IR 05000498/2015002

IR 05000498/2015002, 05000499/2015002; on 04/05/2015 - 07/04/2015; South Texas Project Electric Generating Station, Units 1 and 2, Adverse Weather Protection, and Problem Identification and Resolution

ML15230A068
Person / Time
Site:	South Texas
Issue date:	08/14/2015
From:	Nick Taylor NRC/RGN-IV/DRP/RPB-B
To:	Koehl D South Texas
Taylor N
References
IR 2015002
Download: ML15230A068 (61)

Text

UNITED STATES ust 14, 2015

SUBJECT:

SOUTH TEXAS PROJECT ELECTRIC GENERATING STATION -

NRC INTEGRATED INSPECTION REPORT 05000498/2015002 AND 05000499/2015002

Dear Mr. Koehl:

On July 4, 2015, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your South Texas Project Electric Generating Station, Units 1 and 2, facility. On July 16, 2015, the NRC inspectors discussed the results of this inspection with Mr. L. Peter, General Manager of Projects, and other members of your staff. Inspectors documented the results of this inspection in the enclosed inspection report.

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

Both 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 this violation as non-cited violation (NCV) 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, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC resident inspector at the South Texas Project Electric Generating Station, Units 1 and 2, facility.

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 Regional Administrator, Region IV; and the NRC resident inspector at the South Texas Project Electric Generating Station, Units 1 and 2, facility. 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 available electronically for public inspection in the NRCs Public Document Room or from the Publicly Available Records (PARS) component of the NRC's Agencywide Documents Access and Management System (ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,

/RA/

Nick Taylor, Branch Chief Project Branch B Division of Reactor Projects Docket Nos.: 50-498 and 50-499 License Nos.: NPF-76 and NPF-80

Enclosure:

Inspection Report 05000498/2015002 and 05000499/2015002 w/Attachment 1: Supplemental Information w/Attachment 2: Document Request for O

REGION IV==

Docket: 05000498, 05000499 License: NPF-76, NPF-80 Report: 05000498/2015002 and 05000499/2015002 Licensee: STP Nuclear Operating Company Facility: South Texas Project Electric Generating Station, Units 1 and 2 Location: FM 521 - 8 miles west of Wadsworth Wadsworth, Texas 77483 Dates: April 5 through July 4, 2015 Inspectors: A. Sanchez, Senior Resident Inspector N. Hernandez, Resident Inspector B. Baca, Project Engineer/Health Physicist S. Janicki, Project Engineer R. Kopriva, Senior Reactor Inspector J. ODonnell, Health Physicist C. Stott, Reactor Inspector Approved Nick Taylor By: Branch Chief, Project Branch B Division of Reactor Projects-1- Enclosure

SUMMARY

IR 05000498/2015002, 05000499/2015002; 04/05/2015 - 07/04/2015; South Texas Project

Electric Generating Station, Units 1 and 2, Adverse Weather Protection, and Problem Identification and Resolution The inspection activities described in this report were performed between April 5 and July 4, 2015, by the resident inspectors at the South Texas Project and inspectors from the NRCs Region IV office. Two findings of very low safety significance (Green) are documented in this report. Both 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 (Green, White,

Yellow, or Red), which is determined using Inspection Manual Chapter 0609, Significance Determination Process. Their cross-cutting aspects are determined using Inspection Manual Chapter 0310, Aspects within the Cross-Cutting Areas. 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.

Cornerstone: Initiating Events

Green.

Inspectors identified a non-cited violation of Technical Specification 6.8.1.a for failure to follow Procedure 0PGP03-ZV-0002, Hurricane Plan, Revision 7. Specifically, on June 15 through 16, 2015, the licensee failed to remove loose trash and materials inside the protected area to protect against potential missile hazards in accordance with Data Sheet 3 of Procedure 0PGP03-ZV-0002 in preparation for Tropical Storm Bill. The licensee has entered this issue into the corrective action program as Condition Report 15-17110.

The failure of the licensee to address and control potential missile hazards on site, on the Unit 1 mechanical auxiliary building roof, turbine deck, and around standby transformer 1 was a performance deficiency. Specifically, on June 16, 2015, the licensee failed to follow Data Sheet 3 of Procedure 0PGP03-ZV-0002, Hurricane Plan, Revision 7, to adequately secure potential missile hazards in preparation for Tropical Storm Bill. The performance deficiency was determined to be more than minor because it was associated with the protection against external factor attribute and adversely affected the Initiating Event Cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during power operations. Using NRC Inspection Manual 0609,

Appendix A, Exhibit 1, Initiating Events Screening Questions, the inspectors determined the finding was of very low safety significance (Green) because it did not cause a reactor trip and the loss of mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition. The inspectors determined the finding had a cross-cutting aspect in the area of problem identification and resolution associated with resolution. Specifically, the licensee failed to take effective corrective action from previous NRC-identified instances in the past where the licensee had loose material and debris that could become a missile hazards during a severe weather event [P.3]. (Section 1R01)

Cornerstone: Mitigating Systems

Green.

