IR 05000498/2015004

NRC Integrated Inspection Report 05000498/2015004 and 05000499/2015004

ML16042A550
Person / Time
Site:	South Texas
Issue date:	02/11/2016
From:	Nick Taylor NRC/RGN-IV/DRP/RPB-B
To:	Koehl D South Texas
Taylor N
References
IR 2015004
Download: ML16042A550 (75)

Text

UNITED STATES ary 11, 2016

SUBJECT:

SOUTH TEXAS PROJECT ELECTRIC GENERATING STATION - NRC INTEGRATED INSPECTION REPORT 05000498/2015004 AND 05000499/2015004

Dear Mr. Koehl:

On December 31, 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 January 7, 2015, the NRC inspectors discussed the results of this inspection with Mr. G. Powell, Site Vice President, 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.

One of these findings involved a violation of NRC requirements.

If you contest the violation or significance of this non-cited violation (NCV), 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 or a finding not associated with a regulatory requirement 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/

Nicholas H. 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 05000498/2015004 and 05000499/2015004 w/Attachment 1: Supplemental Information w/Attachment 2: Document Request for Inservice Inspection

ML16042A550 SUNSI Review ADAMS Non- Publicly Available Keyword:

By: NHT Yes No Sensitive Non-Publicly Available NRC-002 Sensitive OFFICE SRI:DRP/B RI:DRP/B TL:DRS/TSS C:DRS/EB1 C:DRS/EB2 C:DRS/OB NAME ASanchez NHernandez THipschman TFarnholtz GWerner VGaddy SIGNATURE /RA/E- /RA/E- /RA/ /RA/ /RA/ /RA/

DATE 2/10/16 2/10/16 2/4/16 2/4/16 2/4/16 2/3/16 OFFICE C:DRS/PSB1 C:DRS/PSB2 BC:DRP/B NAME MHaire HGepford NTaylor SIGNATURE /RA/ /RA/ /RA/

DATE 2/4/16 2/3/16 2/11/16

Letter to Dennis Koehl from Nicholas Taylor dated February 11, 2016 SUBJECT: SOUTH TEXAS PROJECT ELECTRIC GENERATING STATION - NRC INTEGRATED INSPECTION REPORT 05000498/2015004 AND 05000499/2015004 DISTRIBUTION:

Regional Administrator (Marc.Dapas@nrc.gov)

Deputy Regional Administrator (Kriss.Kennedy@nrc.gov)

DRP Director (Troy.Pruett@nrc.gov)

DRP Deputy Director (Ryan.Lantz@nrc.gov)

DRS Director (Anton.Vegel@nrc.gov)

DRS Deputy Director (Jeff.Clark@nrc.gov)

Senior Resident Inspector (Alfred.Sanchez@nrc.gov)

Resident Inspector (Nicholas.Hernandez@nrc.gov)

Branch Chief, DRP/B (Nick.Taylor@nrc.gov)

Senior Project Engineer, DRP/B (David.Proulx@nrc.gov)

Project Engineer, DRP/B (Shawn.Money@nrc.gov)

Project Engineer, DRP/B (Steven.Janicki@nrc.gov)

STP Administrative Assistant (Lynn.Wright@nrc.gov)

Public Affairs Officer (Victor.Dricks@nrc.gov)

Project Manager (Lisa.Regner@nrc.gov)

Team Leader, DRS/TSS (Thomas.Hipschman@nrc.gov)

RITS Coordinator (Marisa.Herrera@nrc.gov)

ACES (R4Enforcement.Resource@nrc.gov)

Regional Counsel (Karla.Fuller@nrc.gov)

Technical Support Assistant (Loretta.Williams@nrc.gov)

Congressional Affairs Officer (Jenny.Weil@nrc.gov)

RIV Congressional Affairs Officer (Angel.Moreno@nrc.gov)

OEWEB Resource (OEWEB.Resource@nrc.gov)

OEWEB Resource (Sue.Bogle@nrc.gov)

RIV/ETA: OEDO (Raj.Iyengar@nrc.gov)

ROPreports.Resource@nrc.gov ROPassessment.Resource@nrc.gov

U.S. NUCLEAR REGULATORY COMMISSION

REGION IV

Docket: 05000498, 05000499 License: NPF-76, NPF-80 Report: 05000498/2015004 and 05000499/2015004 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: October 4 through December 31, 2015 Inspectors: A. Sanchez, Senior Resident Inspector N. Hernandez, Resident Inspector M. Bloodgood, Operations Engineer J. Braisted, Reactor Inspector T. Farina, Senior Operations Engineer G. Guerra, CHP, Emergency Preparedness Inspector R. Kopriva, Senior Reactor Inspector R. Kumana, Resident Inspector B. Larson, Senior Operations Engineer D. Proulx, Senior Project Engineer C. Smith, Reactor Inspector Approved Nicholas H. Taylor By: Chief, Project Branch B Division of Reactor Projects-1- Enclosure

SUMMARY

IR 05000498/2015004, 05000499/2015004; 10/04/2015 - 12/31/2015; South Texas Project

Electric Generating Station, Units 1 and 2, Licensed Operator Requalification, and Problem Identification and Resolution The inspection activities described in this report were performed between October 4 and December 31, 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. One of these findings involved a violation of NRC requirements.

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, 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, dated February 4, 2015. The NRCs program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process,

Revision 5.

Cornerstone: Mitigating Systems

Green.

The inspectors identified a finding, associated with simulator operability testing, for the failure of the licensee to track and incorporate actual plant data into their cyclic operability tests, as required by American National Standards Institute-3.5-2009, Nuclear Power Plant Simulators for Use in Operator Training and Examination. With the exception of one transient, the licensee exclusively used engineering analysis from the RETRAN code as baseline data without reference to plant events that may have been related to the required transient tests. This issue was entered into the licensees corrective action program as Condition Report 15-21463.

The failure to track and incorporate plant events into baseline data for simulator operability testing is a performance deficiency. It is more than minor and, therefore, a finding because it is associated with the human performance attribute of the Mitigating Systems Cornerstone and negatively affected the objective to ensure the reliability and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, if simulator performance is not being compared to the most relevant baseline data from the plant, the reliability of the simulator performance is reduced. Using Inspection Manual Chapter 0609,

Significance Determination Process, Phase 1 worksheets, and the corresponding Appendix I, Licensed Operator Requalification SDP (block 14), the finding was determined to have very low safety significance (Green) because it is a Simulator testing, maintenance, or modification deficiency. This finding has a cross-cutting aspect in the procedure adherence component of the human performance cross-cutting area because the licensee failed to ensure that individuals follow processes, procedures, and work instructions in that the American National Standards Institute-3.5-2009 guidance for selecting baseline data for simulator testing was not followed [H.8]. (Section 1R11.3)

Cornerstone: Emergency Preparedness

Green.

The inspectors identified a non-cited violation of 10 CFR 50.54(q)(2) for failure to maintain the emergency plan in accordance with the approved safety evaluation report.

Specifically, the licensee failed to meet 10 CFR 50.47(b)(2) requirements for timely augmentation of response capabilities, in accordance with the approved safety evaluation report. Following an update to the safety evaluation report in 1993, the licensee failed to update the emergency response organization staff augmentation time requirements to commence at the time of an emergency declaration vice from the time of an emergency notification. To restore compliance, the licensee updated the emergency plan in accordance with the current safety evaluation report.

Failure to maintain the site emergency plan in accordance with the approved safety evaluation report, dated May 20, 1993, was a performance deficiency. Specifically, the licensee failed to update the ERO staff augmentation time requirements to commence at the time of an emergency declaration, as required by the NRC safety evaluation report. This performance deficiency is more than minor because it is associated with the procedure quality attribute of the Emergency Preparedness Cornerstone and adversely affected the cornerstone objective to ensure that the licensee is capable of implementing adequate measures to protect the health and safety of the public in the event of a radiological emergency. This finding was evaluated using Inspection Manual Chapter 0609, Appendix B, Emergency Preparedness Significance Determination Process (SDP), dated September 22, 2015, and was determined to be of very low safety significance (Green) per Table 5.2-1, Significance Examples 50.47(b)(2), because the staffing processes do not meet the threshold of routinely not capable of ensuring timely augmentation of the on shift emergency response staff to the extent that more than one required ERO functional area (in accordance with E-plan commitments) would not be filled. No cross-cutting aspect is assigned because the performance deficiency is not indicative of present performance.

