the lockers were not accounted for in the fire area loading calculations.

2. On April 13, 2017, the licensee failed to follow the requirements of Procedure EN-IS-109, Compressed Gas Cylinder Handling and Storage, Revision 7, for temporary storage of 15 cylinders of compressed hydrogen located adjacent to the entrance to the Unit 1 Auxiliary Building. Specifically, the hydrogen cylinders were not protected from environmental and physical damage because a scaffold platform immediately above the cylinders, used by workers, did not have toe boards installed and the workers were not using restraints on their tools. In addition, there were combustible materials within 20 feet of the gas cylinders.

The licensee immediately removed the hydrogen cylinders and stored them in an approved location and began processing the flammable liquid lockers through the design change process. Because this finding is of very low safety significance and has been entered into the corrective action program as Condition Reports CR-ANO-2-2017-01525 and CR-ANO-C-2017-01508, this violation is being treated as a non-cited violation consistent with Section 2.3.2.a of the NRC Enforcement Policy: NCV 05000368/2017002-01, Failure to Follow Fire Protection Program Procedures.

1R08 Inservice Inspection Activities

The activities described in subsections 1 through 5 below constitute completion of one inservice inspection sample, as defined in Inspection Procedure 71111.08.

.1 Non-destructive Examination Activities and Welding Activities

a. Inspection Scope

The inspectors directly observed the following nondestructive examinations:

SYSTEM COMPONENT IDENTIFICATION EXAMINATION TYPE Low Pressure 2GCB-7-H18 Visual Test 3 Safety Injection Low Pressure 2PSV-5089 FW-6 Dye Penetrant Safety Injection Emergency Diesel 2JBD-202-30 Ultrasonic Generator Reactor Vessel Eddy Current Penetration 49 Head Main Steam Reheat FW-44C1 Radiograph Main Steam Reheat FW-27C1 Radiograph The inspectors reviewed records for the following nondestructive examinations:

SYSTEM COMPONENT IDENTIFICATION EXAMINATION TYPE Reactor Vessel Ultrasonic Penetration 49 Head Reactor Vessel Ultrasonic Penetration 29 Head Main Feedwater FW-1024 Ultrasonic Safety Injection* Part 2724A Weld ID 320* Ultrasonic Safety Injection* Part 2724A Weld ID 320* Ultrasonic Safety Injection 2GCB-5-H10 Visual Test 3 Containment 2P-66 Visual Test 3 SYSTEM COMPONENT IDENTIFICATION EXAMINATION TYPE Common Feedwater FW-6C1 Magnetic Particle Common Feedwater FW-8C1 Magnetic Particle

• This is inservice designation and part number, not plant system and component identification number. The heat exchangers have not been installed in the plant and actual location (2E-35 A or 2E-35 B) has not been determined.

During the review and observation of each examination, the inspectors observed whether activities were performed in accordance with the ASME Code requirements and applicable procedures. The inspectors reviewed seven indications that were previously examined, and observed that the licensee evaluated and accepted the indications in accordance with the ASME Code and/or an NRC approved alternative. The inspectors also reviewed the qualifications of all nondestructive examination technicians performing the inspections to determine whether they were current.

The inspectors directly observed a portion of the following welding activities:

SYSTEM WELD IDENTIFICATION WELD TYPE Common Feedwater FW-6C1 Gas Tungsten Arc Common Feedwater FW-8C1 Gas Tungsten Arc The inspectors reviewed records for the following welding activities:

SYSTEM WELD IDENTIFICATION WELD TYPE Main Feedwater FW-100 Gas Tungsten Arc Emergency Feedwater FW-14 Gas Tungsten Arc Emergency Feedwater FW-16 Gas Tungsten Arc Main Feedwater FW-82 Shielded Metal Arc Main Feedwater FW-83 Shielded Metal Arc Main Feedwater FW-152 Shielded Metal Arc The inspectors reviewed whether the welding procedure specifications and the welders had been properly qualified in accordance with ASME Code Section IX requirements.

The inspectors also determined whether that essential variables were identified, recorded in the procedure qualification record, and formed the bases for qualification of the welding procedure specifications.

b. Findings

No findings were identified.

.2 Vessel Upper Head Penetration Inspection Activities

a. Inspection Scope

The inspectors reviewed the results of the licensees bare metal visual inspection of the Reactor Vessel Upper Head Penetrations to determine whether the licensee identified any evidence of boric acid challenging the structural integrity of the reactor head components and attachments. The inspectors also verified that the required inspection coverage was achieved and limitations were properly recorded. The inspectors reviewed the results of the licensees volumetric inspection of the reactor vessel head to determine whether the inspection met Code Case N-729-1. The inspectors also reviewed that the required inspection coverage was achieved and whether limitations were properly recorded. The inspectors reviewed the certifications for the personnel performing the inspection to verify that the examiners were certified to their respective nondestructive examination method.

b. Findings

No findings were identified.

.3 Boric Acid Corrosion Control Inspection Activities

a. Inspection Scope

The inspectors reviewed the licensees implementation of its boric acid corrosion control program for monitoring degradation of those systems that could be adversely affected by boric acid corrosion. The inspectors reviewed the documentation associated with the licensees boric acid corrosion control walk-down as specified in Procedure CEP-BAC-001, Boric Acid Corrosion Control (BACC) Program Plan, Revision 1. The inspectors reviewed whether the visual inspections emphasized locations where boric acid leaks could cause degradation of safety-significant components, and whether engineering evaluation used corrosion rates applicable to the affected components and properly assessed the effects of corrosion induced wastage on structural or pressure boundary integrity. The inspectors observed whether corrective actions taken were consistent with the ASME Code, 10 CFR 50, and Appendix B requirements.

b. Findings

No findings were identified.

.4 Steam Generator Tube Inspection Activities

Inspection Scope There were no steam generator tube inspections performed during this outage.

.5 Identification and Resolution of Problems

a. Inspection Scope

The inspectors reviewed 15 condition reports which dealt with inservice inspection activities and found the corrective actions for inservice inspection issues were appropriate. From this review, the inspectors concluded that the licensee has an appropriate threshold for entering inservice inspection issues into the corrective action program and has procedures that direct a root cause evaluation when necessary. The licensee also has an effective program for applying industry inservice inspection operating experience. Specific documents reviewed during this inspection are listed in the attachment.

b. Findings

No findings were identified.

1R11 Licensed Operator Requalification Program and Licensed Operator Performance

.1 Review of Licensed Operator Requalification

a. Inspection Scope

On May 8, 2017, the inspectors observed simulator training for a Unit 2 operating crew.

The inspectors assessed the performance of the operators and the evaluators critique of their performance. The inspectors also assessed the modeling and performance of the simulator during the requalification activities.

On May 23, 2017, the inspectors observed simulator training for a Unit 1 operating crew.

