IR 05000280/2015002

IR 05000280/2015002, 05000281/2015002; on 04/01/2015 - 06/30/2015; Surry Power Station, Units 1 and 2: Inservice Inspection Activities and Maintenance Effectiveness

ML15218A522
Person / Time
Site:	Surry
Issue date:	08/06/2015
From:	Steven Rose NRC/RGN-II/DRP/RPB5
To:	Heacock D Virginia Electric & Power Co (VEPCO)
References
IR 2015002
Download: ML15218A522 (50)

Text

August 6, 2015

SUBJECT:

SURRY POWER STATION - NRC INTEGRATED INSPECTION REPORT 05000280/2015002 AND 05000281/2015002

Dear Mr. Heacock:

On June 30, 2015, the United States Nuclear Regulatory Commission (NRC) completed an inspection at your Surry Power Station Units 1 and 2. On July 29, 2015, the NRC inspectors discussed the results of this inspection with Mr. R. Simmons 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.

These findings involved violations of NRC requirements. The NRC is treating these violations as non-cited violations (NCVs) consistent with Section 2.3.2.a of the NRC Enforcement Policy.

If you contest the violations or significance of these NCVs, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the Nuclear Regulatory Commission, ATTN.: Document Control Desk, Washington DC 20555-0001; with copies to the Regional Administrator Region II; the Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at the Surry Power Station.

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 II, and the NRC Resident Inspector at the Surry Power Station.

As a result of the Safety Culture Common Language Initiative, the terminology and coding of cross-cutting aspects were revised beginning in calendar year (CY) 2014. New cross-cutting aspects identified in CY 2014 will be coded under the latest revision to IMC 310. Cross-cutting aspects identified in the last six months of 2013 using the previous terminology will be converted to the lastest revision in accordance with the crosss-reference in IMC 0310. The revised cross-cutting aspects will be evaluated for cross-cutting themes and potential substantive cross-In accordance with Title 10 of the Code of Federal Regulations (CFR) 2.390, Public Inspections, Exemptions, Requests for Withholding, of the NRCs Agency Rules of Practice and Procedure, 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 NRCs 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/

Steven D. Rose, Chief

Reactor Projects Branch 5

Division of Reactor Projects

Docket Nos.: 50-280, 50-281 License Nos.: DPR-32, DPR-37

Enclosure:

IR 05000280/2015002, 05000281/2015002 w/Attachment: Supplementary Information

REGION II==

Docket Nos.:

50-280, 50-281

License Nos.:

DPR-32, DPR-37

Report No:

05000280/2015002, 05000281/2015002

Licensee:

Virginia Electric and Power Company (VEPCO)

Facility:

Surry Power Station, Units 1 and 2

Location:

5850 Hog Island Road

Surry, VA 23883

Dates:

April 1, 2015 through June 30, 2015

Inspectors:

P. McKenna, Senior Resident Inspector C. Jones, Resident Inspector B. Collins, Reactor Inspector (1R08)

R. Hamilton, Senior Health Physicist (2RS6, 2RS7)

R. Kellner, Senior Health Physicist (2RS6, 2RS7)

G. Kolcum, Senior Resident Inspector North Anna (1R04, 1R05, 4OA2)

A. Sengupta, Reactor Inspector (1R08, 4OA5)

Approved by:

Steven D. Rose, Chief Reactor Projects Branch 5 Division of Reactor Projects

SUMMARY

IR 05000280/2015002, 05000281/2015002; 04/01/2015-06/30/2015; Surry Power Station,

Units 1 and 2: Inservice Inspection Activities and Maintenance Effectiveness

The report covered a three-month period of inspection by resident inspectors and region-based inspectors. Inspectors identified two non-cited violations (NCVs) of very low safety significance.

The significance of most findings is indicated by their color (Green, White, Yellow, Red) using Inspection Manual Chapter (IMC) 0609, Significance Determination Process (SDP), dated April 29, 2015. The cross-cutting aspects were determined using IMC 0310, Components Within The Cross-Cutting Areas, dated December 4, 2014. All violations of NRC requirements are dispositioned in accordance with the NRCs 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.

A self-revealing NCV of Surry Technical Specification (TS) 6.4.D was identified because the Unit 1 A motor driven auxiliary feedwater (MDAFW) pump motor outboard bearing thermocouple was improperly installed while installing a new motor on the MDAFW pump in November, 2013. The improper thermocouple installation in the bearing caused the bearing to fail while the pump was running on January 5, 2015. This issue was documented in the licensees corrective action program (CAP) as condition report (CR) 568663.

The inspectors concluded that the failure of the licensee to use a procedure to remove and reinstall the A MDAFW pump motor thermocouples was a performance deficiency (PD).

Using Manual Chapter 0612, Appendix B, Issue Screening, dated September 7, 2012, the inspectors determined that the PD was more than minor because it was associated with the human performance attribute of the Mitigating Systems Cornerstone, and it adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the incorrect installation of the motor outboard bearing thermocouple eventually damaged the bearing and caused the A MDAFW pump to become inoperable. Using Manual Chapter 0609.04, Initial Characterization of Findings, dated June 19, 2012, the finding was determined to affect the Mitigating Systems Cornerstone. The inspectors screened the finding using IMC 0609, Appendix A, Significance Determination Process (SDP) for Findings at-Power, dated June 19, 2012, and determined that it screened as Green because the deficiency did not affect the design or qualification of the AFW system and it did not represent a loss of system safety function. This finding has a cross-cutting aspect in the Challenge the Unknown aspect of the human performance area, H.11, because the individuals involved in removing and installing the thermocouples did not stop when faced with a work order that did not have the appropriate procedure reference for the action they were taking. (Section 1R12)

Cornerstone: Barrier Integrity

Green.