(Section 4OA2.3)

PLANT STATUS

Unit 1 began the inspection period operating at 100 percent power. On October 18, 2015, Unit 1 entered Mode 3 to begin Refueling Outage 1RE19. On November 13, 2015, Unit 1 entered Mode 3, but identified a reactor coolant pump 1C high seal leak off from the number 1 seal and returned to Mode 5 later that day to replace the seal. On November 17, 2015, following the repair of the reactor coolant pump 1C seal replacement, Unit 1 entered Mode 3. On November 20, 2015, Unit 1 entered Mode 5 to evaluate issues regarding unreliable operation of control rod D-6. Following an NRC emergency license amendment review and approval, the licensee removed control rod D-6 from the reactor and entered Mode 3 on December 18, 2015. On December 20, 2015, Unit 1 closed main generator output breakers ending Refueling Outage 1RE19.

On December 21, 2015, while at 48 percent reactor power, main turbine governor valve number 2 began oscillating uncontrollably. Reactor operators tripped the main turbine. Following the main turbine trip, group one steam dumps failed to operate, which led to rising steam generator levels and resulted in a main feedwater isolation actuation. Reactor operators initiated a manual reactor trip, and entered Mode 3, due to the inability to maintain and control steam generator levels. Following repairs to the main turbine number 2 governor valve and the group one steam dumps, Unit 1 entered Mode 1 on December 24, 2015, and main generator breakers were closed on December 25, 2015. On December 30, 2015, Unit 1 reached 100 percent power and remained there for the remainder of the inspection period.

Unit 2 operated at 100 percent power for the entire inspection period.

REPORT DETAILS

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R01 Adverse Weather Protection

.1 Readiness for Seasonal Extreme Weather Conditions

a. Inspection Scope

On October 13, 2015, the inspectors completed an inspection of the stations readiness for seasonal extreme weather conditions. The inspectors reviewed the licensees adverse weather procedures for extreme cold weather and evaluated the licensees implementation of these procedures. The inspectors verified that prior to the onset of cold weather, the licensee had corrected weather-related equipment deficiencies identified during the previous cold weather season.

The inspectors selected two risk-significant systems that were required to be protected from cold weather:

• Units 1 and 2, essential cooling water intake structures

• Units 1 and 2, engineered safety features transformers The inspectors reviewed the licensees procedures and design information to ensure the systems would remain functional when challenged by adverse weather. The inspectors verified that operator actions described in the licensees procedures were adequate to maintain readiness of these systems. The inspectors walked down portions of these systems to verify the physical condition of the adverse weather protection features.

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

b. Findings

No findings were identified.

.2 Readiness to Cope with External Flooding

a. Inspection Scope

On October 14 and December 30, 2015, the inspectors completed an inspection of the stations readiness to cope with external flooding. After reviewing the licensees flooding analysis, the inspectors chose six plant areas that were susceptible to flooding:

• Units 1 and 2 electrical auxiliary building

• Units 1 and 2 auxiliary feedwater storage tank areas

• Units 1 and 2 tendon access and auxiliary airlock areas The inspectors reviewed plant design features and licensee procedures for coping with flooding. The inspectors walked down the selected areas to inspect the design features, including the material condition of seals, drains, and flood barriers. The inspectors evaluated whether credited operator actions could be successfully accomplished.

These activities constituted one sample of readiness to cope with external flooding, as defined in Inspection Procedure 71111.01.

b. Findings

No findings were identified.

1R04 Equipment Alignment

.1 Partial Walkdown

a. Inspection Scope

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

• October 14, 2015, Unit 1, train A high head safety injection system while train B high head safety injection system was out of service for planned maintenance

• October 21, 2015, Unit 1, technical support diesel generator when it was required for backup electrical power for closure of the containment equipment hatch

• December 14 through 15, 2015, Unit 2, train A auxiliary feedwater system while train D auxiliary feedwater pump was out of service for planned maintenance

• December 16 through 17, 2015, Unit 1, train B essential cooling water system while train C essential cooling water was out of service for planned maintenance 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 trains 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.

.2 Complete Walkdown

a. Inspection Scope

On October 6, 2015, the inspectors performed a complete system walk-down inspection of the Unit 2, train A component cooling water. The inspectors reviewed the licensees procedures and system design information to determine the correct component cooling water lineup for the existing plant configuration. The inspectors also reviewed open condition reports, temporary modifications, and other open items tracked by the licensees operations and engineering departments. The inspectors then visually verified that the system was correctly aligned for the existing plant configuration.

On December 19, 2015, the inspectors performed a complete system walk-down inspection of the Unit 1, train B high pressure safety injection system. The inspectors reviewed the licensees procedures and system design information to determine the correct high pressure safety injection system lineup for the existing plant configuration.

The inspectors also reviewed open condition reports, temporary modifications, and other open items tracked by the licensees operations and engineering departments. The inspectors then visually verified that the system was correctly aligned for the existing plant configuration.

These activities constituted two complete 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 seven plant areas important to safety:

• October 7, 2015, Unit 2, mechanical auxiliary building, Fire Areas 27, 29, and 02; Fire Zones Z128, Z139, and Z140

• October 19, 2015, Unit 1, reactor containment building, Fire Area 63, Fire Zones Z222 and Z203

• November 4, 2015, Unit 1, electrical auxiliary building, Fire Area 04, Fire Zones Z052 and Z054

• November 18, 2015, Unit 1, mechanical auxiliary building, Fire Area 50, Fire Zone 401

• November 18, 2015, Unit 1, mechanical auxiliary building, Fire Area 49, Fire Zone 402

• November 19, 2015, Unit 1, mechanical auxiliary building, Fire Area 48, Fire Zone 403

• November 19, 2015, Unit 1, mechanical auxiliary building, Fire Area 51, Fire Zone 405 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 seven quarterly inspection samples, as defined in Inspection Procedure 71111.05.

b. Findings

No findings were identified.

1R06 Flood Protection Measures

a. Inspection Scope

The inspectors completed an inspection of the stations ability to mitigate flooding due to internal causes. After reviewing the licensees flooding analysis, the inspectors chose two plant areas containing risk-significant structures, systems, and components (SSCs)that were susceptible to flooding:

• On November 20, 2015, Unit 1, train A auxiliary feedwater pump room

• On December 30, 2015, Unit 1, fuel handling building The inspectors reviewed plant design features and licensee procedures for coping with internal flooding. The inspectors walked down the selected areas to inspect the design features, including the material condition of seals, drains, and flood barriers. The inspectors evaluated whether operator actions credited for flood mitigation could be successfully accomplished.

These activities constitute completion of two flood protection measures samples, as defined in Inspection Procedure 71111.06.

b. Findings

No findings were identified.

1R07 Heat Sink Performance

a. Inspection Scope

The inspectors reviewed licensee programs to verify heat exchanger performance and operability for the following heat exchangers:

• Unit 1, train A standby diesel generator lube oil and jacket water heat exchangers

• Unit 1, train C essential chilled water chiller

• Unit 2, train A component cooling water heat exchanger

• Unit 2, train C essential chilled water chiller The inspectors verified whether testing, inspection, maintenance, and chemistry control programs are adequate to ensure proper heat transfer. The inspectors verified that the periodic testing and monitoring methods, as outlined in commitments to NRC Generic Letter 89-13, utilized proper industry heat exchanger guidance. Additionally, the inspectors verified that the licensees chemistry program ensured that biological fouling was properly controlled between tests. The inspectors reviewed previous maintenance records of the heat exchangers to verify that the licensees heat exchanger inspections adequately addressed structural integrity and cleanliness of their tubes. Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of four triennial heat sink inspection samples, as defined in Inspection Procedure 71111.07-05.

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 Nondestructive Examination (NDE) Activities and Welding Activities

a. Inspection Scope

The inspectors directly observed the following nondestructive examinations:

SYSTEM WELD IDENTIFICATION EXAMINATION TYPE Auxiliary Feedwater Component ID # Pipe Lugs/8-AF- Magnetic Particle System 1010-GA2[C]/19PL1-19PL8.