The inspectors assessed the performance of the operators and the evaluators critique of their performance. The inspectors also assessed the modeling and performance of the simulator during the requalification activities.

These activities constituted completion of two quarterly licensed operator requalification program samples, as defined in Inspection Procedure 71111.11.

b. Findings

No findings were identified.

.2 Review of Licensed Operator Performance

a. Inspection Scope

The inspectors observed the performance of on-shift licensed operators in the plants main control room. At the time of the observations, the plant was in a period of heightened activity and risk. The inspectors observed the operators performance of the following activities:

• April 3, 2017, Unit 2, lowering reactor coolant system inventory to remove the vessel head

• May 4, 2017, Unit 1, lowering reactor coolant system inventory to replace reactor coolant pump seal In addition, the inspectors assessed the operators adherence to plant procedures, including the conduct of operations procedure and other operations department policies.

These activities constituted completion of two quarterly licensed operator performance samples, as defined in Inspection Procedure 71111.11.

b. Findings

No findings were identified.

1R12 Maintenance Effectiveness

Routine Maintenance Effectiveness

a. Inspection Scope

The inspectors reviewed two instances of degraded performance or condition of safety-significant SSCs:

• June 28, 2017, Unit 2, shutdown cooling heat exchanger replacement due to corrosion

• June 28, 2017, Units 1 and 2, common feedwater system installation and startup The inspectors reviewed the extent of condition of possible common cause SSC failures and evaluated the adequacy of the licensees corrective actions. The inspectors reviewed the licensees work practices to evaluate whether these may have played a role in the degradation of the SSCs. The inspectors assessed the licensees characterization of the degradation in accordance with 10 CFR 50.65 (the Maintenance Rule), and verified that the licensee was appropriately tracking degraded performance and conditions in accordance with the Maintenance Rule.

These activities constituted completion of two maintenance effectiveness samples, as defined in Inspection Procedure 71111.12.

b. Findings

No findings were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

The inspectors reviewed six risk assessments performed by the licensee prior to changes in plant configuration and the risk management actions taken by the licensee in response to elevated risk:

• April 2, 2017, Unit 2, recirculation actuation signal defeated for trip of low pressure safety injection pumps, protected train signs posted, and fire watches on station prior to entering lowered inventory

• April 14, 2017, Units 1 and 2, alternate ac diesel generator fuel makeup isolated while Unit 1 turbine driven emergency feedwater pump was out of service

• April 20, 2017, Units 1 and 2, switchyard work while Midcontinent Independent System Operator had issued Conservative Operations Notification, a notification of potential generation shortage

• April 27, 2017, Unit 2, removal and lifting of old shutdown cooling heat exchanger

• April 27, 2017, Unit 1, lifting of the old shutdown cooling heat exchanger potential cross-unit interactions

• May 7, 2017, Unit 1, procedurally required postings to prevent hot work during lowered inventory The inspectors verified that these risk assessment were performed timely and in accordance with the requirements of 10 CFR 50.65 (the Maintenance Rule) and plant procedures. The inspectors reviewed the accuracy and completeness of the licensees risk assessments and verified that the licensee implemented appropriate risk management actions based on the result of the assessments.

Additionally, on April 13, 2017, the inspectors observed portions of emergent work to correct an incorrect torque switch setting that had rendered the Unit 1 turbine driven emergency feedwater pump steam admission valve inoperable. The emergent work activity had the potential to affect the functional capability of a mitigating system.

The inspectors verified that the licensee appropriately developed and followed a work plan for these activities. The inspectors verified that the licensee took precautions to minimize the impact of the work activities on unaffected structures, systems, and components (SSCs).

These activities constituted completion of seven maintenance risk assessments and emergent work control inspection samples, as defined in Inspection Procedure 71111.13.

b. Findings

No findings were identified.

1R15 Operability Determinations and Functionality Assessments

.1 Operability Determinations

a. Inspection Scope

The inspectors reviewed six operability determinations that the licensee performed for degraded or nonconforming SSCs:

• April 11, 2017, operability determination of the Unit 1 reactor protection system with one nuclear instrument failed, causing a half-trip of the system

• April 13, 2017, operability determination of the Unit 1 turbine driven emergency feedwater pump steam admission valve for an incorrectly set torque switch settings

• May 11, 2017, operability determination of the Unit 1 control rods following ratcheting during a reactor trip

• May 11, 2017, operability determination of the Unit 1 emergency feedwater initiation and control system after emergency feedwater did not immediately feed steam generators following reactor trip

• May 31, 2017, operability determination of Units 1 and 2 Magne-blast breakers after licensee discovered loose closing cam set screws

• June 28, 2017, operability determination of Units 1 and 2 tornado missile vulnerabilities The inspectors reviewed the timeliness and technical adequacy of the licensees evaluations. Where the licensee determined the degraded SSC to be operable, the inspectors verified that the licensees compensatory measures were appropriate to provide reasonable assurance of operability. The inspectors verified that the licensee had considered the effect of other degraded conditions on the operability of the degraded SSC.

These activities constituted completion of six operability and functionality review samples, as defined in Inspection Procedure 71111.15.

b. Findings

Introduction.

The inspectors documented a Green self-revealing finding and associated non-cited violation of Unit 2 Technical Specification 6.4.1.a, for failure to properly pre-plan and perform maintenance on the Unit 2 containment spray pump B breaker in accordance with written procedures. Specifically, the licensee failed to install a cam shaft set screw during the breakers last overhaul. The cam eventually became displaced on the shaft, and the breaker failed to close.

Description.

On May 26, 2017, operators attempted to start the Unit 2 containment spray pump B but the breaker failed to close. During troubleshooting on the Magne-Blast breaker, the licensee discovered that the closing cam had moved down the cam shaft and jammed, preventing the breaker from closing. The cam had displaced because the closing cam set screw intended to secure the cam axially to the shaft was missing. The licensee documented the issue in Condition Report CR-ANO-2-2017-03168, replaced the breaker, and repaired the failed breaker.

The licensee promptly performed an extent of condition review of all other important-to-safety Magne-Blast breakers and discovered that 11 breakers had loose set screws. All of the additional loose set screws still maintained engagement with the shaft, so that the closing cams remained secure. The licensee also performed a cause evaluation and concluded that the set screw had loosened and backed out over time. However, the inspectors noted that the missing set screw and the locking screw that fit on top were not found in the breaker cubicle and all of the set screws identified as loose during the extent of condition review still staked the cam to the shaft, so the evidence did not support the licensees conclusion. Therefore, the inspectors concluded that it was more likely that maintenance personnel had failed to reinstall the set screw during the last breaker overhaul.