The inspectors documented a self-revealing, non-cited violation of 10 CFR Part 50,

Appendix B, Criterion III, Design Control, for the failure to have adequate measures for the selection and review for suitability of application of parts that are essential to the safety-related functions of structures, systems and components. Specifically, the licensee failed to properly inspect and test essential chiller condenser purge check valves during the stations commercial dedication process to ensure proper function in their safety-related application. The licensee has entered the issue into the corrective action program as Condition Report 15-4990 and has implemented corrective actions to the technical evaluation that will adequately measure and test the purge check valve in the future.

The failure to properly inspect and test essential chiller condenser check valves during the stations commercial dedication process to ensure proper function in the safety-related application was a performance deficiency. This performance deficiency is more than minor because it adversely affected the equipment performance attribute of the Mitigating Systems Cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, on January 18, 2015, March 5, 2015, and March 21, 2015, the inadequately dedicated purge check valves resulted in a trip of the essential chiller, rendering the train inoperable and challenging plant operations. Using NRC Inspection Manual 0609, Appendix A, Exhibit 2,

Mitigating Systems Screening Questions, the inspectors determined the finding was of very low safety significance (Green) because it did not affect the design or qualification of the system, did not result in a loss of system function, did not represent a loss of function of a single train for greater than its technical specifications allowed outage time, and did not cause the loss of function of one or more non-technical specification trains of equipment designated as high safety-significance. The inspectors determined that the finding did not have a cross-cutting aspect because the main contributor to the cause of the performance deficiency occurred in 1993. (Section 4OA2)

=

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 period at 100 percent and remained there for the entire inspection period.

Unit 2 began the period in Mode 6 for Refueling Outage 2RE17. On May 15, 2015, the reactor achieved 100 percent power and remained there for the rest of the inspection period.

REPORT DETAILS

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R01 Adverse Weather Protection

Readiness for Impending Adverse Weather Conditions

a. Inspection Scope

On May 27, 2015, 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 for a tornado watch on May 25 and May 26, 2015.

The inspectors evaluated operator staffing and accessibility of controls and indications for those systems required to control the plant. The inspectors also evaluated the licensees control of planned work for those safety-related systems.

On June 17, 2015, 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 tropical storms and hurricanes, and the licensees implementation of these procedures for Tropical Storm Bill on June 15 through June 17. The inspectors evaluated operator staffing and accessibility of controls and indications for those systems required to control the plant. The inspectors also evaluated the licensees control of planned work for those safety-related systems.

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

b. Findings

Introduction.

Inspectors identified a Green, non-cited violation of Technical Specification 6.8.1.a for failure to follow Procedure 0PGP03-ZV-0002, Hurricane Plan, Revision 7. Specifically, on June 15 through 16, 2015, the licensee failed to remove loose trash and materials inside the protected area to protect against potential missile hazards in accordance with Data Sheet 3 of Procedure 0PGP03-ZV-0002, in preparation for Tropical Storm Bill.

Description.

On June 13, 2015, the licensee became aware of a tropical system that would likely impact the plant the week of June 15 and began to prepare for the storm.

The licensee entered Procedure 0PGP03-ZV-0002, Hurricane Plan, Revision 7, Data Sheet 3. A punch list of items and areas that needed attention was put together and was completed by the end of dayshift Monday, June 15. The tropical system developed into Tropical Storm Bill. Tropical Storm Bill was scheduled to impact the site the morning of June 16, but slowed and did not make landfall until the afternoon. This gave the inspectors another opportunity to walk down the site after the licensee had completed their storm preparations. The inspectors toured the station, paying special attention to the protected area and in areas of high work activity.

The inspectors identified numerous potential missile hazards, especially in and around Unit 1. Some of these issues identified included: 1) many unsecured items on the mechanical auxiliary building roof, such as empty 5-gallon buckets, trash can lids, rope and torn concealment tarps, which pertained to ongoing FLEX modification work; 2) large floor mat and boxed sheet metal ventilation ducting on the turbine deck above the main and standby transformer 1; and 3) two flatbed trucks with mops, brooms, and various small pieces of wood, rope, and cables near the standby transformer 1. Standby transformer 1 supplies Unit 1 with offsite power for engineered safety feature loads, and can be also aligned to supply a train of Unit 2 engineered safety feature loads.

The inspectors informed the control room of the observations and the licensee promptly took action to secure or remove the potential missile hazards. Tropical Storm Bill made landfall and directly impacted the site on the afternoon of June 16. Both units remained at 100 percent power, and wind speeds on site were approximately 40 miles per hour average with gusts up to 60 miles per hour. The high winds associated with this storm were forceful enough to cause damage to several non-safety related structures on site.

On several occasions in the last 2 years, the inspectors identified areas of the plant that were not prepared for severe weather after the licensee had completed their storm preparations. On each occasion, the licensee initiated condition reports and addressed the items pointed out by the inspectors. However, the corrective actions to date only addressed that specific area and failed to evaluate and determine if there was a larger issue with the process or how procedures and site managements expectations were being implemented. This most recent issue was placed into the corrective action program as Condition Report 15-17110.

Analysis.

The failure of the licensee to address and control potential missile hazards on site, on the Unit 1 mechanical auxiliary building roof, turbine deck, and around standby transformer 1 was a performance deficiency. Specifically, on June 16, 2015, the licensee failed to follow Data Sheet 3 of Procedure 0PGP03-ZV-0002, Hurricane Plan, Revision 7, to adequately secure potential missile hazards in preparation for Tropical Storm Bill. The performance deficiency was determined to be more than minor because it was associated with the protection against external factor attribute and adversely affected the Initiating Events Cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during power operations.