Examination Drawing # B AF 5. Record

1. MT-2015-062 Safety Injection Component ID # SI-1206-HFW- Penetrant Examination System 0191 - FLEX tie-in to Safety Injection System. 3 inch Weld-O-Let to 6 inch pipe. Record

1. PT-2015-218 Reactor Coolant Component ID # Reactor Vessel Penetrant Examination System Head Vent Isolation Valve FW-0015 (10 Pipe-to-Valve HV3658A). Record

1. PT 2015 222 Reactor Coolant Component ID # Reactor Vessel Penetrant Examination System Head Vent Isolation Valve FW-0006 (13 Pipe-to-Valve HV3658B). Record #

PT 2015 223 Safety Injection Component ID # SI 1206. Weld Radiograph Examination System ID # HFW-0177. Dated 10/27/2015. 3 inch butt weld.

Mistras Job # J 4542-4063457 Safety Injection Component ID # SI 1106. Weld Radiograph Examination System ID # HFW-0156. Dated 10/22/2015. 3 inch butt weld.

Mistras Job # J 4542-40163457 Main Steam System Component ID # 30-MS-1002 Ultrasonic Examination GA2. Weld 23B Pipe to Pipe.

Record # UTCAL-2015-84 (Ultrasonic Calibration)

SYSTEM WELD IDENTIFICATION EXAMINATION TYPE Main Steam System Component ID # 30-MS-1002 Ultrasonic Examination GA2. Weld 23B Pipe to Pipe.

Record # UTP 2015-15 (Ultrasonic Profile)

Main Steam System Component ID # 30-MS-1002 Ultrasonic Examination GA2. Weld 23B Pipe to Pipe.

Record # UT Exam 2015-69 Main Steam System Component ID # 30-MS-1002 Ultrasonic Examination GA2. Weld 25 Valve to Pipe.

Record # UTCAL 2015-82 (Ultrasonic Calibration)

Main Steam System Component ID # 30-MS-1002 Ultrasonic Examination GA2. Weld 25 Valve to Pipe.

Record # UTP 2015 1 (Ultrasonic Profile)

Main Steam System Component ID # 30-MS-1002 Ultrasonic Examination GA2. Weld 25 Valve to Pipe.

Record # UT Exam 2015-68 Auxiliary Feedwater Component ID # Pipe to Elbow, Ultrasonic Examination System 16 F 1018-GA2 weld 9.1.

Transducer 45/60 degree.

Drawing # B-FW-8. Record # UT Exam-2015-076 Auxiliary Feedwater Component ID # Pipe to Elbow, Ultrasonic Examination System 16 FW 1018-GA2, weld 9.1.

Drawing # B-FW-8. Record #

UTP 2015-20 (UT Profile)

Auxiliary Feedwater Component ID # Elbow to Pipe, Ultrasonic Examination System 16 F 1018-GA2 weld 8.1.

Transducer 45/60 degree.

Drawing # B-FW-8. Record # UT Exam-2015-077 Auxiliary Feedwater Component ID # Elbow to Pipe, Ultrasonic Examination System 16-FW-1018-GA2, weld 8.1.

Drawing # B-FW-8. Record #

UTP 2015-21 (UT Profile)

Safety Injection Component ID # SI-1106HFW- Visual Examination System 0190. FLEX tie-in to Safety Injection System. 3 inch Weld-O-Let to Spool SI-1106-F. Record #

VTW-2015-427 SYSTEM WELD IDENTIFICATION EXAMINATION TYPE Safety Injection Component ID # SI-1206-HFW- Visual Examination System 0191. FLEX tie-in to Safety Injection System. 3 inch Weld-O-Let to 6 inch pipe. Record #

VTW-2015-457 Component Cooling Component ID # GUIDE/CC- Visual Examination Water 1101-HL5001, Drawing # CC-9101-HL5001. Pipe Support.

Report # VTC-2015-80 Component Cooling Component ID # GUIDE/CC- Visual Examination Water 1102-HL5002, Drawing # CC-9102-HL5002. Pipe Support.

Report # VTC-2015-72 Reactor Coolant Component ID # Bottom Visual Examination System Mounted Instrument Penetration/No. 1-58. Drawing #

A-RPB-BMI. Record #

VE 2015-005 Reactor Coolant Component Summary: #100718. Visual Examination System RPV1 N1ASE/RPV Loop A Outlet Nozzle to Safe End @ 202 Degrees. Drw. # A-RPV-2 Reactor Coolant Component Summary: #100858. Visual Examination System RPV1 N1BSE/RPV Loop B Outlet Nozzle to Safe End @ 338 Degrees. Drw. # A-RPV-2 Reactor Coolant Component Summary: #100998.

Visual Examination System RPV1 N1CSE/RPV Loop C Outlet Nozzle to Safe End @ 22 Degrees. Drw. # A-RPV-2 Reactor Coolant Component Summary: #101138. Visual Examination System RPV1 N1DSE/RPV Loop D Outlet Nozzle to Safe End @ 158 Degrees. Drw. # A-RPV-2 Reactor Coolant Component Summary: # 760180. Visual Examination System RPV1 N1ASE/RPV Loop A Outlet Nozzle to Safe End, (Hot Leg). Drw. # A-RPV-2 Reactor Coolant Component Summary: # 760200. Visual Examination System RPV1 N1BSE/RPV Loop B Outlet Nozzle to Safe End, (Hot Leg). Drw. # A RPV-2 SYSTEM WELD IDENTIFICATION EXAMINATION TYPE Reactor Coolant Component Summary: # 760220. Visual Examination System RPV1-N1CSE/RPV Loop C Outlet Nozzle to Safe End, (Hot Leg). Drw. # A-RPV-2 Reactor Coolant Component Summary: # 760240. Visual Examination System RPV1-N1DSE/RPV Loop D Outlet Nozzle to Safe End, (Hot Leg). Drw. # A-RPV-2 Component Cooling Record # VTC-2015-80.

Visual Examination Water System Component: Guide/CC-1101-HL5001, pipe support. Drw. #

CC- 9101-HL5001 Component Cooling Record # VTC-2015-72.

Visual Examination Water System Component: Guide/CC-1102-HL5002, pipe support. Drw. #

CC- 9102-HL5002 Reactor Pressure Record # VTW-2015-465.

Visual Examination Vessel System Component: Reactor Vessel Head Vent Isolation Valve FW-0015 (Pipe to Valve HV3658A)

Reactor Pressure Record # VTW-2015-466.

Visual Examination Vessel System Component: Reactor Vessel Head Vent Isolation Valve FW-0006 (Pipe to Valve HV3658B)

Chemical Volume Record # VTC-20105-82.

Visual Examination Control System Component: SH-V/CV-1121-HS5004 (Spring Can Hanger).

Drawing: CV-9121-HS5004 Auxiliary Feedwater Component ID # Pipe Lugs/8-AF- Magnetic Particle System 1010-GA2[C]/19PL1-19PL8.

Examination Drawing # B AF 5. Record # MT-2015-062 Safety Injection Component ID # SI-1206-HFW- Penetrant Examination System 0191 - FLEX tie-in to Safety Injection System. 3 inch Weld-O-Let to 6 inch pipe. Record # PT-2015-218 Reactor Coolant Component ID # Reactor Vessel Penetrant Examination System Head Vent Isolation Valve FW-0015 (10 Pipe-to-Valve HV3658A). Record # PT 2015 222 SYSTEM WELD IDENTIFICATION EXAMINATION TYPE Reactor Coolant Component ID # Reactor Vessel Penetrant Examination System Head Vent Isolation Valve FW-0006 (13 Pipe-to-Valve HV3658B). Record # PT 2015 223 Safety Injection Component ID # SI 1206. Weld Radiograph Examination System ID # HFW-0177. Dated 10/27/2015. 3 inch butt weld.

Mistras Job # J 4542-4063457 Safety Injection Component ID # SI 1106. Weld Radiograph Examination System ID # HFW-0156. Dated 10/22/2015. 3 inch butt weld.

Mistras Job # J 4542-40163457 Main Steam System Component ID # 30-MS-1002 Ultrasonic Examination GA2. Weld 23B Pipe to Pipe.