Licensee maintenance personnel had last overhauled the failed breaker on October 7, 2011, in accordance with Procedure OP-1416.041, Magne-Blast Circuit Breaker Overhaul, Revision 9. The procedure contained instructions to assemble the breaker operating mechanism. The procedure did not provide detailed assembly instructions for the closing cam and shaft set screw, which are parts in the operating mechanism. The inspectors concluded that the maintenance personnel had but failed to install the set screw for unknown reasons. As corrective actions for the failure, the licensee added detailed steps to ensure that the set screws are inspected and tightened during future overhauls, and to add adhesive to the screw threads to prevent the screws from backing out. The inspectors concluded that the corrective actions would provide reasonable assurance that the screw would be installed during future breaker overhauls.

The inspectors noted that the breaker had been cycled to start the pump earlier the same day as the breaker failed, while the reactor fuel had been offloaded. Therefore, the inspectors concluded that the exposure period for the breaker was less than one day while the reactor fuel had been offloaded to the spent fuel pool. The inspectors also concluded that the reliability of the breaker had been adversely affected since the overhaul in 2011.

Analysis.

The failure to install a cam shaft set screw during the overhaul of the Unit 2 containment spray pump B breaker is a performance deficiency. The performance deficiency is more than minor because it was associated with the equipment performance attribute of the mitigating systems cornerstone and adversely affected the cornerstone objective to ensure the reliability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the performance deficiency resulted in the failure of a Unit 2 containment spray pump breaker. Using Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, dated June 19, 2012, Exhibit 2, Mitigating Systems Screening Questions, the issue screened as having very low safety significance (Green) because it was not a design or qualification deficiency; did not represent a loss of system; did not result in the actual loss of function of a train of technical specification equipment for greater than its allowed outage time; and did not screen as potentially risk significant due to seismic, flooding, or severe weather. The inspectors determined this finding did not have a cross-cutting aspect because the most significant contributor did not reflect current licensee performance. Specifically, the failed breaker was last overhauled in 2011.

Enforcement.

Unit 2 Technical Specification 6.4.1.a requires, in part, that written procedures shall be established, implemented, and maintained covering the applicable procedures recommended in Regulatory Guide 1.33, Quality Assurance Program Requirements, Revision 2, Appendix A, February 1978. Regulatory Guide 1.33, Revision 2, Appendix A, Section 9.a, states, in part, that maintenance that can affect the performance of safety-related equipment should be properly pre-planned and performed in accordance with written procedures, documented instructions, or drawings appropriate to the circumstances. The licensee established Procedure OP-1416.041, Magne-Blast Circuit Breaker Overhaul, Revision 9, to meet the Regulatory Guide 1.33 requirement related to maintenance on safety-related Magne-Blast breakers. Step 8.26 of Procedure OP-1416.041 required that the breaker operating mechanism be assembled after disassembly and inspection. Contrary to the above, on October 7, 2011, the licensee did not ensure that the operating mechanism for the Unit 2 containment spray pump B was assembled after disassembly and inspection. Specifically, the licensee failed to install the cam shaft set screw, which allowed the cam shaft to become displaced over time and caused the breaker to fail. To correct the issue, the licensee replaced the breaker and installed the cam shaft set screw on the breaker and improved the level of detail in the maintenance procedure. Because this finding is of very low safety significance and was entered into the corrective action program as Condition Report CR-ANO-2-2017-03168, this violation is being treated as a non-cited violation, consistent with Section 2.3.2.a of the NRC Enforcement Policy: NCV 05000368/2017002-02, Failure to Install Set Screw Leads to Breaker Failure.

.2 EA-16-143, Enforcement Discretion for Tornado-Generated Missile Protection

Noncompliances Description Appendix A to 10 CFR 50, General Design Criteria for Nuclear Power Plants, Criterion 2, Design Bases for Protection Against Natural Phenomena, states, in part, that SSCs important to safety shall be designed to withstand the effects of natural phenomena, such as tornadoes. Criterion 4, Environmental and Dynamic Effects Design Basis, states, in part, that SSCs important to safety shall be appropriately protected against dynamic effects including missiles which may result from events and conditions outside the nuclear power unit.

As part of their response to external flood boundary degradation, the licensee performed a review of external hazard protection at the site, which included protection against tornado-generated missiles required by the current licensing basis for each unit. During the review in 2016, the licensee identified four different plant areas containing safety-related SSCs that could be susceptible to tornado missiles. See NRC Inspection Report 2016003 and Enforcement Discretion EA-16-143 for more details. During a recent review of the tornado missile protection walkdowns, the licensee discovered additional tornado missile vulnerabilities:

• Unit 1 cable trays in electrical equipment room

• Unit 1 conduits in turbine building

• Unit 2 conduit in controlled access area In each case, the licensee identified low-probability scenarios where one or more tornado-generated missiles could penetrate doors, walls, and other building features that were not fully qualified and damage equipment that was important to safety inside the affected rooms. Details about the date of discovery, affected SSCs, condition report numbers, compensatory actions taken by the licensee, notifications made to the NRC, and affected technical specification actions for each susceptible area are listed in 4 of this report.

Relevant Enforcement Discretion Policy On June 10, 2015, the NRC issued Enforcement Guidance Memorandum (EGM) 15-002, Enforcement Discretion for Tornado-Generated Missile Protection Noncompliance. (ML15111A269) On February 7, 2017, the NRC issued EGM 15-002, Revision 1 that incorporated lessons learned during the implementation of Revision 0 and allows licensees, on a case-by-case basis, to request an extension to the applicable enforcement discretion timeframe (ML16355A286). The EGM referenced a bounding generic risk analysis performed by the NRC staff that concluded that tornado missile vulnerabilities pose a low risk significance to operating nuclear plants. Because of this, the EGM described the conditions under which the NRC staff may exercise enforcement discretion for noncompliances with the current licensing basis for tornado-generated missile protection. Specifically, if the licensee could not meet the technical specification required actions within the required completion time, the EGM allows the staff to exercise enforcement discretion provided the licensee implements initial compensatory measures prior to the expiration of the time allowed by the limiting condition for operation. The compensatory actions should provide additional protection such that the likelihood of tornado missile effects are lessened. The EGM then requires the licensee to implement more comprehensive compensatory measures within approximately 60 days of issue discovery. The compensatory measures must remain in place until permanent repairs are completed, or until the NRC dispositions the non-compliance in accordance with a method acceptable to the NRC such that discretion is no longer needed. In addition, the issue must be entered into the licensees corrective action program. Because EGM 15-002 listed Arkansas Nuclear One as a Group A plant, enforcement discretion will expire on June 10, 2018. However, the EGM did not provide for enforcement discretion for any related underlying technical violations; the EGM specifically requires that any associated underlying technical violations be assessed through the enforcement process.