Using NRC Inspection Manual 0609, Appendix A, Exhibit 1, Initiating Events Screening Questions, the inspectors determined the finding was of very low safety significance (Green) because it did not cause a reactor trip and the loss of mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition. The inspectors determined the finding had a cross-cutting aspect in the area of problem identification and resolution associated with resolution. Specifically, the licensee failed to take effective corrective action from previous NRC-identified instances in the past where the licensee had loose material and debris that could become a missile hazards during a severe weather event. [P.3].

Enforcement.

Technical Specification 6.8.1.a requires, in part, written procedures shall be established, implemented, and maintained covering applicable procedures in Regulatory Guide 1.33, Revision 2, Appendix A, February 1978. Regulatory Guide 1.33, Appendix A, Section 6.w, Acts of Nature, requires procedure for acts of nature.

Contrary to the above, on June 16, 2015, the licensee failed to properly implement Procedure 0PGP03-ZV-0002, Hurricane Plan, Revision 7, to remove loose trash and materials inside the protected area to protect against potential missile hazards. The licensee promptly addressed all items identified by the inspectors, and as a result, there was no plant damage identified following the tropical storm. The violation was entered into the licensees corrective action program as Condition Report 15-17110. This violation is being treated as a non-cited violation consistent with Section 2.3.2.a of the NRC Enforcement Policy: NCV 05000498/2015002-01; 05000499/2015002-01, Failure to Follow Hurricane Plan Procedure to Secure Missile Hazards During Tropical Storm Bill.

1R04 Equipment Alignment

Partial Walkdown

a. Inspection Scope

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

• June 23, 2015, Unit 2, train B, 120 volts alternating current inverter and 125 volts direct current battery during 10-year rebuild of the train D, 120 volts alternating current inverter

• June 24, 2015, Unit 1, feedwater booster pumps 11 and 13 during replacement of the feedwater booster pump 12 auxiliary lube oil pump 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 and trains were correctly aligned for the existing plant configuration.

These activities constituted two 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 four plant areas important to safety:

• June 9, 2015, Unit 2, electrical auxiliary building, Fire Area 03 and Fire Zone Z043

• July 2, 2015, Unit 1, technical support center diesel room, Fire Area 99 and Fire Zone Z912

• July 3, 2015, Unit 2, electrical auxiliary building, Fire Area 03 and Fire Zone Z045

• July 3, 2015, Unit 2, electrical auxiliary building, Fire Area 01 and Fire Zone Z032 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 four quarterly inspection samples, as defined in Inspection Procedure 71111.05.

b. Findings

No findings were identified.

1R07 Heat Sink Performance

a. Inspection Scope

On March 29 and June 23, 2015, the inspectors completed an inspection of the readiness and availability of risk-significant heat exchangers. For the Unit 2 component cooling water heat exchangers, the inspectors:

(1) observed the setup of the performance test,

(2) reviewed the data from a performance test, and

(3) verified the licensee used the industry standard periodic maintenance method outlined in EPRI NP-7552. Additionally, the inspectors walked down the heat exchanger to observe its performance and material condition and verified that the heat exchanger was correctly categorized under the Maintenance Rule and was receiving the required maintenance.

These activities constitute completion of one heat sink performance annual review sample, as defined in Inspection Procedure 71111.07.

b. Findings

No findings were identified.

1R08 Inservice Inspection Activities

The activities described in subsections 1 through 4 below constitute completion of one inservice inspection sample, as defined in Inspection Procedure 71111.08.

.1 Non-destructive Examination (NDE) Activities and Welding Activities

a. Inspection Scope

The inspectors directly observed the following nondestructive examinations:

SYSTEM WELD IDENTIFICATION EXAMINATION TYPE Main Steam Steam Generator Steam Outlet Power Penetrant Examination Operated Relief Valve (ORC), Valve Stem Shank.

Residual Heat Residual Heat Removal Valve RH- Penetrant Examination Removal 0032A - pipe end weld preps after System machining.

Residual Heat Residual Heat Removal check valve Penetrant Examination Removal RH-0032A. Weld # FW0001 (Outlet).

System Final PT after welding.

Residual Heat Residual Heat Removal check valve Penetrant Examination Removal RH-0032A. Weld # FW0002 (Inlet).

System Final PT after welding.

Residual Heat Residual heat removal check valve RH- Radiograph Removal 0032A. Record # FW0002, Dated Examination System 04/15/2015.

Safety Injection FLEX Modification tie-in to the Safety Radiograph injection system. Weld # HFW0083 Examination (Train A), HFW0087 (Train A).

Reactor Coolant Reactor coolant system pipe to pipe Ultrasonic Examination System weld. Component ID # 12 inch - RC-2312-BB1 Weld 6.

Reactor Coolant Reactor coolant system pipe to pipe Ultrasonic Examination System weld. Component ID # 12 inch - RC-2312-BB1 Weld 7.

SYSTEM WELD IDENTIFICATION EXAMINATION TYPE Reactor Coolant Reactor coolant system pipe to pipe Ultrasonic Examination System weld. Component ID # 12 inch - RC-2312-BB1 Weld 10.