An NRC-identified NCV of 10 CFR 50.55a, Codes and Standards, was identified for the licensees failure to conduct a detailed visual examination of the concrete-liner interface for the Unit 1 containment, per the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code (BPVC)Section XI, Subsection IWE 1241, Table IWE-2500-1, Category E-C, Item E 4.11. This issue was documented in the licensees CAP as CR 578448.

The licensees failure to conduct a detailed visual examination of the concrete-liner interface of the Units 1 and 2 containment in accordance with the ASME BPVC Section XI,

Subsection IWE 1241, Table IWE-2500-1, Category E-C, Item E 4.11, was a PD that was within the licensees ability to foresee and correct. Using Manual Chapter 0612, Appendix B, Issue Screening, dated September 7, 2012, the inspectors determined that the PD was more than minor because, if left uncorrected, it had the potential to lead to a more significant safety concern. Specifically, detailed visual inspections of the containment metallic liner provides assurance that the liner remains capable of performing its intended safety function, and in the absence of such inspections, corrosive conditions could progress to challenge that capability. Using Manual Chapter 0609.04, Initial Characterization of Findings, dated June 19, 2012, the finding was determined to affect the Barrier Integrity Cornerstone. The inspectors screened the finding using IMC 0609, Appendix A, Significance Determination Process (SDP) for Findings at-Power, dated June 19, 2012, and determined that the finding was of very low safety-significance (Green) because the finding did not represent an actual open pathway in the physical integrity of the reactor containment. The team determined that no cross cutting aspect was applicable to this performance deficiency because this finding was not indicative of current licensee performance. (Section 1R08)

REPORT DETAILS

Summary of Plant Status

Unit 1 operated at or near rated thermal power (RTP) from the beginning of the inspection period until April 19, 2015, when it was shutdown to begin a planned refueling outage (RFO). It remained offline until May 27, when the main turbine generator was synchronized to the grid.

On June 1, the unit reached full RTP and operated there for the remainder of the inspection period.

Unit 2 operated at or near RTP throughout the inspection period.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

==1R01 Adverse Weather Protection

==

.1 Review of Offsite Power and Alternate AC Power Readiness

a.

The inspectors verified that plant features, and procedures for operation and continued availability of offsite and alternate alternating current (AC) power systems were appropriate. The inspectors reviewed the licensees procedures affecting those areas, and the communications protocols between the transmission system operator and the nuclear power plant to verify that the appropriate information was exchanged when issues arose that could impact the offsite power system. The inspectors evaluated the readiness of the offsite and alternate AC power systems by reviewing the licensees procedures that address measures to monitor and maintain the availability and reliability of the offsite and alternative AC power systems.

b. Findings

No findings were identified.

.2 Seasonal Readiness Reviews for Hot Weather

a. Inspection Scope

The inspectors reviewed the licensees preparations for seasonal hot weather.

Inspection focused on verification of design features and implementation of the licensees procedure for hot weather conditions, 0-OSP-ZZ-003, Hot Weather Preparation, Revision 6. The inspectors walked down key structures (i.e, the turbine and auxiliary buildings, safeguards buildings, the emergency switchgear rooms, and emergency battery rooms) and verified heating, ventilation and air-conditioning (HVAC)systems were operating properly and that area temperatures remained within design requirements specified in the Updated Final Safety Analysis Report (UFSAR). The mitigating systems reviewed during this inspection include: the auxiliary feedwater systems, the refueling water storage tanks, emergency diesel generators, and emergency switchgear.

b. Findings

No findings were identified.

==1R04 Equipment Alignment

==

.1 Partial Walkdown

a. Inspection Scope

The inspectors conducted three equipment alignment partial walkdowns to evaluate the operability of selected redundant trains or backup systems, listed below, with the other train or system inoperable or out of service. The inspectors reviewed the functional systems descriptions, UFSAR, system operating procedures, and Technical Specifications (TS) to determine correct system lineups for the current plant conditions.

The inspectors performed walkdowns of the systems to verify that critical components were properly aligned and to identify any discrepancies which could affect operability of the redundant train or backup system.

• Emergency Diesel Generator (EDG) 1 after completion of a planned maintenance outage.

• Unit 1 Turbine Driven Auxiliary Feedwater (TDAFW) Pump after completion of planned maintenance.

• Unit 1 Containment Instrument Air (IA) system while the A containment IA train was out of service for unplanned maintenance.

b. Findings

No findings were identified.

.2 Complete Walkdown

a. Inspection Scope

The inspectors performed a detailed walkdown and inspection of the Unit 1 recirculation spray (RS) system including the service water (SW) supporting lineup to verify the systems were properly aligned and capable of performing their safety function, and to assess their material condition. During the walkdown, the inspectors verified breaker positions were in the proper alignment, component labeling was accurate, hangers and supports were functional, and local indications were accurate. Recent testing history was also reviewed to verify that standby components were performing within their design. The plant health report, system drawings, condition reports, the UFSAR, and TS were reviewed and outstanding deficiencies were verified to be properly classified and not affect system operability and capability to perform its safety function. The inspectors reviewed the corrective action program (CAP) to verify equipment alignment issues were being identified and resolved.

b. Findings

No findings were identified.