Licensee Actions For each of the examples listed above, the licensee declared the affected systems inoperable and complied with the applicable technical specification action statement(s),initiated a condition report, invoked the enforcement discretion guidance, implemented prompt compensatory measures, and returned the SSCs to an operable status. The licensee instituted compensatory measures intended to reduce the likelihood of tornado missile effects that included developing actions to be taken: if a tornado watch is predicted or issued for the area to ensure the operability or restore redundant equipment during severe weather; if a tornado warning is issued, including pre-staging operators in safe, strategic locations to promptly implement mitigative actions, and verifying the readiness of equipment and procedures dedicated to the Diverse and Flexible Coping Strategy (FLEX). Other specific compensatory actions for the individual areas are listed in Attachment 4.

NRC Actions The inspectors review addressed the material issues in the plant, and whether the compensatory measures were implemented in accordance with the guidance in EGM 15-002. The inspectors also evaluated whether the measures would function as intended and were properly controlled. The inspectors verified through inspection that the EGM 15-002 criteria were met in each case. Therefore, the staff determined that it was appropriate to exercise enforcement discretion and not take enforcement action for the technical specification requirements listed in Attachment 4 of this report, provided the noncompliances are resolved prior to expiration of the enforcement discretion (EA-16-143).

The inspectors did not fully review the underlying circumstances that resulted in the technical specification violations. As stated in EGM 15-002, violations of other requirements which may have contributed to the technical specification violations will be evaluated independently of EGM implementation. The inspectors will verify restoration of compliance and assess the underlying circumstances in a follow-up inspection tracked under Licensee Event Reports 05000313/2016-002-00 (ML16224A767),05000313/2016-003-00 (ML16293A66), 05000313/2016-003-01 (ML17163A27),05000368/2017-001-00 (ML17150A48), and any updates or additional licensee event reports that the licensee issues.

1R18 Plant Modifications

.1 Temporary Modifications

a. Inspection Scope

On April 10, 2017, the inspectors reviewed a temporary plant modification for the inoperable Unit 1 reactor protection system D power range excore nuclear instrument intended to bypass the power range input to the reactor protection system channel while keeping all other functions of the channel in-service, which is a SSC. This was necessary because the instrument was experiencing excessive noise.

The inspectors verified that the licensee had installed these temporary modifications in accordance with technically adequate design documents. The inspectors verified that this modification did not adversely impact the operability or availability of affected SSCs.

The inspectors reviewed design documentation and plant procedures affected by the modification to verify the licensee maintained configuration control.

These activities constituted completion of one sample of temporary modifications, as defined in Inspection Procedure 71111.18.

b. Findings

No findings were identified.

.2 Permanent Modifications

a. Inspection Scope

The inspectors reviewed two permanent plant modifications that affected risk-significant SSCs:

• April 27, 2017, Unit 2, replacement of both shutdown cooling heat exchangers due to shell corrosion

• May 21-22, 2016, Unit 2, common feedwater system installation The inspectors reviewed the design and implementation of the modifications. The inspectors verified that work activities involved in implementing the modifications did not adversely impact operator actions that may be required in response to an emergency or other unplanned event. The inspectors verified that post-modification testing was adequate to establish the operability or functionality of the SSCs as modified.

These activities constituted completion of two samples of permanent modifications, as defined in Inspection Procedure 71111.18.

b. Findings

No findings were identified.

1R19 Post-Maintenance Testing

a. Inspection Scope

The inspectors reviewed eight post-maintenance testing activities that affected risk-significant SSCs:

• April 6, 2017, Unit 2, circuit checks after control circuit modification to prevent spurious operation of reactor coolant system high point vent valves

• May 5, 2017, Unit 2, energized tests of non-vital 4160 Volt bus B

• May 12, 2017, Unit 2, circuit checks after control circuit modification to prevent spurious operation for shutdown cooling suction isolation valve 2CV-5038-1

• May 31, 2017, Unit 1, high pressure injection pump A breaker racking

• June 19, 2017, Unit 2, service water system full flow test after service water pipe replacements

• June 21, 2017, Unit 2, high pressure safety injection full flow test after multiple valve and piping replacements

• June 21, 2017, Unit 2, common feedwater pump P-805-A discharge pressure and flow test

• June 27, 2017, Unit 2, common feedwater system flow to the steam generator test The inspectors reviewed licensing- and design-basis documents for the SSCs and the maintenance and post-maintenance test procedures. The inspectors observed the performance of the post-maintenance tests to verify that the licensee performed the tests in accordance with approved procedures, satisfied the established acceptance criteria, and restored the operability of the affected SSCs.

These activities constituted completion of eight post-maintenance testing inspection samples, as defined in Inspection Procedure 71111.19.

b. Findings

Introduction.

The inspectors reviewed a Green self-revealing finding and associated non-cited violation of Unit 1 Technical Specification 3.5.2, Emergency Core Cooling System (ECCS) - Operating, for the failure to ensure the operability of the P36A High Pressure Injection (HPI) pump after reinstalling its feeder breaker during a unit outage.

A violation of Unit 1 Technical Specification 3.0.4 was also identified for making a mode change without meeting the requirements to do so. Following unit restart, the pump failed to start during a routine test, resulting in inoperability of one train of ECCS for a period of time greater than allowed by Unit 1 Technical Specifications.

Description.

On May 11, 2017, the licensee racked in the four Siemens 4160 Volt breakers associated with the HPI pumps in accordance with their breaker racking procedure in preparation for Unit 1 startup and return to full power. These breakers had been racked out to comply with station procedures to prevent cold over-pressure conditions for reactor coolant system components during the Unit 1 outage. There are four breakers associated with the three HPI pumps (P36A, P36B, and P36C), because the swing pump (P36B) can be aligned to either 4160 Volt engineered safeguards electrical bus (A3 or A4) through motor-operated disconnects. Operators did not test any of the breakers at the time they were racked in, and later started only one HPI pump (P36C) prior to reactor startup. Licensee Procedure COPD-001, Operations Expectations and Standards, Revision 074, provided the shift manager with latitude to waive the requirement to operate the P36A pump subsequent to the breaker rack in evolution.

On May 27, 2017, following Unit 1 restart, the P36A HPI pump failed to start. The licensee declared the P36A HPI pump and one ECCS train inoperable, documented the issue in Condition Report CR-ANO-1-2017-01764, and performed troubleshooting on the breaker. Licensee personnel determined that the breaker was not fully racked into the switchboard because the trip pedal was in a tripped condition and the roller nut was not free to roll. The licensee fully racked in the breaker, successfully started the P36A HPI pump, and declared the associated ECCS train operable. Subsequent to the P36A HPI pump failure to start, the remaining three HPI pump breakers were inspected to ensure they were properly racked in. Additionally, the licensee performed an extent of condition investigation on all other safety bus A3 Siemens breakers (no Siemens breakers are installed on safety bus A4) and found no issues.