Reactor Coolant Weld Number RPV2-N1DSE, Outlet Ultrasonic Examination System Nozzle 158°. Nozzle to Safe End Weld (DM).

Reactor Coolant Weld Number 29-RC-2401-1, Outlet Ultrasonic Examination System Nozzle at 158°. Safe End to Pipe.

Reactor Coolant Weld Number RPV2-N1ASE, Outlet Ultrasonic Examination System Nozzle at 202°. Nozzle to Safe End Weld (DM).

Reactor Coolant Weld Number 29-RC-2101-1, Outlet Ultrasonic Examination System Nozzle at 202°. Safe End to Pipe.

Reactor Personnel Airlock. Component ID # M- Visual Examination Containment 90-LP-BLT-OE-IL.

Reactor Personnel Airlock. Component ID # M- Visual Examination Containment 90-EV-BLT-OE.

Reactor Personnel Airlock. Component ID # M- Visual Examination Containment 90-DH-BLT-OE-IL.

Reactor Containment Liner, CC-LINER-GV-F, Visual Examination Containment (180-270 degrees) Elevation >83 feet.

Safety Injection Safety Injection system pipe support Visual Examination System (Safety Injection tank room. Component ID # - RR/SI-2101-HL5019.

The inspectors reviewed records for the following nondestructive examinations:

SYSTEM IDENTIFICATION EXAMINATION TYPE Main Feedwater Pipe lugs. Component ID # - 18-FW- Magnetic Particle System 2032-AA2, 1PL1-1PL8.

Examination Main Steam Steam Generator Steam Outlet Power Penetrant Examination Operated Relief Valve (ORC), Valve Stem Shank.

Residual Heat Residual heat removal check valve. RH- Radiograph Removal 0032A Component ID # RG-2018-BB1.

Examination System Safety Injection FLEX Modification tie-in to the Safety Radiographic injection system. ID/Weld # HFW0089, Examination HFW0084, HFW0088 (all train A).

Reactor Coolant Weld Number RPV2-N1BSE, Outlet Ultrasonic System Nozzle 338°. Nozzle to Safe End Weld Examination (DM).

Reactor Coolant Weld Number 29-RC-2201-1, Outlet Ultrasonic System Nozzle at 338°. Safe End to Pipe.

Examination Reactor Coolant Weld Number RPV2-N1CSE, Outlet Ultrasonic System Nozzle at 22°. Nozzle to Safe End Weld Examination (DM).

Reactor Coolant Weld Number 29-RC-2301-1, Outlet Ultrasonic System Nozzle at 22°. Safe End to Pipe.

Examination Residual Heat Component ID # FW0001 and FW0002.

Visual Examination Removal System 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 inspector reviewed 7 indications and observed whether 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 Reactor Coolant Residual Heat Removal check valve Manual Gas Tungsten Arc System RH-0032A, FW0001 - Outlet side of Welding.

valve.

Reactor Coolant Residual Heat Removal check valve Manual Gas Tungsten Arc System RH-0032A, FW0002 - Inlet side of Welding.

valve.

Safety Injection FLEX Modification tie-in to Safety Manual Gas Tungsten Arc System Injection System - Train A.

Welding.

The inspectors reviewed records of the following welding activities:

System Weld Identification Weld Type Reactor System Reactor Head Vent Valves Manual Gas Tungsten Arc A2RCHV3657A, B2RCHV3657B, Welding.

A2RCHV36578A, B2RCHV3658B 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 of significance 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 whether the personnel performing the inspection were certified examiners to their respective nondestructive examination method.

b. Findings

No findings of significance were identified.

.3 Boric Acid Corrosion Control Inspection Activities

a. Inspection Scope

The inspectors evaluated the implementation of the licensees 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 walkdown as specified in Procedure 0PGP03-ZE-0133, Boric Acid Corrosion Control Program, Revision 8, and Procedure 0PGP03-ZE-0033, RCS Pressure Boundary Inspection for Boric Acid Leaks, Revision 13. The inspectors reviewed visual records of components and equipment containing boric acid leaks. The inspectors performed walkdowns of Residual Heat Removal pump 2C and the associated valve room along with portions of the Safety Injection, Reactor Coolant, and Chemical Volume Control systems. The inspectors verified that the visual inspections emphasized locations where boric acid leaks could cause degradation of safety-significant components. The inspectors also verified that the engineering evaluations for those components where boric acid was identified gave assurance that the ASME Code wall thickness limits were properly maintained.

b. Findings

No findings of significance were identified.

.4 Steam Generator Tube Inspection Activities

a. Inspection Scope

The licensee did not perform any steam generator activities during Refueling Outage 2RE17.

b. Findings

No findings of significance were identified.

.5 Identification and Resolution of Problems

a. Inspection scope

The inspectors reviewed 41 condition reports which dealt with inservice inspection activities and found the corrective actions to be appropriate. The specific condition reports reviewed are listed in the documents reviewed section. From this review the inspectors concluded that the licensee has an appropriate threshold for entering 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 operating experience. Specific documents reviewed during this inspection are listed in the attachment.

b. Findings

No findings of significance were identified.

1R11 Licensed Operator Requalification Program and Licensed Operator Performance

(71111.11)

.1 Review of Licensed Operator Requalification

a. Inspection Scope

On May 25, 2015, the inspectors observed an evaluated simulator scenario performed by an operating crew. The inspectors assessed the performance of the operators and the evaluators critique of their performance.