Record # UTCAL-2015-84 (Ultrasonic Calibration)

Main Steam System Component ID # 30-MS-1002 Ultrasonic Examination GA2. Weld 23B Pipe to Pipe.

Record # UTP 2015-15 (Ultrasonic Profile)

Main Steam System Component ID # 30-MS-1002 Ultrasonic Examination GA2. Weld 23B Pipe to Pipe.

Record # UT Exam 2015-69 Main Steam System Component ID # 30-MS-1002 Ultrasonic Examination GA2. Weld 25 Valve to Pipe.

Record # UTCAL 2015-82 (Ultrasonic Calibration)

Main Steam System Component ID # 30-MS-1002 Ultrasonic Examination GA2. Weld 25 Valve to Pipe.

Record # UTP 2015 1 (Ultrasonic Profile)

Main Steam System Component ID # 30-MS-1002 Ultrasonic Examination GA2. Weld 25 Valve to Pipe.

Record # UT Exam 2015-68 Auxiliary Feedwater Component ID # Pipe to Elbow, Ultrasonic Examination System 16 F 1018-GA2 weld 9.1.

Transducer 45/60 degree.

Drawing # B-FW-8. Record # UT Exam-2015-076 The inspectors reviewed records for the following nondestructive examinations:

SYSTEM IDENTIFICATION EXAMINATION TYPE Safety Injection Component ID # SI 1106. Weld Radiograph Examination System ID # HFW-0149. Dated 10/22/2015. 3 inch butt weld.

Mistras Job # J 4542-40163457 Safety Injection Component ID # SI 1106. Weld Radiograph Examination System ID # HFW-0156. Dated 10/22/2015. 3 inch butt weld.

Mistras Job # J 4542-40163457 Safety Injection Component ID # SI 1106. Weld Radiograph Examination System ID # HFW-0150. Dated 08/19/2015. 3 inch butt weld.

Mistras Job # J 4491-40131645 Safety Injection Component ID # SI 1206. Weld Radiograph Examination System ID # HFW-0163. Dated 10/05/2015. 3 inch butt weld.

Mistras Job # J 4542-40163457 Auxiliary Feedwater Component ID # 4-RC-1320-BB1 Ultrasonic Examination System weld 4, pipe to elbow.

Transducer 45 degrees. Drawing

1. A-RC-10. Record # UT Exam 2015-064 Auxiliary Feedwater Component ID # 4-RC-1320- Ultrasonic Examination System BB1-4, elbow to pipe. Drawing #

A-RC-10. Record # UTP 2015-16 (UT Profile)

Auxiliary Feedwater Component ID # 4-RC-1320-BB1 Ultrasonic Examination System weld 5, elbow to pipe.

Transducer 45 degrees. Drawing

1. A-RC-10. Record # UT Exam-2015-065 Auxiliary Feedwater Component ID # 4-RC-1320- Ultrasonic Examination System BB1-5, elbow to pipe. Drawing #

A-RC-10. Record # UTP 2015-17 (UT Profile)

Auxiliary Feedwater Component ID # 102950 12-RC- Ultrasonic Examination System 1312-BB1 weld 10, elbow to pipe. Transducer 45 degrees.

Drawing # A-RC-8. Record # UT Exam-2015-066 SYSTEM IDENTIFICATION EXAMINATION TYPE Auxiliary Feedwater Component ID # 12-RC-1312- Ultrasonic Examination System BB1 weld 10, elbow to pipe.

Drawing # A RC-8. Record # UTP 2015-19 (UT Profile)

Auxiliary Feedwater Component ID # 8-RC-1214-BB1 Ultrasonic Examination System weld 3, elbow to pipe. Drawing #

A-RC-8. Record # UTP 2015-18 (UT Profile)

During the review and observation of each examination, the inspectors verified that activities were performed in accordance with ASME Boiler and Pressure Vessel Code requirements and applicable procedures. The qualifications of all nondestructive examination technicians performing the inspections were verified to be current.

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

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

Welding Line # SI 1106, Weld # HFW0149 LA Safety Injection FLEX Modification tie-in to Safety Manual Gas Tungsten Arc System Injection System - Train A.

Welding Line # SI 1106, Weld # HFW0190 Safety Injection FLEX Modification tie-in to Safety Manual Gas Tungsten Arc System Injection System - Train B.

Welding Line # SI 1206, Weld # HFW0177 Safety Injection FLEX Modification tie-in to Safety Manual Gas Tungsten Arc System Injection System - Train B.

Welding Line # SI 1206, Weld # HFW0191 Auxiliary Feedwater FLEX Modification tie-in to Safety Manual Gas Tungsten Arc System Injection System - Train B.

Welding Line # AF 1077, Weld #

HFW0184 Auxiliary Feedwater FLEX Modification tie-in to Safety Manual Gas Tungsten Arc System Injection System - Train B.

Welding Line # AF 1077, Weld #

HFW0185 The inspectors reviewed records of the following welding activities:

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

Welding Line # SI 1101, Weld # HFW0097 Safety Injection FLEX Modification tie-in to Safety Manual Gas Tungsten Arc System Injection System - Train B.

Welding Line # SI 1201, Weld # HFW0097 Auxiliary Feedwater FLEX Modification tie-in to Safety Manual Gas Tungsten Arc System Injection System - Train B.

Welding Line # AF 1077, Weld #

HFW0190 Auxiliary Feedwater FLEX Modification tie-in to Safety Manual Gas Tungsten Arc System Injection System - Train B.

Welding Line # AF 1014, Weld #

HFW0198 Auxiliary Feedwater FLEX Modification tie-in to Safety Manual Gas Tungsten Arc System Injection System - Train B.

Welding Line # AF 1014, Weld #

HFW0199 Auxiliary Feedwater FLEX Modification tie-in to Safety Manual Gas Tungsten Arc System Injection System - Train C.

Welding Line # AF 1079, Weld #

HFW0191 Auxiliary Feedwater FLEX Modification tie-in to Safety Manual Gas Tungsten Arc System Injection System - Train C.

Welding Line # AF 1079, Weld #

HFW0192 Auxiliary Feedwater FLEX Modification tie-in to Safety Manual Gas Tungsten Arc System Injection System - Train C.

Welding Line # AF 1079, Weld #

HFW0197 Auxiliary Feedwater FLEX Modification tie-in to Safety Manual Gas Tungsten Arc System Injection System - Train C.

Welding Line # AF 1047, Weld #

HFW0204 Auxiliary Feedwater FLEX Modification tie-in to Safety Manual Gas Tungsten Arc System Injection System - Train B.

Welding Line # AF 1047, Weld #

HFW0205 The inspectors verified, by review, that the welding procedure specifications and the welders had been properly qualified in accordance with ASME Code,Section IX requirements. The inspectors also verified through record review that essential variables for the welding process were identified, recorded in the procedure qualification record, and formed the bases for qualification of the welding procedure specifications. Specific documents reviewed during this inspection are listed in the attachment.

b. Findings

No findings were identified.

.2 Vessel Upper Head Penetration Inspection Activities

a. Inspection Scope

During South Texas Project Refueling Outage 1RE19, there was no visual examination of the reactor pressure vessel head performed. In compliance with ASME Code Case N-729-1, Alternative Examination Requirements for PWR Reactor Vessel Upper Heads With Nozzles Having Pressure-Retaining Partial-Penetration WeldsSection XI, Division 1, Table 1 requires licensees that have new reactor heads with nozzles and partial-penetration welds of primary water stress corrosion cracking-resistant materials to perform a 100 percent inspection every third refueling outage or 5 calendar years, whichever is less. The licensee last inspected the Unit 1 reactor pressure vessel head in March 2014.

b. Findings

No findings 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 walk-down as specified in Procedure 0PGP03-ZE-0133, Boric Acid Corrosion Control Program, Revision 9, 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 walk-downs of portions of the following areas: residual heat removal pump rooms, safety injection pump rooms, reactor pressure vessel hot and cold leg nozzles, and reactor vessel bottom mounted instrument penetrations. 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 were identified.

.4 Steam Generator (SG) Tube Inspection Activities

a. Inspection Scope

The inspectors reviewed the steam generator tube eddy current (ECT) examination scope and expansion criteria to determine whether these criteria met technical specification requirements, EPRI guidelines, and commitments made to the NRC.