Licensee Procedure OP-1107.001, Electrical System Operations, Exhibit C, Revision 113, provided options to either electrically or manually rack in 4160 Volt breakers. Due to the electric racking tools not being available or in disrepair, the licensee used the manual racking option in lieu of the electrical option in OP-1107.001 to rack in the four HPI pump Siemens 4160 Volt breakers on May 11, 2017. Inspectors noted that no special precautions had been taken to ensure this infrequently-used method was successful. Using the electric racking tool automatically stops when the breaker is fully racked in, while manually racking required a manual determination that it is correctly racked in.

When operators racked the breakers in, the plant was outside the mode of applicability for HPI pump operability as specified by technical specifications. But the inspectors determined that operators did not declare or track the HPI pumps as being inoperable when their feeder breakers were racked out. As a result, there was no tracking mechanism to ensure that operators would subsequently consider what actions were needed to declare the pumps operable after the breakers were racked in prior to entering the mode of applicability. The inspectors noted that the licensee routinely waived pump starts following breaker racking and concluded that the licensee failed to ensure that the associated mitigating equipment was operable prior to declaring the equipment operable.

Unit 1 Technical Specification 3.5.2, ECCS - Operating, states that two ECCS trains shall be operable in MODES 1 and 2, and MODE 3 with reactor coolant system (RCS)temperature >350°F. Unit 1 exceeded 350°F on May 14, 2017. Since the P36A HPI pump was inoperable because its breaker was not fully racked in at this time, one train of ECCS became inoperable. This technical specification required restoring the train to operable status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />, or exiting the mode of applicability. However, the licensee failed to meet the technical specification until May 19, 2017, when operators realign both HPI trains for equipment rotation and P36A was no longer required. As a result, one train of ECCS was inoperable from May 14, 2017, to May 19, 2017, which exceeded the operability requirements of Technical Specification 3.5.2, ECCS -

Operating. A violation of Unit 1 Technical Specification 3.0.4 was also identified for making a mode change without meeting the requirements to do so.

For corrective actions, the licensee revised Procedure OP-1107.001, Electrical System Operation, Revision 113, to include a requirement that the licensee electrical relay maintenance group verify the breaker is properly racked in when racking breakers manually. The licensee also revised COPD-001, Operations Expectations and Standards, Step 5.13.1C, to require obtaining approval from the operations manager or an assistant operations manager approval prior to waiving the requirement to start a load after racking in a breaker. The licensee has also taken steps to ensure availability of functioning breaker racking equipment such that the preferred method to rack breakers (electrically) is once again available.

Analysis.

The inspectors determined that the failure to verify that the P36A HPI pump was operable after racking its feeder breaker into the switchgear cubicle was a performance deficiency. The performance deficiency is more than minor because it was associated with the human performance attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The inspectors performed the initial significance determination for the performance deficiency using NRC Inspection Manual Chapter 0609, Appendix A, Exhibit 2, Mitigating Systems Screening Questions, dated June 19, 2012, and concluded that the finding required a detailed risk evaluation because it involved the loss of a single train of mitigating equipment for longer than the technical specification allowed outage time.

In the detailed risk evaluation, the analyst considered the exposure time of the performance deficiency to be from May 11 to May 27, 2017, since that was the time pump P36A would have failed to start. The analyst referred to NRC Inspection Manual Chapter 0609, Appendix G, Shutdown Operations Significance Determination Process, dated May 9, 2014, to qualitatively screen the time in which the plant was shut down with decay heat being removed by the shutdown cooling system. The analyst estimated all of the remaining exposure time of 307 hours0.00355 days <br />0.0853 hours <br />5.076058e-4 weeks <br />1.168135e-4 months <br /> using NRC Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, dated June 19, 2012, considering all of that time to be at-power risk. In this exposure time, 5 days were assumed with P-36A as the only pump in the train. The analyst modeled the degradation to be a failure to start basic event in the Arkansas Nuclear One, Unit 1 SPAR model, Version 8.50, and ran on SAPHIRE, Version 8.1.5. These assumptions yielded an estimate in the increase in core damage frequency of 4.4E-8 per year or of very low safety significance (Green). The dominant core damage sequences were losses of switchgear and small loss of coolant accidents which were mitigated by the feedwater systems and the ability to feed and bleed.

This finding has a cross-cutting aspect in the area of human performance, avoid complacency, because the licensee failed to ensure that individuals recognize and plan for the possibility of mistakes, latent issues, and inherent risk, even while expecting successful outcomes. Specifically, the licensee failed to verify that the pump was operable after its breaker was reinstalled, even though an infrequent method was employed. [H.12]

Enforcement.

Two violations were identified with this finding:

The Unit 1 Technical Specification 3.5.2, ECCS - Operating, requires that two ECCS trains shall be operable in Modes 1 and 2, and Mode 3 with RCS temperature >350°F.

Technical Specification 3.5.2, Condition A, requires that if one ECCS train is inoperable, then restore the ECCS train to operable status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. Technical Specification 3.5.2, Condition B, states that if the required action and associated completion time of Condition A is not met, then the plant shall be placed in Mode 3 in six hours and reduce RCS temperature less than 350°F within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. Contrary to the above, from May 14 to May 19, 2017, one train of ECCS was inoperable but the licensee failed to place Unit 1 in Mode 3 within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and reduce RCS temperature below 350°F within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> as required by Technical Specification 3.5.2, Condition B.

The Unit 1 Technical Specification 3.0.4 states, in part, that when a limiting condition for operation is not met, entry into a mode of applicability shall only be made when the associated actions to be entered permit continued operation in the mode for an unlimited period of time, after performance of a risk assessment and establishment of risk management actions, or when an allowance is stated in the individual specification.

Contrary to the above, for a Mode 3 entry on May 14, 2017, for a Mode 2 entry on May 17, 2017, and for a Mode 1 entry on May 17, 2017, Unit 1 entered into a mode of applicability when the associated actions to be entered did not permit continued operation in the mode for an unlimited period of time; without performance of a risk assessment and establishment of risk management actions; and without an allowance stated in the individual specification. Specifically, Unit 1 Technical Specification 3.5.2, ECCS -

Operating did not permit continued operation in the mode for an unlimited period of time, the licensee did not perform a risk assessment or establish risk management actions prior to entering the modes of applicability, and there was no allowance stated in the individual specification. The licensee did identify in their apparent cause assessment that an opportunity was missed to discover this issue during a mode of non-applicability.

Because this finding was of very low safety significance (Green), and was entered into the licensees corrective action program as CR-ANO-1-2017-01764, this violation is being treated as a non-cited violation, consistent with Section 2.3.2.a of the NRC Enforcement Policy: NCV 05000313/2017002-03, Failure to Comply with ECCS Technical Specifications.