==1R05 Fire Protection

==

.1 Quarterly Fire Protection Reviews

a. Inspection Scope

The inspectors conducted tours of the five areas listed below that are important to reactor safety to verify the licensees implementation of fire protection requirements as described in fleet procedures CM-AA-FPA-100, Fire Protection/Appendix R (Fire Safe Shutdown) Program, Revision 10, CM-AA-FPA-101, Control of Combustible and Flammable Materials, Revision 8, and CM-AA-FPA-102, Fire Protection and Fire Safe Shutdown Review and Preparation Process and Design Change Process, Revision 5.

The reviews were performed to evaluate the fire protection program operational status and material condition and the adequacy of:

(1) control of transient combustibles and ignition sources;

(2) fire detection and suppression capability;

(3) passive fire protection features;

(4) compensatory measures established for out-of-service, degraded or inoperable fire protection equipment, systems, or features; and

(5) procedures, equipment, fire barriers, and systems so that post-fire capability to safely shutdown the plant is ensured. The inspectors reviewed the corrective action program to verify fire protection deficiencies were being identified and properly resolved.

• Unit 1 Safeguards and Valve Pit

• Unit 2 Safeguards and Valve Pit

• Technical Support Center

• Alternate AC Diesel Building

• Unit 1 Containment

b. Findings

No findings were identified.

1. Inspection Scope

The inspectors observed an unannounced fire drill on June 9, 2015, that took place in the Unit 2 normal switchgear room. The drill was observed to evaluate the readiness of the plant fire brigade to fight fires. The inspectors verified that the licensee staff identified deficiencies, openly discussed them in a self-critical manner at the debrief, and took appropriate corrective actions as required. Specific attributes evaluated were: (1)proper wearing of turnout gear and self-contained breathing apparatus;

(2) proper uses and layout of fire hoses;

(3) employment of appropriate firefighting techniques; (4)sufficient firefighting equipment brought to the scene;

(5) effectiveness of command and control;

(6) search for victims and propagation of the fire into other plant areas; (7)smoke removal operations;

(8) utilization of pre-planned strategies;

(9) adherence to the pre-planned drill scenario; and

(10) drill objectives.

2. Findings

No findings were identified.

==1R06 Flood Protection Measures

a. Inspection Scope

==

The inspectors reviewed the internal flood protection measures and procedural controls established to address potential flooding in the Unit 1 and 2 turbine buildings and the emergency switchgear rooms while design change SU-13-00012, Component Cooling Heat Exchanger (CCHX) Service Water (SW) Outlet Jumper, was installed during the Unit 1 RFO. This design change installed a temporary pipe and isolation valves downstream of the A and B CCHXs SW outlets in the Unit 1 turbine building to the Unit 2 main condenser outlet waterbox B located in the Unit 2 turbine building. The inspectors conducted a walk down of the affected areas to observe and assess the condition of the installed flood dikes, floor drain backflow preventers, the sealing of holes and penetrations between flood areas, the adequacy of water tight doors, the operability of flooding alarms, and the installed sump pumps. Additionally, the inspectors verified that the required compensatory actions required as part of the design change where being accomplished by the licensee.

b. Findings

No findings were identified.

==1R08 Inservice Inspection Activities

a. Inspection Scope

==

Non-Destructive Examination Activities and Welding Activities

From April 27, through May 1, 2015, the inspectors conducted an onsite review of the implementation of the licensees in-service inspection (ISI) program for monitoring degradation of the reactor coolant system (RCS) boundary, risk-significant piping and component boundaries, and containment boundaries in Unit 1.

The inspectors either directly observed or reviewed the following non-destructive examinations (NDEs), mandated by the American Society of Mechanical Engineers (ASME) boiler and pressure vessel code (BPVC) (Code of Record: 2004 Edition) to evaluate compliance with the ASME Code,Section XI and Section V requirements, and if any indications or defects were detected, to evaluate if they were dispositioned in accordance with the ASME Code or an NRC-approved alternative requirement. The code of record for the containment program is the 2001 Edition with 2003 Addenda. The inspectors also reviewed the qualifications of the NDE technicians performing the examinations to determine whether they were current, and in compliance with the ASME Code requirements.

• WO 38103517058, Ultrasonic Testing (UT), Safety Injection elbow-to-pipe weld 12-RC-22/1-08, 12-inch line from accumulator, Class 1 (observed)

• WO 38103423799, Visual Testing (VT), N-722-1 Bottom-Mounted Instrumentation Penetration Nozzle, Class 1 (reviewed)

• WO 38103423539, Penetrant Testing (PT), 01-CH-431-Valve, CVCS System, Class 1 (reviewed)

• WO 38103359485, PT, RCS Make Up Suction Connection on Containment Spray, Class 2 (reviewed)

• WO 38103359485, Radiography Testing (RT) RCS Make Up Suction Connection on Containment Spray, Class 2 (reviewed)

• WO 38103583329, UT, MRP-146 Thermal Fatigue B Cold Leg Drain Line, Class 1 (reviewed)

The inspectors either directly observed or reviewed the following welding activities, qualification records, and associated documents, in order to evaluate compliance with procedures, and the ASME Code,Section XI and Section IX requirements. Specifically, the inspectors reviewed the work order (WO), repair and replacement plan, weld data sheets, welding procedures, procedure qualification records, welder performance qualification records, and NDE reports.