These activities constitute completion of one quarterly licensed operator requalification program sample, as defined in Inspection Procedure 71111.11.

b. Findings

No findings were identified.

.2 Review of Licensed Operator Performance

a. Inspection Scope

On May 7, 2015, 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 due to performing a reactor start-up following completion of Maintenance Outage 2RE17. The inspectors observed the operators performance of the following activities:

• Reactor start-up, including the pre-job brief In addition, the inspectors assessed the operators adherence to plant procedures, including conduct of operations procedure and other operations department policies.

These activities constitute completion of one quarterly licensed operator performance sample, as defined in Inspection Procedure 71111.11.

b. Findings

No findings were identified.

1R12 Maintenance Effectiveness

a. Inspection Scope

The inspectors reviewed three instances of degraded performance or condition of safety-related structures, systems, and components (SSCs):

• March 5 and March 21, 2015, Unit 1, essential chiller 12C trip on low oil pressure due to defective purge check valve resulting in the system being placed into Maintenance Rule a(1)

• April 22, 2015, Unit 1 and 2, technical support center diesel generator non-functional due to an inadequate temporary modification during refueling outages and resulted in an ORAM red risk status

• May 7, 2015, Unit 2, train B main steam power operated relief valve functional failure due to packing leak 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 three 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 five 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 4 and April 7, 2015, Unit 2, crane operations near standby 2 transformer to replace feedwater heaters 23A and B during Refueling Outage 2RE17

• May 7, 2015, Unit 2, train B steam generator power operated relief valve risk functional failure due to packing leak during reactor start-up

• June 9, 2015, Unit 2, train B, 125 volts direct current battery breaker replacement that required entry into the stations Configuration Risk Management Program

• June 23, 2015, Unit 2, train D, 120 volts alternating current 10-year inverter preventative maintenance that required use of the stations Configuration Risk Management Program

• June 30, 2015, Unit 2, train S solid state protection system logic card failure that required entry into the stations Configuration Risk Management Program The inspectors verified that these risk assessments 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.

The inspectors also reviewed the licensees actions for implementing the Configuration Risk Management Program for determining and implementing the risk-informed allowed outage time for the planned activities listed above.

The inspectors also observed portions of emergent work activities that had the potential to cause an initiating event:

• June 15 through 17, 2015, Unit 2, rescheduled work activities that involved the use of stations risk management program due to Tropical Storm Bill 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 SSCs.

These activities constitute completion of six 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

a. Inspection Scope

The inspectors reviewed four operability determinations and functionality assessments that the licensee performed for degraded or nonconforming SSCs:

• April 20, 2015, operability determination of the Unit 2 temperature element TE-0420Y thermowell (loop B hot leg) reaming activities that left the inner diameter out of tolerance

• May 8, 2015, operability determination of Unit 1 electrical auxiliary building train B heating, ventilation, and air conditioning damper following discovery of two corroded areas

• June 8, 2015, functionality assessment of Unit 2, train B emergency features safeguards 13.8 kV transformer upon receiving alarms on the load tap changer

• June 11, 2015, operability assessment of Unit 2, reactor coolant system loop 2B hot leg narrow range temperature element TE-0420Z that became grounded The inspectors reviewed the timeliness and technical adequacy of the licensees evaluations. Where the licensee determined the degraded SSC to be operable or functional, the inspectors verified that the licensees compensatory measures were appropriate to provide reasonable assurance of operability or functionality. The inspectors verified that the licensee had considered the effect of other degraded conditions on the operability or functionality of the degraded SSC.

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

b. Findings

No findings were identified.

1R18 Plant Modifications

Permanent Modifications

a. Inspection Scope

On June 9, 2015, the inspectors reviewed a permanent plant modification for the replacement of the Class 1E, 125 volts direct current battery output breaker on Unit 2 train B.

The inspectors reviewed the design and implementation of the modification. The inspectors verified that work activities involved in implementing the modification 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 of the SSC as modified.

These activities constitute completion of one sample 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 six post-maintenance testing activities that affected risk-significant SSCs:

• April 10, 2015, Unit 2, train B 13.8 kV to 4160 volts alternating current emergency safeguards features transformer following repair of cable stress cones

• April 20, 2015, Unit 2, FLEX diesel generator 22 following initial installation

• April 27, 2015, Unit 2, train B main steam power operated relief valve following replacement of valve internals

• May 3, 2015, Unit 2, train A low head safety injection to loop 2A cold leg check valve following complete replacement

• May 9, 2015, Unit 2, train B main steam power operated relief valve following replacement of valve stem and follower

• June 9, 2015, Unit 2, train B, 125 volts direct current battery breaker E2B11 following replacement 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 constitute completion of six post-maintenance testing inspection samples, as defined in Inspection Procedure 71111.19.

b. Findings

No findings were identified.

1R20 Refueling and Other Outage Activities

a. Inspection Scope

During the stations 2RE17 Refueling Outage that concluded on May 9, 2015, 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. This verification included the following:

• Review and verification of the licensees fatigue management activities

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

• Observation and review of reduced-inventory and mid-loop activities

• Observation and review of fuel handling activities

• Monitoring of heat-up and startup activities These activities constitute completion of one refueling outage sample, as defined in Inspection Procedure 71111.20.

b. Findings

No findings were identified.