1R20 Refueling and Other Outage Activities

a. Inspection Scope

During the Unit 1 unplanned outage between April 26 and May 22, 2017, and the Unit 2 refueling outage that continued throughout the inspection period, the inspectors evaluated the licensees outage activities. The inspectors verified that the licensee considered risk in developing and implementing the outage plan, appropriately managed personnel fatigue, and developed mitigation strategies for losses of key safety functions.

During this inspection period, this verification included the following:

• Review and verification of the licensees fatigue management activities

• Monitoring of cool-down activities

• Verification that the licensee maintained defense-in-depth during outage activities

• Observation and review of reduced-inventory activities

• Observation and review of fuel handling activities

• Monitoring of heat-up and startup activities The inspectors observed the licensees projects to replace the Unit 2 shutdown cooling heat exchangers and common feedwater system for Unit 2. The inspectors observed methods of controlling hot work, risk assessment and mitigation, lifting activities, testing, inspections, alignment, problem identification and resolution, and restoration. The other inspection samples for these activities are documented in this inspection report.

These activities constituted completion of two refueling and other outage samples (one refueling and one other), as defined in Inspection Procedure 71111.20.

b. Findings

No findings were identified.

1R22 Surveillance Testing

a. Inspection Scope

The inspectors observed seven risk-significant surveillance tests and reviewed test results to verify that these tests adequately demonstrated that the structures, systems, and components (SSCs) were capable of performing their safety functions:

In-service tests:

• May 8, 2017, Unit 1, motor driven emergency feedwater pump flow to steam generators during shutdown

• June 2, 2017, Unit 2, steam generator snubber testing Containment isolation valve surveillance tests:

• June 26, 2017, Unit 2, local leak rate test on the containment equipment hatch, including the containment test isolation valve 2-IA-200 Reactor coolant system leak detection tests:

• June 27, 2017, Unit 1, reactor coolant system mass balance calculation, containment sump level trending, and containment radiation monitoring following increase in reactor coolant system pump seal leakage Other surveillance tests:

• May 24, 2017, Unit 2, emergency diesel generator B operational test

• June 1, 2017, Unit 2, 2A1 bus offsite power transfer test

• June 19, 2017, Unit 2, battery 2D-11 discharge test The inspectors verified that these tests met technical specification requirements, that the licensee performed the tests in accordance with their procedures, and that the results of the test satisfied appropriate acceptance criteria. The inspectors verified that the licensee restored the operability of the affected SSCs following testing.

These activities constituted completion of seven surveillance testing inspection samples, as defined in Inspection Procedure 71111.22.

b. Findings

No findings were identified.

RADIATION SAFETY

Cornerstones: Public Radiation Safety and Occupational Radiation Safety

2RS1 Radiological Hazard Assessment and Exposure Controls

a. Inspection Scope

The inspectors evaluated the licensees performance in assessing the radiological hazards in the workplace associated with licensed activities. The inspectors assessed the licensees implementation of appropriate radiation monitoring and exposure control measures for both individual and collective exposures. During the inspection, the inspectors interviewed licensee personnel, walked down various areas in the plant, performed independent radiation dose rate measurements, and observed postings and physical controls. The inspectors reviewed licensee performance in the following areas:

• Radiological hazard assessment, including a review of the plants radiological source terms and associated radiological hazards. The inspectors also reviewed the licensees radiological survey program to determine whether radiological hazards were properly identified for routine and non-routine activities and assessed for changes in plant operations.

• Instructions to workers including radiation work permit requirements and restrictions, actions for electronic dosimeter alarms, changing radiological condition, and radioactive material container labeling.

• Contamination and radioactive material control, including release of potentially contaminated material from the radiologically controlled area, radiological survey performance, radiation instrument sensitivities, material control and release criteria, and control and accountability of sealed radioactive sources.

• Radiological hazards control and work coverage. During walk downs of the facility and job performance observations, the inspectors evaluated ambient radiological conditions, radiological postings, adequacy of radiological controls, radiation protection job coverage, and contamination controls. The inspectors also evaluated dosimetry selection and placement as well as the use of dosimetry in areas with significant dose rate gradients. The inspectors examined the licensees controls for items stored in the spent fuel pool and evaluated airborne radioactivity controls and monitoring.

• High radiation area and very high radiation area controls. During plant walk downs, the inspectors verified the adequacy of posting and physical controls, including areas of the plant with the potential to become risk-significant high radiation areas.

• Radiation worker performance and radiation protection technician proficiency with respect to radiation protection work requirements. The inspectors determined if workers were aware of significant radiological conditions in their workplace, radiation work permit controls/limits in place, and electronic dosimeter dose and dose rate set points. The inspectors observed radiation protection technician job performance, including the performance of radiation surveys.

• Problem identification and resolution for radiological hazard assessment and exposure controls. The inspectors reviewed audits, self-assessments, and corrective action program documents to verify problems were being identified and properly addressed for resolution.

These activities constituted completion of the seven required samples of radiological hazard assessment and exposure control program, as defined in Inspection Procedure 71124.01.

b. Findings

No findings were identified.

2RS3 In-plant Airborne Radioactivity Control and Mitigation

a. Inspection Scope

The inspectors evaluated whether the licensee controlled in-plant airborne radioactivity concentrations consistent with ALARA principles and that the use of respiratory protection devices did not pose an undue risk to the wearer. During the inspection, the inspectors interviewed licensee personnel, walked down various areas in the plant, and reviewed licensee performance in the following areas:

• Engineering controls, including the use of permanent and temporary ventilation systems to control airborne radioactivity. The inspectors evaluated installed ventilation systems, including review of procedural guidance, verification the systems were used during high-risk activities, and verification of airflow capacity, flow path, and filter/charcoal unit efficiencies. The inspectors also reviewed the use of temporary ventilation systems used to support work in contaminated areas such as high efficiency particulate air (HEPA)/charcoal negative pressure units.

Additionally, the inspectors evaluated the licensees airborne monitoring protocols, including verification that alarms and set points were appropriate.

• Use of respiratory protection devices, including an evaluation of the licensees respiratory protection program for use, storage, maintenance, and quality assurance of National Institute for Occupational Safety and Health (NIOSH)certified equipment, air quality and quantity for supplied-air devices and self-contained breathing apparatus (SCBA) bottles, qualification and training of personnel, and user performance.

• Self-contained breathing apparatus for emergency use, including the licensees capability for refilling and transporting SCBA bottles to and from the control room and operations support center during emergency conditions, hydrostatic testing of SCBA bottles, status of SCBA staged and ready for use in the plant including vision correction, mask sizes, etc., SCBA surveillance and maintenance records, and personnel qualification, training, and readiness.