The inspectors also reviewed whether the ECT inspection scope included areas of degradations that were known to represent potential ECT test challenges such as the top of tube sheet, tube support plates, and U-bends. The inspectors confirmed that no repairs were required at the time of the inspection.

The scope of the licensees ECT examinations included:

• Full length bobbin inspection of the outer three peripheral tubes from tube end to tube end, including 10 tubes inwards into the no-tube lane from the periphery

• Fifty percent full length bobbin inspection of all tubes. Scope shall include all remaining tubes not inspected full length during 1RE13

• Twenty percent +point probe inspection of the upper tube sheet plate hot leg to upper tube sheet plate cold leg on rows 1 and 2 (U-bends)

• Twenty percent +point probe inspection of tube sheet hot leg +6 inches/-3 inches

• +Point probe inspection of outer three tubes of periphery and divider lane top of tube sheet

• +6 inches/-3 inches to aid in loose parts detection (hot leg and cold leg)

• >Twenty percent +point probe sample inspection of tube sheet hot leg

+6 inches/-16 inches in tube with bulges and over expansions. This includes 65 in SG A, 18 in SG B, 5 in SG C, and 7 in SG D The primary side inspection also includes the following special interest scope:

• +Point probe inspection of all previously identified dents and dings >5 volts

• +Point probe inspection of all prior and 1RE19 I-code and/or non-quantifiable indications as determined by bobbin inspection or any previously reported signal that has changed

• +Point probe inspection of possible loose parts in the ECT database as identified by previous ECT inspections

• +Point probe inspection of all observed loose parts as identified by previous secondary side video inspections and not removed

• +Point probe inspection of a minimum two tube locations surrounding any new possible loose parts or foreign object identified in 1RE16

• Video inspection of all installed plugs Inspection scope of the secondary side of the SGs for 1RE19 includes the following:

• Top of tube sheet foreign object search and retrieval in all four SGs including annulus and tube lane

• Top of tube sheet in-bundle foreign object search and retrieval as follows:

• SG 1A inspect every fourth column both hot leg and cold leg

• SG 1B inspect every fourth column both hot leg and cold leg

• SG 1C inspect every fourth column both hot leg and cold leg

• SG 1D inspect every second column both hot leg and cold leg

• Ultra sludge lancing on all four SGs

• Sludge collector inspection and cleaning (if required based on inspection) in SG 1A. The sludge collectors will only be cleaned if more than 0.5 inch of sludge is seen

• Steam drum inspection in SG 1A and 1B

• Upper steam drum inspection of SG 1A

• Foreign object search and retrieval of all possible

b. Findings

No findings were identified.

.5 Identification and Resolution of Problems

a. Inspection Scope

The inspectors reviewed 54 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.

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 October 12, 2015, the inspectors observed simulator just-in-time training for an operating crew in preparation for the Unit 1, 1RE19 Refueling Outage. 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 just-in-time training activities.

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 October 17, 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 shutting down the reactor for Refueling Outage 1RE19.

In addition, the inspectors assessed the operators adherence to plant procedures, including 0POP03-ZG-0006, Plant Shutdown From 100% to Hot Standby, Revision 61, 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.

.3 Biennial Review

a. Inspection Scope

The licensed operator requalification program involves two training cycles that are conducted over a 2-year period. In the first cycle, the annual cycle, the operators are administered an operating test consisting of job performance measures and simulator scenarios. In the second part of the training cycle, the biennial cycle, operators are administered an operating test and a comprehensive written examination.

To assess the performance effectiveness of the licensed operator requalification program, the inspectors reviewed both the written examination and operating test quality, and observed licensee administration of an annual requalification test while on site. The operating tests observed included five job performance measures and two scenarios that were used in the current biennial requalification cycle. These observations allowed the inspectors to assess the licensee's effectiveness in conducting the operating test to ensure operator mastery of the training program content and to determine if feedback of performance analyses into the requalification training program was being accomplished.

On December 23, 2015, the licensee informed the inspectors of the completed cycle results for Units 1 and 2, for both the written examinations and the operating tests:

• Thirteen of fifteen crews passed the simulator portion of the operating test

• Eighty-three of eighty-five licensed operators passed the simulator portion of the operating test

• Eighty-five of eighty-five licensed operators passed the job performance measure portion of the operating test

• Eighty-two of eighty-five licensed operators passed the written examination The individuals that failed any portion of the exam were remediated, retested, and passed their retake examinations. Two operators have not completed their examinations due to extended medical leave, and their licenses have been placed in a suspended status pending completion of missed training and the requalification examinations.

The inspectors observed examination security measures in place during administration of the examinations (including controls and content overlap) and reviewed remedial training and re-examinations, as available. The inspectors also reviewed medical records of 12 licensed operators for conformance to license conditions and the licensees system for tracking qualifications and records of license reactivation for five operators.

The inspectors reviewed simulator performance for fidelity with the actual plant and the overall simulator program of maintenance, testing, and discrepancy correction.

The inspectors completed one inspection sample of the biennial licensed operator requalification program.

b. Findings

Failure to Track and Incorporate Actual Plant Data into Simulator Operability Testing

Introduction.

The inspectors identified a Green finding associated with simulator operability testing for the failure of the licensee to track and incorporate actual plant data into their cyclic operability tests, as required by American National Standards Institute (ANSI)-3.5-2009, Nuclear Power Plant Simulators for Use in Operator Training and Examination. With the exception of one transient, the licensee exclusively used engineering analysis from the RETRAN code as baseline data without reference to plant events that may have been related to the required transient tests.

Description.

During the week of September 14, 2015, while performing a biennial requalification inspection in accordance with Inspection Procedure 71111.11, Licensed Operator Requalification Program, the inspectors reviewed the baseline data sources used to evaluate simulator operability testing. South Texas Projects Simulator Configuration Control Procedure (0PNT01-ZA-0037), Section 4.5.5.2, requires that each fuel cycle, benchmark transient tests shall be conducted as delineated in ANSI-3.5-2009.

Section B.3.2 of ANSI-3.5-2009 lists 11 transient performance tests that must be performed such as a manual reactor trip, reactor coolant pump trip, maximum design load rejection, and others. Section 5.1.1 of ANSI-3.5-2009 requires that the baseline data against which the simulator is compared shall be used in the following order of preference: 1) actual plant data, 2) engineering analysis, 3) similar plant data, and 4) subject matter expert estimates. Contrary to this standard, South Texas Project cyclic simulator operability testing exclusively used engineering analysis from the RETRAN code without reference to plant events that may be related to the transients (with the exception of the manual reactor trip transient, for which South Texas Project had appropriately demonstrated equivalency with a 2002 plant event). The station does perform post-event simulator testing as required following actual plant events, but this is one-time testing that is not repeated, in contrast with cyclic operability testing which is repeated after each fuel load. Because the station was not actively incorporating plant data into cyclic simulator operability testing at the time of the sample, the station was unable to provide a list of relevant plant events that might qualify as baseline data.

This issue was entered into the licensees corrective action program as Condition Report 15-21463.

South Texas Projects Simulator Configuration Control Procedure (0PNT01-ZA-0037),

Section 4.5.5.2, requires that each fuel cycle, benchmark transient tests shall be conducted as delineated in ANSI-3.5-2009. Section 5.1.1 of ANSI-3.5-2009 requires that the baseline data against which the simulator is compared shall be used in the following order of preference: 1) actual plant data, 2) engineering analysis, 3) similar plant data, and 4) subject matter expert estimates. Contrary to the above, the licensee failed to actively track and incorporate actual plant data into cyclic simulator operability testing, instead relying on engineering analysis exclusively. This issue was entered into the licensees corrective action program as Condition Report 15-21463.

Analysis.

The failure to track and incorporate plant events into baseline data for simulator operability testing is a performance deficiency. It is more than minor and, therefore, a finding because it is associated with the human performance attribute of the Mitigating Systems Cornerstone and negatively affected the objective to ensure the reliability and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, if simulator performance is not being compared to the most relevant baseline data from the plant, the reliability of the simulator performance is reduced. Using Inspection Manual Chapter 0609, Significance Determination Process, Phase 1 worksheets, and the corresponding Appendix I, Licensed Operator Requalification SDP (block 14), the finding was determined to have very low safety significance (Green) because it is a Simulator testing, maintenance, or modification deficiency. This finding has a cross-cutting aspect in the procedure adherence component of the human performance cross-cutting area because the licensee failed to ensure that individuals follow processes, procedures, and work instructions in that the ANSI-3.5-2009 guidance for selecting baseline data for simulator testing was not followed [H.8].