1R22 Surveillance Testing

a. Inspection Scope

The inspectors observed six risk-significant surveillance tests and reviewed test results to verify that these tests adequately demonstrated that the SSCs were capable of performing their safety functions:

In-service tests:

• June 11, 2015, Unit 2, emergency diesel 22, 24-hour load test

• June 12, 2015, Unit 1, train A centrifugal charging pump 1A quarterly pump test Containment isolation valve surveillance tests:

• April 18, 2015, Unit 2, containment penetration M-18, train A high head safety injection discharge isolation valves 2-SI-0005A, 2-SI-0004A, and 2-SI-0211A Other surveillance tests:

• May 20, 2015, Unit 1, control room makeup and cleanup emergency function testing

• June 8, 2015, Unit 2, train B emergency safeguards features 13.8 kV to 4.1 kV emergency transformer load tap changer test

• June 13, 2015, Unit 1, monthly control rod operability 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 constitute completion of six 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 assessed 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. The inspectors walked down various portions of the plant and performed independent radiation dose rate measurements. The inspectors interviewed the radiation protection manager, radiation protection supervisors, and radiation workers. The inspectors reviewed licensee performance in the following areas:

• The hazard assessment program, including a review of the licensees evaluations of changes in plant operations and radiological surveys to detect dose rates, airborne radioactivity, and surface contamination levels

• Instructions and notices to workers, including labeling or marking containers of radioactive material, radiation work permits, actions for electronic dosimeter alarms, and changes to radiological conditions

• Programs and processes for control of sealed sources and release of potentially contaminated material from the radiologically controlled area, including survey performance, instrument sensitivity, release criteria, procedural guidance, and sealed source accountability

• Radiological hazards control and work coverage, including the adequacy of surveys, radiation protection job coverage and contamination controls, the use of electronic dosimeters in high noise areas, dosimetry placement, airborne radioactivity monitoring, controls for highly activated or contaminated materials (non-fuel) stored within spent fuel and other storage pools, and posting and physical controls for high radiation areas and very high radiation areas

• Radiation worker and radiation protection technician performance with respect to radiation protection work requirements. Audits, self-assessments, and corrective action documents related to radiological hazard assessment and exposure controls since the last inspection.

These activities constitute completion of one sample of radiological hazard assessment and exposure controls, 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 portions of the plant, and reviewed licensee performance in the following areas:

• The licensees use, when applicable, of ventilation systems as part of its engineering controls

• The licensees respiratory protection program for use, storage, maintenance, and quality assurance of National Institute for Occupational Safety and Health certified equipment, qualification and training of personnel, and user performance

• The licensees capability for refilling and transporting self-contained breathing apparatus air bottles to and from the control room and operations support center during emergency conditions, status of self-contained breathing apparatus staged and ready for use in the plant and associated surveillance records, and personnel qualification and training

• Audits, self-assessments, and corrective action documents related to in-plant airborne radioactivity control and mitigation since the last inspection These activities constitute completion of one sample of in-plant airborne radioactivity control and mitigation, 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 January 2014 through March 2015, the inspectors reviewed licensee event reports, 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 January 2014 through March 2015 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 January 2014 through March 2015 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 verified that there were no unplanned exposures or losses of radiological control over locked high radiation areas and very high radiation areas during the period of January 1, 2014 through March 31, 2015. The inspectors reviewed a sample of radiologically controlled area exit transactions showing exposures greater than 100 mrem. 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 or gaseous effluent releases that occurred between January 1, 2014 and March 31, 2015, and were 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 Semiannual Trend Review

a. Inspection Scope

The inspectors reviewed the licensees corrective action program, performance indicators, system and program health reports, and other documentation to identify trends that might indicate the existence of a more significant safety issue. The inspectors verified that the licensee was taking corrective actions to address identified adverse trends.

These activities constitute completion of one semiannual trend review sample, as defined in Inspection Procedure 71152.

b. Observations and Assessments Several trends emerged and were identified by both the licensee and the inspectors.

The following is a list of the trends and a brief description:

• An increase in the number of foreign material exclusion events during Refueling Outage 2RE17 that challenged reactor coolant system and fuel integrity

• Fatigue rule station procedure violations

• Hot work permit violations and several small fire events

• A number of maintenance re-work items during Refueling Outage 2RE17

• A number of personnel contamination events that exceeded outage goal by approximately 20

• Numerous housekeeping issues, especially inside containment The inspectors determined, through interviews with station personnel and by direct observation, that several of these trends were due in part to lack of management presence in the field. These trends have been discussed with the responsible departments, condition reports generated, and corrective action taken or scheduled to be taken.

c. Findings

No findings were identified.

.3 Annual Follow-up of Selected Issues

a. Inspection Scope

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

• From January 2015 through March 2015, safety related essential chillers tripped on low oil pressure three times from the failure of a condenser purge check valve.

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 planned corrective actions and that these actions were adequate to [correct the condition].

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

b. Findings

Introduction.

The inspectors documented a self-revealing, Green non-cited violation of 10 CFR Part 50, Appendix B, Criterion III, Design Control, for the failure to have adequate measures for the selection and review for suitability of application of parts that are essential to the safety-related functions of structures, systems and components.