• Problem identification and resolution for airborne radioactivity control and mitigation. The inspectors reviewed audits, self-assessments, and corrective action documents to verify problems were being identified and properly addressed for resolution.

These activities constituted completion of the four required samples of in-plant airborne radioactivity control and mitigation program, as defined in Inspection Procedure 71124.03.

b. Findings

No findings were identified.

OTHER ACTIVITIES

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity, Emergency Preparedness, Public Radiation Safety, Occupational Radiation Safety, and Security

4OA1 Performance Indicator Verification

.1 Safety System Functional Failures (MS05)

a. Inspection Scope

For the period of April 1, 2016, through March 31, 2017, the inspectors reviewed Licensee Event Reports (LERs), maintenance rule evaluations, and other records that could indicate whether safety system functional failures had occurred. The inspectors used definitions and guidance contained in Nuclear Energy Institute Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7, and NUREG-1022, Event Reporting Guidelines: 10 CFR 50.72 and 50.73, Revision 3, to determine the accuracy of the data reported.

These activities constituted verification of the safety system functional failures performance indicator for Units 1 and 2, as defined in Inspection Procedure 71151.

b. Findings

No findings were identified.

.2 Reactor Coolant System Specific Activity (BI01)

a. Inspection Scope

The inspectors reviewed the licensees reactor coolant system chemistry sample analyses for the period of April 1, 2016, through March 31, 2017, to verify the accuracy and completeness of the reported data. The inspectors used definitions and guidance contained in Nuclear Energy Institute Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7, to determine the accuracy of the reported data.

These activities constituted verification of the reactor coolant system specific activity performance indicator for Units 1 and 2, as defined in Inspection Procedure 71151.

b. Findings

No findings were identified.

.3 Reactor Coolant System Identified Leakage (BI02)

a. Inspection Scope

The inspectors reviewed the licensees records of reactor coolant system identified leakage for the period of April 1, 2016 through March 31, 2017 to verify the accuracy and completeness of the reported data. The inspectors used definitions and guidance contained in Nuclear Energy Institute Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7, to determine the accuracy of the reported data.

These activities constituted verification of the reactor coolant system leakage performance indicator for Units 1 and 2, as defined in Inspection Procedure 71151.

b. Findings

No findings were identified.

.4 Occupational Exposure Control Effectiveness (OR01)

a. Inspection Scope

The inspectors reviewed corrective action program records documenting unplanned exposures and losses of radiological control over locked high radiation areas and very high radiation areas during the period of October 1, 2016, to March 30, 2017. The inspectors reviewed a sample of radiologically controlled area exit transactions showing exposures greater than 100 millirem. The inspectors used definitions and guidance contained in Nuclear Energy Institute Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7, to determine the accuracy of the reported data.

These activities constituted verification of the occupational exposure control effectiveness performance indicator as defined in Inspection Procedure 71151.

b. Findings

No findings were identified.

.5 Radiological Effluent Technical Specifications (RETS)/Offsite Dose Calculation Manual

(ODCM) Radiological Effluent Occurrences (PR01)

a. Inspection Scope

The inspectors reviewed corrective action program records for liquid and/or gaseous effluent releases, leaks, and spills that occurred between October 1, 2016, and March 30, 2017, including those reported to the NRC to verify the performance indicator data. The inspectors used definitions and guidance contained in Nuclear Energy Institute Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7, to determine the accuracy of the reported data.

These activities constituted verification of the radiological effluent technical specifications (RETS)/offsite dose calculation manual (ODCM) radiological effluent occurrences performance indicator as defined in Inspection Procedure 71151.

b. Findings

No findings were identified.

4OA2 Problem Identification and Resolution

.1 Routine Review

a. Inspection Scope

Throughout the inspection period, the inspectors performed daily reviews of items entered into the licensees corrective action program and periodically attended the licensees condition report screening meetings. The inspectors verified that licensee personnel were identifying problems at an appropriate threshold and entering these problems into the corrective action program for resolution. The inspectors verified that the licensee developed and implemented corrective actions commensurate with the significance of the problems identified. The inspectors also reviewed the licensees problem identification and resolution activities during the performance of the other inspection activities documented in this report.

b. Findings

No findings were identified.

.2 Annual Follow-up of Selected Issues

a. Inspection Scope

The inspectors selected an issue for an in-depth follow-up:

• On May 31, 2017, Units 1 and 2, licensee response to operating experience regarding valve stem to disk separation for Anchor Darling double disc gate valves The inspectors assessed the licensees problem identification threshold, cause analyses, extent of condition reviews and compensatory actions. The inspectors verified that the licensee appropriately prioritized the taken and planned corrective actions and that these actions were adequate to correct the condition.

These activities constituted completion of one annual follow-up sample as defined in Inspection Procedure 71152.

b. Findings

No findings were identified.

4OA3 Follow-up of Events and Notices of Enforcement Discretion

.1 High Winds Damage Offsite Power Transmission Lines Causing Unit 1 Reactor Trip

On April 26, 2017, high winds damaged offsite power transmission lines, which caused a Unit 1 main generator trip and reactor trip. After the generator trip and reactor trip, the site autotransformer locked out, which caused a loss of power to the connected startup 1 transformer. The autotransformer is located in the switchyard, and it receives power from both 500 KV and 161 KV ring buses and provides power to startup transformer 1 (Unit 1) and startup transformer 3 (Unit 2). By design, loss of power to Unit 1 non-vital buses caused a fast bus transfer to startup transformer 1, which was unsuccessful due to loss of feed from the autotransformer, so a slow transfer to startup transformer 2 occurred. This transformer powers one train of plant loads in each unit. For Unit 1, the other train was powered by its emergency diesel generator. The operators cooled the unit down on natural circulation using emergency feedwater because the reactor coolant pumps had lost power. All onsite equipment important to safety functioned as designed, although one reactor coolant pump seal developed unexpected leakage and was subsequently replaced prior to unit restart.

At the time of the event, Unit 2 was shut down for refueling and being powered from startup transformer 2. The startup transformer 2 momentarily lost power long enough for both emergency diesel generators to automatically start on low bus voltage. Power from startup transformer 2 was restored before the diesels powered the buses, so the startup transformer continued to supply power as designed. The core was fully offloaded into the spent fuel pool at the time of the event. Although the spent fuel pool cooling pumps tripped due to the momentary loss of power, operators restarted the pumps within ten minutes.

Inspectors responded to the control room, observed implementation of emergency and abnormal operating procedures, verified emergency action levels, verified the status of safety equipment and barriers, and observed command and control functions.

Inspectors also observed portions of the plant cooldown on natural circulation. Prior to startup, inspectors reviewed equipment and plant response after the trip, and verified that the licensee had appropriately resolved plant issues prior to restart.