• WO 38103533149, 01-RC-139 Pressurizer Spray Valve PCV-1455A Bypass, Class 1 (observed)

• WO 38103359485, RCS Make Up Suction Connection on Containment Spray, Class 2 (reviewed)

• WO 38103423539, 01-CH-431-Valve, chemical and volume control system (CVCS),

Class 1 (reviewed)

During non-destructive surface and volumetric examinations performed since the previous refueling outage, the licensee did not identify any relevant indications that were analytically evaluated and accepted for continued service; therefore, no NRC review was completed for this inspection procedure attribute.

Pressurized Water Reactor Vessel Upper Head Penetration Inspection Activities

The inspectors verified that for the Unit 1 vessel head, a bare metal visual examination and a volumetric examination were not required during this outage, in accordance with the requirements of ASME Code Case N-729-1 and 10 CFR 50.55a(g)(6)(ii)(D).

The licensee did not identify any relevant indications that were accepted for continued service. Additionally, the licensee did not perform any welding repairs to the vessel head penetrations since the beginning of the last Unit 1 refueling outage; therefore, no NRC review was completed for these inspection procedure (IP) attributes.

Boric Acid Corrosion Control Inspection Activities

The inspectors reviewed the licensees boric acid corrosion control (BACC) program activities to determine if the activities were implemented in accordance with the commitments made in response to NRC Generic Letter 88-05, Boric Acid Corrosion of Carbon Steel Reactor Pressure Boundary Components in PWR Plants, and applicable industry guidance documents. Specifically, the inspectors performed an onsite records review of procedures, and the results of the licensees containment walkdown inspections performed during the current refueling outage. The inspectors also interviewed the BACC program owner, conducted an independent walkdown of containment to evaluate compliance with licensee BACC program requirements, and verified that degraded or non-conforming conditions such as boric acid leaks, were properly identified and corrected in accordance with the licensees BACC, and the CAP.

The inspectors reviewed the following engineering evaluations completed for evidence of boric acid leakage, to determine if the licensee properly applied applicable corrosion rates to the affected components, and properly assessed the effects of corrosion-induced wastage on structural or pressure boundary integrity, in accordance with the licensee procedures.

• CR 530120, CA to Engineering to Initiate Required Actions of ASME XI IWA-5250

• CR 569758, Increase in 1-RC-PCV-1455 A Leakage

• CR 545699, Through-Wall Leak on 2-RC-MOV-2595 Packing Leak-Off Line

• CR 529746, Boric Acid on 1-RH-20 (Body to Bonnet)

• CR 530120, Boric Acid on 3/4 inch-CH-109-1502 (Flange) Piping between 1-RC-P-1C Seal & 1-CH-360

• CR 539354, RCS Leakby at 1-RC-ICV-3510 approximately 1 drop/10 sec

• CR 559138, 1-RC-PCV-1455A Boric Acid Buildup Not Being Contained by Spray Shield

The inspectors reviewed the following CRs and associated corrective actions (CAs)related to evidence of boric acid leakage, to evaluate if the corrective actions completed were consistent with the requirements of the ASME Code and 10 CFR Part 50, Appendix B, Criterion XVI.

• CR 578230, Excessive Dry, White Boric Acid Deposits on Containment Basement Floor

• CR 577242, 1-CH-433 Packing Leak

• CR 557322, Found Boric Acid Buildup on 1-RC-PCV-1455A PZR Spray Loop A

Steam Generator Tube Inspection Activities

The inspectors verified that for the Unit 1 steam generator (SG) B tubes, no inspection activities were required for this refueling outage, in accordance with the requirements of the ASME Code, the licensees TS, and Nuclear Energy Institute (NEI) 97-06, Steam Generator Program Guidelines.

The inspectors reviewed the eddy current (EC) examination activities performed in Unit 1 SGs A and C during current refueling outage, to verify compliance with the licensees TSs, ASME BPVC Section XI, and NEI 97-06, Steam Generator Program Guidelines.

The inspectors reviewed the scope of the EC examinations, and the implementation of scope expansion criteria, to verify that these were consistent with the Electric Power Research Institute (EPRI) Pressurized Water Reactor Steam Generator Examination Guidelines, Revision 7. The inspectors reviewed documentation for a sample of EC data analysts, probes, and testers to verify that personnel and equipment were qualified to detect the applicable degradation mechanisms, in accordance with the EPRI Examination Guidelines. This review included a sample of site-specific Examination Technique Specification Sheets (ETSSs) to verify that their qualification, and site-specific implementation were consistent with Appendix H or I of the EPRI Examination Guidelines. The inspectors also reviewed a sample of EC data for SG tubes A-R29C77, A-R33C63, A-R12C47, B-R39C23, and B-R35C17 with a qualified data analyst to confirm that data analysis, and equipment configuration, were performed in accordance with the applicable ETSSs and site-specific analysis guidelines. The inspectors verified that recordable indications were detected and sized in accordance with vendor procedures.