Enforcement.

This finding does not involve enforcement action because no violation of a regulatory requirement was identified. Because this finding does not involve a violation and is of very low safety or security significance, it is identified as FIN 05000498/2015004-01; 05000499/2015004-01-01, Failure to Track and Incorporate Actual Plant Data into Simulator Operability Testing.

1R12 Maintenance Effectiveness

a. Inspection Scope

The inspectors reviewed one instance of degraded performance or condition of safety-related SSCs:

• December 28, 2015, periodic assessment of the effectiveness of Maintenance Rule activities from February 2014 through March 2015 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 one maintenance effectiveness sample, 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 three 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:

• October 7, 2015, Unit 2, train C, 125-Vdc battery breaker E2C-11 replacement, which required the licensee to enter the Configuration Risk Management Program

• October 8, 2015, installation of corona balls on the shunt reactor in the switchyard on the south bus, which required isolating the Unit 2 standby transformer

• October 16, 2015, Unit 1, train B high head safety injection pump replacement, which required the licensee to enter the 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 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.

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 activity listed above.

These activities constitute completion of three maintenance risk assessments 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 five operability determinations that the licensee performed for degraded or nonconforming SSCs:

• October 13, 2015, operable but degraded determination of the Unit 1 qualified data processing system upon discovery of a drifting circuit board

• October 15, 2015, operability determination of Unit 1, train B containment spray following the discovery of an air void during fill and vent activity for the system

• November 5, 2015, operable but degraded determination of Unit 1, train A emergency safeguards features sequencer following essential chiller 12A starting time outside surveillance acceptance criteria

• December 28, 2015, operability determination of Unit 1 reactor vessel water level system, train A, following failure of a sensor

• December 31, 2015, the inspectors performed an in-depth follow-up of the Units 1 and 2 cumulative effects of operator workarounds, operator burdens, and control board items to determine the reliability, availability, and potential for incorrect operation of systems or components 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.

The inspectors reviewed operator actions taken or planned to compensate for degraded or nonconforming conditions. The inspectors verified that the licensee effectively managed these operator workarounds to prevent adverse effects on the function of mitigating systems and to minimize their impact on the operators ability to implement abnormal and emergency operating procedures.

These activities constitute completion of five operability review samples, which included one operator work-around sample, as defined in Inspection Procedure 71111.15.

b. Findings

No findings were identified.

1R18 Plant Modifications

.1 Temporary Modifications

a. Inspection Scope

On November 2, 2015, the inspectors reviewed a temporary modification for Unit 1 temporary power to spent fuel pool cooling pump 1B during Refueling Outage 1RE19.

The inspectors verified that the licensee had installed and removed this temporary modification 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 constitute 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:

• December 23, 2015, Unit 1, removal of electrical power, removal of position indication, and modification of plant computer point for the physical removal of control rod D6 from the reactor for operating cycle 20

• December 23, 2015, Unit 1, installation of a flow restrictor at the top of the guide tube in the upper internals, and a partial length guide tube restrictor in the fuel bundle due to the physical removal of control rod D6 and its drive shaft for operating cycle 20 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 of the SSCs as modified.

These activities constitute 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 five post-maintenance testing activities that affected risk-significant SSCs:

• October 15, 2015, Unit 1, train B high head safety injection pump following pump replacement

• November 1, 2015, Unit 1, technical support diesel and load center 1W following supply breaker maintenance

• November 3, 2015, Unit 1, reactor coolant pump 1A seal injection containment isolation valve MOV-33A following stem nut replacement

• November 3, 2015, Unit 1, reactor coolant pump 1C seal injection containment isolation valve MOV-33C following stem nut replacement

• December 21, 2015, Unit 2, train A essential chiller 22a outlet line following flange replacement due to material de-alloying 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 five post-maintenance testing inspection samples, as defined in Inspection Procedure 71111.19.

b. Findings

No findings were identified.

1R20 Refueling and Other Outage Activities

.1 Unit 1 Refueling Outage 1RE19

a. Inspection Scope

During the stations Refueling Outage 1RE19 that concluded on December 20, 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 of the licensees outage plan prior to the outage

• Review and verification of the licensees fatigue management activities

• Monitoring of shutdown and cooldown 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 heatup 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.

.2 Forced Outage

a. Inspection Scope

During the stations forced outage that began on December 21, 2015, and concluded on December 25, 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 of the licensees outage plan following the reactor trip

• Review and verification of the licensees fatigue management activities

• Monitoring of shutdown activities

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

• Monitoring of startup activities These activities constitute completion of one outage activities sample, as defined in Inspection Procedure 71111.20.

b. Findings

No findings were identified.

1R22 Surveillance Testing

a. Inspection Scope

The inspectors observed five 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:

• October 22, 2015, Unit 1, train C low head safety injection comprehensive pump test

• October 22, 2015, Unit 1, train B high head safety injection comprehensive pump test and pump curve measurement Containment isolation valve surveillance tests:

• October 23, 2015, Unit 1, safety injection system, train A, local leak rate test of penetration M-18, check valve 1-SI-0005A Reactor coolant system leak detection tests:

• November 12, 2015, Unit 1, reactor coolant inventory leak rate Other surveillance tests:

• October 21, 2015, Unit 1, train A emergency diesel generator load reject and safety injection auto-start tests 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 five surveillance testing inspection samples, as defined in Inspection Procedure 71111.22.

b. Findings

No findings were identified.

1EP2 Alert and Notification System Evaluation

a. Inspection Scope

The inspector verified the adequacy of the licensees methods for testing the primary and backup alert and notification system (ANS). The inspector interviewed licensee personnel responsible for the maintenance of the primary ANS and reviewed a sample of corrective action system reports written for ANS problems. The inspector compared the licensees alert and notification system testing program with criteria in NUREG-0654, Criteria for Preparation and Evaluation of Radiological Emergency Response Plans and Preparedness in Support of Nuclear Power Plants, Revision 1; South Texas Project Electric Generating Station Updated Prompt Notification System Design Report, September 30, 2010; and Updated Prompt Notification System Design Report, June 6, 2013. Other documents reviewed are listed in the attachment to this report.

These activities constituted completion of one alert and notification system evaluation sample, as defined in Inspection Procedure 71114.02.

b. Findings

No findings were identified.

1EP3 Emergency Response Organization Staffing and Augmentation System

a. Inspection Scope

The inspector verified the licensees emergency response organization (ERO) on-shift and augmentation staffing levels were in accordance with the licensees emergency plan commitments. The inspector reviewed documentation and discussed with licensee staff the operability of primary and backup systems for augmenting the on-shift emergency response staff to verify the adequacy of the licensees methods for staffing emergency response facilities, including the licensees ability to staff pre-planned alternate facilities.

The inspector also reviewed records of ERO augmentation tests and events to determine whether the licensee had maintained a capability to staff emergency response facilities within emergency plan timeliness commitments.

These activities constitute completion of one emergency response organization staffing and augmentation testing sample, as defined in Inspection Procedure 71114.03.

b. Findings

No findings were identified.

1EP4 Emergency Action Level and Emergency Plan Changes

a. Inspection Scope

The inspector performed an on-site review of the following emergency plan implementing procedures:

• 0ERP01-ZV-IN02, Notifications to Offsite Agencies, Revision 31

• 0ERP01-ZV-IN02, Notifications to Offsite Agencies, Revision 32

• 0ERP01-ZV-IN07, Offsite Protective Action Recommendations, Revision 14

• 0ERP01-ZV-IN07, Offsite Protective Action Recommendations, Revision 15

• 0ERP01-ZV-TP01, Offsite Dose Calculations, Revision 24

• 0ERP01-ZV-TP01, Offsite Dose Calculations, Revision 25 These revisions implemented new administrative instructions because of program or software changes, form updates, and editorial corrections.