.2 Turbine Governor Valve Oscillations Cause Turbine Trip on Unit 1

On May 18, 2017, operators observed the Unit 1 turbine governor valve number 2 oscillating. The operators manually tripped the turbine from approximately 25 percent nuclear power due to the oscillations. The reactor, as designed, did not trip as steam was automatically redirected directly to the main condenser via the steam dump system.

The inspectors responded to the control room shortly after the turbine trip and observed operator actions. After the turbine trip, operators placed the turbine bypass control valves in service and reduced reactor power to approximately 14 percent. The licensee discovered that the Linear Voltage Differential Transmitter (LVDT) for governor valve number 2, used to provide position indication for the valve to the control circuit, was loose, and caused the oscillations. The licensee secured LVDT and placed the turbine back into service.

.3 (Closed) Licensee Event Report 05000313/2016-001-00, Non-Functional External

Penetration Flood Seals On March 19, 2016, the licensee discovered two flood seals that separated the Unit 1 turbine building from the auxiliary building had been constructed with seal material not qualified for flood protection. The licensee had constructed the seal with lath and plaster, but the flooding design basis document required the seal materials to be grout and cellular concrete. In response, the licensee submitted Licensee Event Report 05000313/2016-001-00 on May 18, 2016 (ML16139A795). The licensee entered the issue into their corrective action program as Condition Report CR-ANO-1-2016-0985.

As part of their compensatory actions, on March 23, 2016, the licensee anchored carbon steel forms to the floor around the penetration seals and staged sealing materials nearby as a contingency for potential external flooding. The licensee restored compliance on December 23, 2016, when they replaced the two flood seals with grout and high density silicone elastomer. To determine the potential safety significance of the past nonconformance, the licensee tested the original seal materials and found that the seals would allow less than one gallon per minute of leakage into the auxiliary building during a design basis flood. The Unit 1 auxiliary building sump pumps were capable of removing 150 gallons per minute, which significantly exceeds potential leakage from the nonconforming seals.

Inspectors concluded that the failure to install qualified flood seals is a performance deficiency. This performance deficiency is minor because, although the original material used was not qualified for flood protection, the auxiliary building sump pumps could have mitigated the leakage with significant margin, and therefore the performance deficiency would not have affected safety-related equipment. This failure to comply with flood protection design basis requirements constitutes a minor violation that is not subject to enforcement action in accordance with the NRCs Enforcement Policy. This licensee event report is closed.

These activities constituted completion of three event follow-up samples, as defined in Inspection Procedure 71153.

4OA6 Meetings, Including Exit

Exit Meeting Summary

On April 14, 2017, the inspectors presented the radiation safety inspection results to Mr. R. Anderson, Site Vice President, and other members of the licensee staff. The licensee acknowledged the issues presented. The licensee confirmed that any proprietary information reviewed by the inspectors had been returned or destroyed.

On April 17, 2017, the inspectors presented the inservice inspection results to Mr. R. Anderson, Site Vice President, and other members of the licensee staff. On May 11, 2017, the inspectors presented updated inspection results based on additional information provided by the licensee to Mr. B. Daiber, Engineering Programs and Components Manager, and other members of the licensee staff. The licensee acknowledged the issues presented. The licensee confirmed that any proprietary information reviewed by the inspectors had been returned or destroyed.

On July 10, 2017, the inspectors presented the resident inspector inspection results to Mr. R. Anderson, Site Vice President, and other members of the licensee staff. The licensee acknowledged the issues presented. The licensee confirmed that any proprietary information reviewed by the inspectors had been returned or destroyed.

4OA7 Licensee-Identified Violations

The following violation of very low safety significance (Green) was identified by the licensee and is a violation of NRC requirements which meets the criteria of the NRC Enforcement Policy for being dispositioned as a non-cited violation.

Title 10 CFR 50.55a(g)4, Inservice Inspection Standards Requirement for Operating Plants, states in part, Throughout the service life of a pressurized water-cooled nuclear power facility, components that are classified as ASME Code Class 1, Class 2, and Class 3 must meet the requirements set forth in Section XI of the ASME Code. The ASME Section XI, Article IWA-2610, requires that all welds and components subject to a surface or volumetric examination be included in the licensees inservice inspection program. This includes identifying system supports in the inservice inspection plan, per ASME Section XI, Article IWA-1310. Contrary to the above, prior to March 9, 2017, the licensee did not ensure that all welds and components subject to a surface or volumetric examination were included in the licensees inservice inspection. Specifically, the licensee did not apply the applicable inservice inspection requirements for surface or volumetric examination to all portions of the Unit 2 emergency feedwater system within the system ASME Code Class 3 boundary. The licensee identified that they failed to include the emergency feed pump supports in their inservice inspection program.

The licensee entered this issue into their corrective action program as Condition Report CR-ANO-2-2016-01023 and reasonably determined the emergency feedwater system remained operable. The licensee restored compliance by inspecting the supports, with no degradation identified, and entering the emergency feedwater pump supports into the ASME Section XI program. The finding was of very low safety significance (Green) because the finding did not represent an actual loss of safety function of a system or train and did not result in the loss of a single train for greater than technical specification allowed outage time. This issue was entered into the licensees corrective action program as Condition Report CR-ANO-2-2016-01023.

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

R. Anderson, Site Vice President

J. Beldin, Engineer

L. Blocker, Nuclear Independent Oversight Manager

P. Butler, Design and Program Engineering Manager

P. Crosby, Engineering Programs and Components Supervisor

B. Daiber, Engineering Programs and Components Manager

J. DeVault, Welding Engineer

G. Doran, Specialist, Radiation Protection

P. Ellison, Superintendent, Radiation Protection

T. Evans, General Manager, Plant Operations

M. Fields, Assistant Operations Manager

M. Gibson, ALARA Supervisor, Radiation Protection

G. Hudnall, Corrective Action Program Manager

G. Kilpatrick, Training Manager

R. Lona, Specialist, Radiation Protection

B. Lynch, Manager, Radiation Protection

P. McCray, Site Projects Senior Manager

R. McGaha, NDE Level III Specialist IV

S. Morris, Chemistry Manager

N. Mosher, Licensing Specialist, Regulatory Assurance

R. Penfield, Regulatory Assurance Director

S. Pyle, Regulatory Assurance Manager

M. Skartvedt, System Engineering Manager

S. Taylor, Engineer

D. Varvil, Welding Engineer

D. Vogt, Senior Operations Manager

L. Webb, Dosimetry and RP Support, Radiation Protection

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened and Closed

Failure to Follow Fire Protection Program Procedures

05000368/2017002-01 NCV (Section 1R05)

Failure to Install Set Screw Leads to Breaker Failure

05000368/2017002-02 NCV (Section 1R15)

Failure to Comply with ECCS Technical Specifications

05000313/2017002-03 NCV (Section 1R19)

Attachment 1