The inspectors selected a sample of degradation mechanisms from the Unit 1 Degradation Assessment report (i.e., anti-vibration bar wear), and verified that their respective in-situ pressure testing criteria were determined in accordance with the EPRI Steam Generator Integrity Assessment Guidelines, Revision 3. Additionally, the inspectors reviewed EC indication reports to determine whether tubes with relevant indications were appropriately screened for in-situ pressure testing. The inspectors also compared the latest EC examination results with the last Condition Monitoring and Operational Assessment report for Unit 1, to assess the licensees prediction capability for maximum tube degradation, and number of tubes with indications. The inspectors verified that the licensees evaluation was conservative, and that current examination results were bound by the operational assessment projections.

The inspectors assessed the latest EC examination results to verify that new degradation mechanisms, if any, were identified and evaluated before plant startup.

The review of EC examination results included the disposition of potential loose part indications on the SG secondary side, to verify that corrective actions for evaluating and retrieving loose parts were consistent with the EPRI Guidelines. The inspectors also reviewed a sample of primary-to-secondary leakage data for Unit 1, to confirm that operational leakage in each SG remained below the detection or action level threshold during the previous operating cycle.

The inspectors review included the implementation of tube repair criteria and repair methods, to verify they were consistent with plant TS and industry guidelines. The inspectors verified that the licensee had selected the appropriate tubes for plugging based on the required plugging criteria. The inspectors reviewed the tube plugging procedure, and a sample of tube plugging results for tube A-R29C77, to determine if the licensee installed the tube plugs in accordance with the applicable procedures.

Furthermore, the inspectors interviewed licensee staff and reviewed a sample of inspection results for the inspection conducted in the secondary side internals of SGs A and C, to verify that potential areas of degradation based on site-specific operating experience (OE) were inspected, and appropriate corrective actions were taken to address degradation indications. This review included the results of foreign object search and retrieval activities in both SGs, and an evaluation for a potential loose part in the secondary side of SG A.

Identification and Resolution of Problems

The inspectors reviewed a sample of ISI-related issues entered into the CAP to determine if the licensee had appropriately described the scope of the problem, and had initiated corrective actions. The review also included the licensees consideration and assessment of OE events applicable to the plant. The inspectors performed this review to ensure compliance with 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, requirements.

b. Findings

Introduction:

The NRC identified a Green NCV of 10 CFR 50.55a, Codes and Standards, for the licensees failure to conduct a detailed visual examination of the concrete-liner interface of the Unit 1 containment, per the ASME BPVC Section XI, Subsection IWE 1241, Table IWE-2500-1, Category E-C, Item E 4.11.

Description:

During an inspection of the Unit 1 containment as a part of the boric acid walkdown, the inspectors noted that licensee personnel were not conducting a detailed visual examination of the concrete-liner interface of the Unit 1 containment per the ASME Section XI, Subsection IWE 1241, Table IWE-2500-1, Category E-C, Item E 4.11.

The initial configuration for Unit 1 containment was a concrete containment with a steel containment liner, and a concrete basemat poured such that it was flush to the steel liner. No moisture barrier existed in the interface between the containment liner and the concrete basemat. In September 1996, the NRC added IWE requirements to 10CFR10.55a, and in 1998, the licensee implemented a general visual inspection of the accessible surface areas in accordance with Category E-A, Item E 1.12 of Table IWE-2500-1.

In 2003, NRC inspectors found degraded coatings and rust at the interface of the containment liner and the basemat for Unit 2 (NRC Inspection Report 50-281/2003-05, Adams Accession No. ML040280056). The interface between the concrete basemat and the containment liner is an area likely to experience accelerated degradation and aging, particularly without any moisture barrier installed. During the current inspection, the inspectors identified that the licensee had not performed a detailed visual examination of the concrete-liner interface of the Unit 1 containment, per the ASME Section XI. Subsection IWE 1241 specifically states that surface areas subject to accelerated degradation and aging require the augmented (detailed visual) inspection identified in Table IWE-2500-1, Examination Category E-C. Subsection IWE 1241 also states that such areas include the interior and exterior containment surface areas that are subject to accelerated corrosion with no or minimal corrosion allowance. These areas may also include the concrete to containment liner interfaces. The licensee initiated CR 578448 to address the issue through the CAP.

Analysis:

The inspectors concluded that the licensees failure to conduct a detailed visual examination of the concrete-liner interface of the Units 1 and 2 containment in accordance with the ASME, BPVC,Section XI, Subsection IWE 1241, Table IWE-2500-1, Category E-C, Item E 4.11, was a PD that was within the licensees ability to foresee and correct. Using Manual Chapter 0612, Appendix B, Issue Screening, dated September 7, 2012, the inspectors determined that the PD was more than minor because, if left uncorrected, it had the potential to lead to a more significant safety concern. Specifically, visual inspections of the containment metallic liner provides assurance that the liner remains capable of performing its intended safety function, and in the absence of such inspections, corrosive conditions could progress to challenge that capability. Using Manual Chapter 0609.04, Initial Characterization of Findings, dated June 19, 2012, the finding was determined to affect the Barrier Integrity Cornerstone.

The inspectors screened the finding using IMC 0609, Appendix A, Significance Determination Process (SDP) for Findings at-Power, dated June 19, 2012, and determined that the finding was of very low safety-significance (Green), because the finding did not represent an actual open pathway in the physical integrity of reactor containment. The team determined that no cross cutting aspect was applicable to this performance deficiency because this finding was not indicative of current licensee performance.