Additionally, the inspector reviewed emergency plan change:

• South Texas Project Electric Generating Station Emergency Plan, Revision ICN 20-17 This revision corrected Section C.4 of the plan to state that the augmentation start time for activation of the ERO is from the time of declaration of an event and not from the time of notification to the ERO.

These revisions were compared to previous revisions, to the criteria of NUREG-0654, Criteria for Preparation and Evaluation of Radiological Emergency Response Plans and Preparedness in Support of Nuclear Power Plants, Revision 1, and to the standards in 10 CFR 50.47(b) to determine if the revision adequately implemented the requirements of 10 CFR 50.54(q)(3) and 50.54(q)(4). The inspector verified that the revisions did not reduce the effectiveness of the emergency plan. This review was not documented in a safety evaluation report and did not constitute approval of licensee-generated changes; therefore, the revisions are subject to future inspection.

These activities constitute completion of seven emergency action level and emergency plan changes samples, as defined in Inspection Procedure 71114.04.

b. Findings

No findings were identified.

1EP5 Maintenance of Emergency Preparedness

a. Inspection Scope

The inspector reviewed samples of the following documents for the period of June 2013 to November 2015:

• After-action evaluation reports for licensee drills and exercises

• Independent audits and surveillances of the licensees emergency preparedness program

• Self-assessments of the emergency preparedness program conducted by the licensee

• Licensee evaluations of changes made to the emergency plan and emergency plan implementing procedures

• Drill and exercise performance issues entered into the licensees corrective action program

• Emergency preparedness program issues entered into the licensees corrective action program

• ERO and emergency planner training records The inspector reviewed summaries of corrective action program reports associated with emergency preparedness and selected 19 to review against program requirements to determine the licensees ability to identify, evaluate, and correct problems in accordance with planning standard 10 CFR 50.47(b)(14) and 10 CFR Part 50, Appendix E, IV.F. The inspector verified that the licensee accurately and appropriately identified and corrected emergency preparedness weaknesses during critiques and assessments.

These activities constitute completion of one sample of the maintenance of the licensees emergency preparedness program, as defined in Inspection Procedure 71114.05.

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 Mitigating Systems Performance Index: Heat Removal Systems (MS08)

a. Inspection Scope

The inspectors reviewed the licensees mitigating system performance index data for the period of April 2014 through September 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 mitigating system performance index for heat removal systems for Unit 1 and Unit 2, as defined in Inspection Procedure 71151.

b. Findings

No findings were identified.

.2 Mitigating Systems Performance Index: Residual Heat Removal Systems (MS09)

a. Inspection Scope

The inspectors reviewed the licensees mitigating system performance index data for the period of April 2014 through September 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 mitigating system performance index for residual heat removal systems for Unit 1 and Unit 2, as defined in Inspection Procedure 71151.

b. Findings

No findings were identified.

.3 Mitigating Systems Performance Index: Cooling Water Support Systems (MS10)

a. Inspection Scope

The inspectors reviewed the licensees mitigating system performance index data for the period of April 2014 through September 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 mitigating system performance index for cooling water support systems for Unit 1 and Unit 2, as defined in Inspection Procedure 71151.

b. Findings

No findings were identified.

.4 Drill/Exercise Performance (EP01)

a. Inspection Scope

The inspector reviewed the licensees evaluated exercises and selected drill and training evolutions that occurred between October 1, 2014, and September 30, 2015, to verify the accuracy of the licensees data for classification, notification, and protective action recommendation opportunities. The inspector reviewed a sample of the licensees completed classifications, notifications, and protective action recommendations to verify their timeliness and accuracy. The inspector 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 data reported.

These activities constituted verification of the drill/exercise performance indicator, as defined in Inspection Procedure 71151.

b. Findings

No findings were identified.

.5 Emergency Response Organization Drill Participation (EP02)

a. Inspection Scope

The inspector reviewed the licensees records for participation in drill and training evolutions between October 1, 2014, and September 30, 2015, to verify the accuracy of the licensees data for drill participation opportunities. The inspector verified that all members of the licensees ERO in the identified key positions had been counted in the reported performance indicator data. The inspector reviewed the licensees basis for reporting the percentage of ERO members who participated in a drill. The inspector reviewed drill attendance records and verified a sample of those reported as participating. The inspector 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 data reported.

These activities constituted verification of the emergency response organization drill participation performance indicator, as defined in Inspection Procedure 71151.

b. Findings

No findings were identified.

.6 Alert and Notification System Reliability (EP03)

a. Inspection Scope

The inspector reviewed the licensees records of ANS tests conducted between October 1, 2014, and September 30, 2015, to verify the accuracy of the licensees data for siren system testing opportunities. The inspector reviewed procedural guidance on assessing ANS opportunities and the results of periodic ANS operability tests. The inspector 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 data reported.

These activities constituted verification of the alert and notification system reliability 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 health reports, list of essential cooling water leaks, condition reports associated with the main cooling reservoir, outage performance indications, hot work activities, outstanding work orders, and other documentation to identify trends that might indicate the existence of a more significant safety issue. The inspectors also interviewed licensee personnel. 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 The inspectors review of the possible trends noted above produced the following observations and assessments:

• Hot work performance was a focus item for the licensee as well as the resident inspectors in the last half of the year. The licensee has developed a procedure that is specifically for hot work, has conducted training, and provided extra oversight in the field. The licensee has improved performance although, the resident inspectors continued to note deficiencies in this area.

• The residents and the site have identified a number of maintenance issues associated with the main cooling reservoir. Some of the issues include vegetation control in and around the reservoir, relief well washout, outfall piping elevation drop, and piezometer protection piping damaged. The licensee is having an assessment from an outside consultant to help prioritize and correct the issues. The resident inspectors toured the main cooling reservoir and do not currently have an operability concern.

• The residents have noted several essential cooling water leaks (aluminum-bronze)which were shared with the licensee. The number of noted leaks and condition reports have not identified any trends as the licensee normally identifies 2-3 leaks per year and promptly corrects the issues by replacing the piping as necessary.

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:

• On December 7, 2015, the inspectors reviewed a discrepancy between the emergency plan and the safety evaluation report.

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 bring the emergency plan back into compliance with the safety evaluation report.

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

b. Findings

Failure to Maintain the Emergency Plan

Introduction:

The inspectors identified a Green non-cited violation of 10 CFR 50.54(q)(2)for failure to maintain the emergency plan. Specifically, the licensee failed to meet 10 CFR 50.47(b)(2) requirements for timely augmentation of response capabilities, in accordance with the approved safety evaluation report.

Description:

During review of a license amendment request, dated October 6, 2015, regarding the site emergency plans staff augmentation response times, NRC staff noted a discrepancy between the current site emergency plan and the approved safety evaluation report. The licensee submitted an earlier license amendment request dated November 3, 1992, the purpose of which was to increase the ERO staff augmentation times by 15 minutes. This changed staff augmentation times from 45 minutes (for radiation protection technicians and nuclear engineers) and 60 minutes (for other staff)to 60 minutes and 75 minutes respectively. The license amendment request stated that these times were following an emergency declaration. Prior to this change, the licensees emergency plan and the NRCs safety evaluation report required the licensees staff augmentation time requirements to begin following an emergency notification, which the licensee was satisfied with. On May 20, 1993, the NRC approved the licensees request for extending ERO staff augmentation response times following emergency declaration, and issued an updated safety evaluation report containing this change on the same date. The licensee updated the emergency plan to reflect the new ERO staff augmentation response times, but failed to update the emergency plan with the change for ERO staff augmentation time requirements from notification to declaration. Table C-1 of Section C of the emergency plan incorrectly stated that time requirements for ERO staff augmentation are from the time of an emergency notification vice the time of an emergency declaration. Failing to implement this change could delay ERO staff augmentation times by as much as 15 minutes causing the licensee to exceed the time requirements set forth by the safety evaluation report.

The licensee has demonstrated through unannounced off-hours activation drills and announced staff drills that a loss of timely ERO staff augmentation would not have occurred as a result of the emergency plan change from time of notification to time of declaration. This issue was entered into the licensees corrective action program as Condition Report 15-23835. As part of their corrective actions, the licensee updated the emergency plan to accurately show that ERO staff augmentation times are to commence at the time of an emergency declaration.