Specifically, the licensee failed to properly inspect and test essential chiller condenser purge check valves during the stations commercial dedication process to ensure proper function in their safety-related application.

Description.

On January 18, 2015, the Unit 2 essential chiller 22A tripped on low oil pressure. This trip rendered the system inoperable, and the licensee entered Technical Specification 3.7.14. Operators investigated the failure and determined that the purge check valve was the cause of the low oil pressure condition. Specifically, the purge check valve had failed in the open position, and drained the oil from the system during a system purge of air and non-condensable gases. The valve was replaced, and the system was restored and declared operable. The licensee did not further investigate the cause for the failure. On March 5, 2015, the Unit 1 essential chiller 12C tripped following preventative maintenance that had replaced the condenser purge check valve, and then failed once again on March 21, 2015 due to a stuck open condenser purge check valve.

Following this third failure, the licensee conducted a root cause investigation to determine the cause of the repetitive failures. This issue was entered into the licensees corrective action program as Condition Report 15-4990.

The licensees evaluation of all three instances concluded that the stations commercial dedication process did not identify critical characteristics for the internal thread depth and pressure testing for the essential chiller purge check valves. Specifically, the internal threads extended too far into the valve, which resulted in internal binding and allowed the oil to drain from the system. The licensee noted that the production of the purge check valves for the essential chiller had been outsourced from the original equipment manufacturer to an outside company, which produced the defective parts.

Station Procedure 0PGP03-ZP-0014, Safety/Quality Classification and Dedication of Parts, Revision 5, specifies a process to provide reasonable assurance that a commercial grade item to be used as a basic component will perform its intended safety function and is deemed equivalent to an item designed and manufactured under a 10 CFR Part 50, Appendix B quality assurance program. The licensee concluded that their commercial dedication receipt and testing standards for these valves, as documented in technical evaluation 501-38270, which was last modified in 1993, was not adequate to have identified the defective part. Specifically, the stations commercial dedication process did not specify the internal thread depth as a critical characteristic, and only required testing the valve for flow in one direction and not in a manner in which the part was to operate (cyclic and in both open and closed directions). The licensee has implemented corrective actions to update the technical evaluation to add the internal thread depth as a critical characteristic and require flow testing in open and closed directions in the future.

Analysis.

The licensees failure to properly inspect and test essential chiller condenser purge check valves during the commercial dedication process to ensure proper function in the safety-related application was a performance deficiency. This performance deficiency is more than minor because it adversely affected the equipment performance attribute of the Mitigating Systems Cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, on January 18, 2015, March 5, 2015, and March 21, 2015, the inadequately dedicated purge check valves resulted in a trip of the essential chiller, rendering the train inoperable and challenging plant operations. Using NRC Inspection Manual 0609, Appendix A, Exhibit 2, Mitigating Systems Screening Questions, the inspectors determined the finding was of very low safety significance (Green) because it did not affect the design or qualification of the system, did not result in a loss of system function, did not represent a loss of function of a single train for greater than its technical specifications allowed outage time, and did not cause the loss of function of one or more non-technical specification trains of equipment designated as high safety-significance. The inspectors determined that the finding did not have a cross-cutting aspect because the main contributor to the cause of the performance deficiency occurred during revision of the technical evaluation in 1993.

Enforcement.

Title 10 CFR Part 50, Appendix B, Criterion III, Design Control, states in part, that measures shall be established for the selection and review for suitability of application of parts that are essential to the safety-related functions of structures, systems and components. Contrary to the above, since 1993, the licensee failed to implement measures for the review of suitability of application of parts that were essential to the safety-related functions of structures, systems and components.

Specifically, the failure to define critical characteristics and adequately test those characteristics as required by station Procedure 0PGP03-ZP-0014, Safety/Quality Classification and Dedication of Parts, Revision 5, resulted in installation of defective essential chiller purge check valves and three trips of safety related essential chillers.

The violation was entered into the licensees corrective action program as Condition Report 15-4990. This violation is being treated as a non-cited violation consistent with Section 2.3.2.a of the NRC Enforcement Policy: NCV 05000498/2015002-02; 05000499/2015002-02, Failure to Properly Dedicate Essential Chiller Purge Check Valves.

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

.1 (Closed) Licensee Event Report 05000499/2015-001-00, Technical Specification Action

Statement Time Exceeded Due to Turbine-Driven Auxiliary Feedwater Pump Test Failure Not Recognized On March 4, 2015, the licensee failed to recognize that the Unit 2 turbine-driven auxiliary feedwater (AFW) pump 24 failed to meet surveillance acceptance criteria for as-found discharge pressure. The licensee identified the failure during a review of surveillance documentation on March 11, 2015, and declared AFW pump 24 inoperable from the date of the failed surveillance. As a result, the technical specification allowed outage time of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> was exceeded. The governor was replaced and AFW pump 24 was declared operable on March 14, 2015.

The licensee entered this event into the corrective action program as Condition Report 2015-5477, and conducted a root cause investigation to determine the cause of not immediately identifying a failed surveillance and to determine why a repair to the governor had been delayed until the next refueling outage, 2RE17, in April 2015.