Enforcement:

In September 1996, the NRC added IWE requirements to 10CFR10.55a, and in 1998, the licensee implemented a general visual inspection of the accessible surface areas in accordance with Category E-A, Item E 1.12 of Table IWE-2500-1.

Title 10 CFR 50.55a, Codes and Standards, states, in part that, the examination of metallic liners in concrete containments shall satisfy the requirements of ASME Section XI, Subsection IWE of the 2001 Edition with the 2003 Addenda through the latest edition, and addenda incorporated by reference in paragraph 10 CFR 50.55a(b)(2). The code of record for the current containment ISI Program Interval at Surry Unit 1 is the 2004 Edition of ASME Section XI. Section XI, Subsection IWE 1241, Table IWE-2500-1, Category E-C, Item E 4.11 requires the licensee to do a detailed visual examination of 100 percent of the surface areas subject to accelerated degradation and aging, including the concrete to containment liner interface.

Contrary to the above, from 1998 to 2015, the licensee failed to perform a detailed visual examination of the concrete-liner interface of the Units 1 and 2 containment in accordance with ASME Section XI. The licensee provided the results of the general visual examination, and leak rate test for the Unit 1 containment to demonstrate that there is no immediate safety concern. This violation is being treated as an NCV, consistent with Section 2.3.2 of the NRC Enforcement Policy, dated July 9, 2013. The violation was entered into the licensees CAP as CR 578448. (NCV 05000280, 281/2015002-01, Failure to Perform Detailed Visual Examination of the Concrete-Liner Interface of the Unit 1 Containment).

==1R11 Licensed Operator Requalification Program

==

.1 Resident Inspector Quarterly Review

a. Inspection Scope

The inspectors observed and evaluated a licensed operator simulator exercise given on April 2, 2015. The scenario involved a SG tube rupture with a faulted SG and the loss of two auxiliary feedwater (AFW) pumps. This scenario was intended to exercise the entire operations crew and assess the ability of the operators to react correctly to multiple failures. The inspectors observed the crews performance to determine whether the crew met the scenario objectives; accomplished the critical tasks; demonstrated the ability to take timely action in a safe direction and to prioritize, interpret, and verify alarms; demonstrated proper use of alarm response, abnormal, and emergency operating procedures; demonstrated proper command and control; communicated effectively; and appropriately classified events per the emergency plan. The inspectors observed the post training critique to determine that weaknesses or improvement areas revealed by the training were captured by the instructor and reviewed with the operators.

(

b. Findings

No findings were identified.

.2 Resident Inspector Observation of Control Room Operations

a. Inspection Scope

During the inspection period, the inspectors conducted observations of licensed reactor operator activities to ensure consistency with licensee procedures and regulatory requirements. For the following activities, the inspectors observed the following elements of operator performance: 1) operator compliance and use of plant procedures including technical specifications; 2) control board component manipulations; 3) use and interpretation of plant instrumentation and alarms; 4) documentation of activities; 5)management and supervision of activities; and 6) control room communications.

• On April 20, Unit 1 reactor plant shutdown to begin a refueling outage.

• On May 26, Unit 1 dilute to criticality for reactor startup.

b. Findings

No findings were identified.

==1R12 Maintenance Effectiveness

a. Inspection Scope

==

For the two equipment issues described in the condition reports listed below, the inspectors evaluated the effectiveness of the corresponding licensee's preventive and corrective maintenance. The inspectors performed a detailed review of the problem history and associated circumstances, evaluated the extent of condition reviews, as required, and reviewed the generic implications of the equipment and/or work practice problem(s). Inspectors performed walkdowns of the accessible portions of the system, performed in-office reviews of procedures and evaluations, and held discussions with system engineers. The inspectors compared the licensees actions with the requirements of the Maintenance Rule (10 CFR 50.65), station procedures ER-AA-MRL-10, Maintenance Rule Program, Revision 6, and ER-AA-MRL-100, Implementing the Maintenance Rule, Revision 8.

• CR 566825, Appendix R Lighting failures

• CR 568663, Unit 1 B Motor Driven Auxiliary Feedwater Pump Motor replacement

b. Findings

Introduction:

A self-revealing Green NCV of Surry Technical Specification (TS) 6.4.D was identified because the Unit 1 A motor driven auxiliary feedwater pump (MDAFW)motor outboard bearing thermocouple was improperly installed while installing a new motor on the MDAFW pump in November 2013. The improper thermocouple installation in the bearing caused the bearing to fail while the pump was running on January 5, 2015.

Description:

On January 5, 2015, the A MDAFW pump motor outboard bearing temperature sharply increased to a maximum indicated temperature of 202 degrees F, sixty-eight minutes into the performance of the quarterly periodic test of the pump. The licensee visually inspected the post-test run motor oil samples and the outboard motor bearing sample was cloudy and dark; whereas, the inboard motor bearing sample was clear and golden. Operations declared the A MDAFW pump inoperable and entered a 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> shutdown limiting condition for operation (LCO). Visual inspection of the motor outboard bearing was performed and witnessed by the NRC resident inspectors. When the upper-half outboard bearing housing was removed, babbitt material from the bearing lining was found to be clearly extruded from the upper-half bearing shell. The presence of babbitt material was indication that the bearing had wiped in conjunction with the increase in bearing temperature. This issue was documented in the licensees CAP as CR 568663.