Analysis:

Failure to maintain the site emergency plan in accordance with the approved safety evaluation report, dated May 20, 1993, was a performance deficiency.

Specifically, the licensee failed to update the ERO staff augmentation time requirements to commence at the time of an emergency declaration, as required by the NRC safety evaluation report. This performance deficiency is more than minor because it is associated with the procedure quality attribute of the Emergency Preparedness Cornerstone and adversely affected the cornerstone objective to ensure that the licensee is capable of implementing adequate measures to protect the health and safety of the public in the event of a radiological emergency. This finding was evaluated using Inspection Manual Chapter 0609, Appendix B, Emergency Preparedness Significance Determination Process (SDP), dated September 22, 2015, and was determined to be of very low safety significance (Green) per Table 5.2-1, Significance Examples 50.47(b)(2), because the staffing processes do not meet the threshold of routinely not capable of ensuring timely augmentation of the on shift emergency response staff to the extent that more than one required ERO functional area (in accordance with E-plan commitments) would not be filled. No cross-cutting aspect is assigned because the performance deficiency is not indicative of present performance.

Enforcement:

Title 10 CFR 50.54(q)(2) requires, in part, that a holder of a nuclear power reactor operating license shall follow and maintain in effect emergency plans which meet the requirements in Appendix E, part 50, and for nuclear power reactor licensees, the planning standards of 10 CFR 50.47(b). Title 10 CFR 50.47(b)(2) requires, in part, that timely augmentation of response capabilities is available. Contrary to the above, from May 20, 1993, until November 3, 2015, the licensee failed to ensure that timely augmentation of response capabilities was available. Specifically, a change to the safety evaluation report affecting the emergency plan was not appropriately implemented in that Table C-1 of Section C of the emergency plan was not updated to reflect ERO staff augmentation times are from the time of an emergency declaration vice the time of an emergency notification. The licensee restored compliance by revising the site emergency plan to require timely staff augmentation following an emergency declaration. The violation was entered into the licensees corrective action program as Condition Report 15-23835. Because the finding was of very low safety significance and has been entered into the licensees corrective action program, this violation is being treated as a non-cited violation consistent with Section 2.3.2.a of the NRC Enforcement Policy: (NCV 05000498/2015004-02; 05000499/2015004-02, Failure to Maintain the Emergency Plan Up to Date With the Safety Evaluation Report.)

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

.1 Event Follow-up for Excessive Leakage into a Waste Holding Tank

On November 13, 2015, while in Mode 3, following Refueling Outage 1RE19, Unit 1 experienced increased leakage into the chemical volume control system waste holding tank when a demineralizer was placed on service. Control room operators treated this excessive leakage as reactor coolant system leakage until the source of the leak could be identified and isolated. The licensee declared a Notice of Unusual Event (NOUE)based on Unidentified Reactor Coolant Boundary Leakage. Shortly after entering the NOUE Control room operators identified the leakage was coming from a chemical volume control system drain valve and isolated that valve. The inspectors responded to the control room and observed the licensees identification and resolution of the issue, including walking down the affected portion of the chemical and volume control system, reviewing operator logs, and interviewing operators. The licensee retracted the NOUE on December 08, 2015 because the source of the leak was from the chemical volume control system and not the reactor coolant system. Inspectors determined that the retraction was appropriate.

No findings were identified.

.2 Event Follow-up for Unit 1 Manual Turbine and Reactor Trip

On December 21, 2015, while Unit 1 was at 48 percent power, turbine governor valve 2 began to oscillate open and closed, resulting in large load swings and steam dump actuation. Operators began to reduce turbine load in order to stabilize the governor valve, but the oscillations continued. The shift manager directed a manual trip of the main turbine. Main turbine governor valve 2 continued to oscillate and the group one steam dumps failed to operate, as designed, to manage the main steam to the condenser on the turbine load reject. Main feedwater continued to fill the steam generators to the main feedwater isolation setpoint of 87.5 percent. All four steam generator power operated relief valves lifted as designed. Steam generator levels lowered, and with no ability to feed the steam generators to maintain levels, the shift manager ordered a manual reactor trip. All control rods fully inserted into the reactor core and all safety-related systems functioned as designed, with the exception of steam generator A blowdown containment isolation valve that failed to isolate on the main feedwater isolation.

The resident inspector responded to the control room upon hearing the load reduction plant announcement. The resident inspector observed all major evolutions and the operating crews performance, reviewed the licensees initial investigation and equipment repair prior to starting up the reactor. The inspectors also reviewed the initial licensee notification to verify it met the requirements specified in NUREG-1022, Event Reporting Guidelines, Revision 3.

No findings were identified.

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

4OA6 Meetings, Including Exit

Exit Meeting Summary

On November 5, 2015, the inspectors presented the in-service 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 November 19, 2015, the inspector presented the results of the on-site inspection of the emergency preparedness program to Mr. D. Rencurrel, Senior Vice President, Operations, 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 December 10, 2015, the inspectors presented the final triennial heat sink inspection results to Mr. D. Rencurrel, Senior Vice President, Operations, and Mr. G. Powell, Site Vice President, and other members of the licensee staff. The licensee acknowledged the issues presented.

The inspector asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identified.

The inspectors briefed Mr. G. Powell, Site Vice President, and other members of the licensee's staff of the preliminary results of the licensed operator requalification program inspection on September 17, 2015. The inspectors conducted a telephonic exit meeting with Mr. G. Janak, Operations Training Manager, and other members of the licensees staff on January 4, 2016. The licensee representatives acknowledged the findings presented. The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identified.

On January 7, 2016, the inspectors presented the resident inspection results to Mr. G. Powell, 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.

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

R. Aguilera, Manager, Health Physics

P. Alier, Systems Engineering

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 III

A. Capristo, Executive Vice President and Chief Administrative Officer

D. Caraballo, Systems Engineering

J. Connolly, General Manager, Engineering

M. Crain, Manager, Emergency Response

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

J. Enoch, Supervisor, Emergency Response

T. Frawley, Manager, Plant Protection/Emergency Response

C. Gann, Manager, Employee Concerns Program

M. Garner, Nondestructive Examination Examiner

R. Gibbs, Manager, Operations, Production Support

R. Gonzales, Senior Licensing Engineer

J. Hartley, Manager, Mechanical Maintenance

J. Heil, TPE Engineer, Programs

G. Hildebrandt, Manager, Operations

K. Hilscher, Manager, Training

S. Horak, Emergency Response Department

R. Hubenak, Supervisor, Licensed Operator Requalification

T. Hurley, Supervisor, Simulator Support

D. Janak, Systems Engineering

G. Janak, Operations Training Manager

D. Koehl, President and CEO

S. Korenek, Emergency Response Department

J. Lovejoy, Manager, I&C Maintenance

R. McNeil, Manager, Maintenance Engineering

B. Migl, Supervisor, Testing and Programs

J. Milliff, Manager, Security

M. Murray, Manager, Regulatory Affairs

R. Nieman, Site Authorized Nuclear Inspector (ANII)

C. Pence, Manager, Chemistry

L. Peter, General Manager, Projects

J. Pierce, Manager, Unit 1 Operations

G. Powell, Site Vice President

F. Puleo, Licensing Staff Specialist

K. Regis, Design Engineering

D. Rencurrel, Senior Vice President, Operations

R. Richardson, Welding Engineer

S. Rodgers, Emergency Response Department

M. Ruvalcaba, Manager, Strategic Projects

Attachment 1

R. Savage, Engineer, Licensing Consult 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

S. Taylor, Emergency Response Department

J. Von Suskil, Owner Rep - NRG South Texas LP

T. Wacker, Engineer, Quality Programs

G. Wendel, Emergency Response Department

J. Williams, Engineer, Testing Programs

P. Williams, Boric Acid Corrosion Control Program Manager

C. Younger, Testing Programs

D. Zink, Supervising Engineering Specialist

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened and Closed

05000498/2015004-01 Failure to Track and Incorporate Actual Plant Data into FIN

05000499/2015004-01 Simulator Operability Testing (1R11.4)

05000498/2015004-02 Failure to Maintain the Emergency Plan Up to Date With the NCV

05000499/2015004-02 Safety Evaluation Report (4OA2.3)