Inspectors reviewed the root cause evaluation. The licensee determined the root cause was inadequate communication of an operable but degraded condition that was declared following a December 11, 2014, prompt operability determination. Corrective actions include revising the operability assessment system program and developing a standardized prompt determination process.

The licensee also identified three contributing causes: 1) the as-found discharge pressure data was not being trended by the engineering department, 2) station personnel did not understand or follow the process to reschedule work, and 3) operators used ineffective verification practices for surveillance acceptance criteria. Corrective actions included the acquisition of software to trend as-found discharge pressure, analysis to determine training needs regarding the process of rescheduling work, and additional training for the personnel who conducted the failed surveillance. The inspectors determined the licensees actions were adequate and appropriate.

The enforcement and significance of this event are discussed in section

4OA7 of this

inspection report.

Licensee Event Report 05000499/2015-001-00 is closed.

These activities constitute completion of one event follow-up sample, as defined in Inspection Procedure 71153.

4OA6 Meetings, Including Exit

Exit Meeting Summary

On April 17, 2015, the inspectors presented the radiation safety inspection results to Mr. D. Koehl, President and Chief Executive Officer, 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, 2015, the inspectors debriefed the inservice inspection results to Mr. G. Powell, Site Vice President, and other members of the licensee staff. The licensee acknowledged the issues presented. The inspectors acknowledged review of proprietary material during the inspection, which had been or will be returned to the licensee.

On July 16, 2015, the inspectors presented the resident inspection results to Mr. L. Peter, General Manager of Projects, 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 meet the criteria of the NRC Enforcement Policy for being dispositioned as a Non-Cited Violation.

• Technical Specification 3.7.1.2, Auxiliary Feedwater System, requires, in part, that four independent steam generator AFW pumps and associated flow paths shall be operable with one steam turbine-driven AFW pump capable of being powered from an operable steam supply system. Action B of Technical Specification 3.7.1.2 allows the turbine-driven AFW pump to be inoperable for 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or the requirements of the Configuration Risk Management Program must be applied. Contrary to the above, the turbine-driven AFW pump was inoperable for greater than 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> without application of the Configuration Risk Management Program. Specifically, the licensee failed to recognize that the turbine-driven AFW pump did not meet acceptance criteria for a surveillance performed on March 4, 2015. During a review of surveillance documentation on March 11, 2015, the licensee recognized that the pump had failed the surveillance and was inoperable until repairs could be completed. As a result, the pump was inoperable from March 4, 2015 to March 14, 2015, which exceeded the technical specification allowed outage time of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. This finding has very low safety significance (Green) because the finding did not lead to an actual loss of safety function of the system or cause a component to be inoperable. This issue was entered into the licensees corrective action program as Condition Report 2015-5477.

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

R. Aguilera, Manager, Health Physics

J. Ashcraft, Quality Control

J. Atkins, Manager, Systems Engineering

M. Berg, Manager, Design Engineering/Testing and Programs

C. Bowman, Manager, Nuclear Oversight

W. Brost, Engineer, Licensing

J. Connolly, General Manager, Engineering

R. Dunn Jr., Manager, Nuclear Fuel and Analysis

T. Frawley, Manager, Plant Protection/Emergency Response

M. Garner, Nondestructive Examination Examiner

R. Gibbs, Manager, Operations, Production Support

R. Gonzales, Senior Engineer, Licensing

J. Hartley, Manager, Mechanical Maintenance

J. Heil, TPE Engineer, Programs

G. Hildebrandt, Manager, Operations

G. Janak, Operations Training Manager

K. Kawabata, Plant Health Physicist, Radiation Protection

G. Kelton, Supervisor, Radiation Protection

D. Koehl, President and CEO

J. Lovejoy, Manager, I&C Maintenance

R. McNeil, Manager, Maintenance Engineering

J. Milliff, Manager, Security

M. Murray, Manager, Regulatory Affairs

R. Nieman, Site Authorized Nuclear Inspector (ANII)

L. Peter, General Manager, Projects

J. Pierce, Manager, Unit 1 Operations

G. Powell, Site Vice President

R. Richardson, Welding Engineer

M. Ruvalcaba, Manager, Strategic Projects

R. Savage, Engineer, Licensing Staff Specialist

R. Scarborough, Manager, Quality Assurance

M. Schaefer, Plant General Manager

S. Shojaei, Repair and Replacement Program Engineer, Testing Programs

L. Spiess, Supervisor, Testing Programs

R. Stastny, Maintenance Manager

L. Sterling, Supervisor, Licensing

T. Wacker, Engineer, Quality Programs

R. Wied, Radiation Protection Technician, Health Physics

J. Williams, Engineer, Testing Programs

P. Williams, Program Manager, Boric Acid Corrosion Control

C. Younger, Testing Programs

D. Zink, Supervising Engineering Specialist

Attachment 1

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened and Closed

05000498/2015002-01 Failure to Follow Hurricane Plan Procedure to Secure Missile

NCV

05000499/2015002-01 Hazards During Tropical Storm Bill (1R01)

05000498/2015002-02 Failure to Properly Dedicate Essential Chiller Purge Check

NCV

05000499/2015002-02 Valves (4OA2)

Closed

Technical Specification Action Statement Time Exceeded Due to

05000499/2015-001-00 LER Turbine Drive Auxiliary Feedwater Pump Test Failure Not

Recognized