It was also observed during this inspection that the outboard bearing thermocouple had been incorrectly installed in the bearing. The sensing end of the thermocouple was not inserted into the recessed hole drilled in the lower-half bearing shell as designed.

Instead, the end of the thermocouple was found to be in contact with the outside of the lower bearing shell at the point where it is supported by the bearing housing casting.

Further on-site examination of the removed motor was performed by the licensee upon release from the radiological controlled area (RCA). It was found that the outboard motor bearing thermocouples sensing end was imbedded between the polymer insulation material layer of the bearing and the bearing support.

The inboard bearing thermocouple was also found to be incorrectly installed, with the sensing end in the contact with the lower-half housing bearing support. Additionally, it was observed that the inboard/outboard thermocouple assemblies were found to be installed on the end of the motor which was opposite of the as found labeling on the underside of each thermocouple housing.

Extensive failure analysis of the A MDAFW pump motor was also conducted at the manufacturing facility. The third party contracted by the motor manufacture confirmed that the two bearing thermocouples were interchanged, with the bearing outboard sensor having been bent and forcibly pressing against the lower outboard side of the bearing shell, underneath the insulating Teflon sheet or directly onto the lower bearing shell.

The third party analysis also concluded that the mechanical intrusion of the thermocouple resulted in a disturbance to the alignment of this bearing shell to sufficient extent to cause oil-film and ultimate bearing failure. Additionally, the third party contractor assessed the condition of the A MDAFW pump operating with the incorrectly installed thermocouples during a design base event and came to the conclusion that the A MDAFW pump would have met its mission time.

The licensee conducted an apparent cause evaluation (ACE) and determined that during the October 1, 2013 outage readiness review challenge review board (CRB) for the replacement of the A MDAFW pump motor, it was identified that there would be only two inches of clearance between the motor and the doorway into the Safeguards room doorway. The CRB desired extra margin for the motor movement through the doorway and the decision was made to remove all external attachments to the motor frame.

Subsequently, the work order was not revised to include removing the thermocouples and therefore contained no specific steps for disassembly and assembly of the motor or related sub-components. The inboard and outboard thermocouples were re-installed incorrectly because procedure 0-ECM-1406-05, AFW Pump Motor Maintenance, section 6.4, Motor Disassembly and Assembly, was not referenced or utilized. This included failure to remove the upper half bearing housing to ensure that the thermocouple sensing end was properly inserted into the designed recessed hole drilled in the lower-half bearing shell. The MDAFW pump motor replacement was completed on November 11, 2013, and successfully passed a post maintenance test.

The inspectors agreed that the work order was not updated for the appropriate steps and procedure reference for removing and then reinstalling the motor bearing thermocouples. The inspectors also noted that the workers did not question why the procedure was not referenced in the work package when the actual work was being performed to remove and reinstall the thermocouples. Dominion procedure AD-AA-102, Procedure Use and Adherence, step 3.6.2 states, in part, When the procedure cannot be performed as written then: stop work, contact cognizant supervision, and initiate a procedure change to correct the procedure. This process was not accomplished in the A MDAFW pump motor replacement.

Analysis:

The inspectors concluded that the failure of the licensee to use a procedure to remove and reinstall the A MDAFW pump motor thermocouples was a performance deficiency that was within the licensees ability to foresee and correct. Specifically, the workers who installed the pump motor proceeded to remove and reinstall the new motor thermocouples based on the decision from the CRB even though the motor installation work order for the expanded work scope was not changed and no thermocouple installation instructions were included in the work order. Using Manual Chapter 0612, Appendix B, Issue Screening, dated September 7, 2012, the inspectors determined that the performance deficiency was more than minor because it was associated with the human performance attribute of the Mitigating Systems Cornerstone, and it adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences.

Specifically, the incorrect installation of the motor outboard bearing thermocouple eventually damaged the bearing and caused the A MDAFW pump to become inoperable.

Using Manual Chapter 0609.04, Initial Characterization of Findings, dated June 19, 2012, the finding was determined to affect the Mitigating Systems Cornerstone. The inspectors screened the finding using Manual Chapter 0609, Appendix A, SDP for Findings at-Power, dated June 19, 2012, and determined that it screened as Green because the deficiency did not affect the design or qualification of the AFW system and it did not represent a loss of system safety function. This finding has a cross-cutting aspect in the Challenge the Unknown aspect of the human performance area, H.11, because the individuals involved in removing and installing the thermocouples did not stop when faced with a work order that did not have the appropriate procedure reference for the action they were taking.

Enforcement:

Surry Technical Specification 6.4.D requires, in part, that procedures described in section 6.4.A shall be followed. Surry Technical Specification 6.4.A.7 requires, in part, that detailed written procedures with appropriate instructions shall be provided for conditions that include: corrective maintenance operations which would have an effect on the safety of the reactor. These requirements are implemented, in part, by Dominion procedure 0-ECM-1406-05, AFW Pump Motor Maintenance.

Contrary to the above, on November 11, 2013, the licensee removed and reinstalled the thermocouples for the A MDAFW pump motor bearings under a work order that was not adequate for the task and did not reference, section 6.4, 0-ECM-1406-05, the applicable section for thermocouple removal and re-installation. Because the licensee entered the issue into their corrective action program as CR 568663 and the finding is of very low safety significance (Green), this violation is being treated as an NCV, consistent with Section 2.3.2 of the NRC Enforcement Policy: NCV 05000280/2015002-02, A MDAFW Pump Motor Outboard Bearing Damaged.

==1R13 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

==

The inspectors evaluated, as appropriate, the six activities listed below for the following:

(1) the effectiveness of the risk assessments performed before maintenance activities were conducted;

(2) the management of risk;

(3) that, upon identification of an unforeseen situation, necessary steps were taken to plan and control the resulting emergent work activities; and

(4) that maintenance risk assessments and emergent work problems were adequately identified and resolved. The inspectors verified that the licensee was complying with the requirements of 10 CFR 50.65(a)(4) and the data output from the licensees safety monitor associated with the risk profile of Units 1 and 2.

The inspectors reviewed the corrective action program to verify deficiencies in risk assessments were being identified and properly resolved.

• On April 21, Unit 1 and Unit 2 risk during Unit 1 "H" Bus logic testing and RCS at reduced inventory.

• On May 4, Unit 2 risk while one of two main generator output breakers were open, #1 EDG out of service for planned maintenance, and component cooling SW outlet jumper in service.

• On May 12, Unit 1 risk during a reactor coolant pump (RCP) motor lift concurrent with core reload.

• On May 14, Unit 1 risk during lowered RCS inventory with SGs and RCS loops isolated, and "C" reserved station service transformer (RSST) out of service.

• On May 21, Unit 1 risk after Unit 1 safeguards basement flooding event.

• On June 6, Unit 2 risk while the refueling water storage tank "B" refrigeration unit was out of service for unplanned corrective maintenance and a "Hot Weather" alert was in effect.

b. Findings

No findings were identified.

==1R15 Operability Evaluations

a. Inspection Scope

==

The inspectors reviewed the five operability evaluations listed below, affecting risk-significant mitigating systems, to assess as appropriate:

(1) the technical adequacy of the evaluations;

(2) whether continued system operability was warranted;

(3) whether other existing degraded conditions were considered;

(4) if compensatory measures were involved, whether the compensatory measures were in place, would work as intended, and were appropriately controlled; and

(5) where continued operability was considered unjustified, the impact on TS Limiting Conditions for Operation and the risk significance.

The inspectors review included verification that operability determinations were made as specified in OP-AA-102, Operability Determination, Revision 13. The inspectors reviewed the licensees corrective action program to verify deficiencies in operability determinations were being identified and corrected.

• CR 576194, Uninterruptible power supply (UPS) 1A2 not sharing load.

• CR 577479, Safety Injection failed to reset during Unit 1 "H" bus logic testing.

• CR 580226, U1 Safeguards Equipment after recirculation spray (RS) HX SW flooding in safeguards basement.

• CR 580707, U1 RCS loop flow after the replacement of the "B" and "C" RCPs.

• CR 577346, 1C SW header debris evaluation.

b. Findings

No findings were identified.

==1R18 Plant Modifications

==

.1 Temporary Modifications

a. Inspection Scope

The inspectors reviewed temporary modification design change (DC) SU-13-00012, CCHX SW Outlet Jumper, to verify that the modification did not affect system operability or availability as described by the TS and UFSAR. In addition, the inspectors verified that the temporary modification was in accordance with CM-AA-DDC-201, Design Changes, Revision 16, and for the related work package, that adequate controls were in place, procedures and drawings were updated, and post-installation tests verified the operability of the affected systems.

b. Findings

No findings were identified.

.2 Permanent Modifications

a. Inspection Scope

The inspectors reviewed the completed permanent plant modification (DC) SU-14-0116, Unit 1 RCP Replacement. The inspectors conducted walkdowns of the installation at various stages of completion, reviewed the 10 CFR 50.59 Safety Review/Regulatory Screening, technical drawings, test plans and the modification package to assess the TS implications. The inspectors also verified that the permanent modification was in accordance with licensee procedure CM-AA-DDC-201, Design Changes, Revision 16.

In addition, the inspectors reviewed calculations and conducted interviews with licensee personnel.

b. Findings

No findings were identified.

==1R19 Post Maintenance Testing

a. Inspection Scope

==

The inspectors reviewed nine post maintenance test procedures and/or test activities for selected risk-significant mitigating systems listed below, to assess whether:

(1) the effect of testing on the plant had been adequately addressed by control room and/or engineering personnel;

(2) testing was adequate for the maintenance performed; (3)acceptance criteria were clear and adequately demonstrated operational readiness consistent with design and licensing basis documents;

(4) test instrumentation had current calibrations, range, and accuracy consistent with the application;

(5) tests were performed as written with applicable prerequisites satisfied;

(6) jumpers installed or leads lifted were properly controlled;

(7) test equipment was removed following testing; and

(8) equipment was returned to the status required to perform in accordance with VPAP-2003, Post Maintenance Testing Program, Revision 14.

• 1-IPT-FT-RP-SI-001A, OTO 1, Train A Safeguards Action Logic Functional Test, Revision 0, to validate SI switch functionality following troubleshooting.

• 1-OPT-EG-009, #1 EDG Major Maintenance Operability Test, Revision 53, following breaker 15H8 indicating lights control power cable replacement

• 0-ECM-1509-06, Quiklook Testing for Quarter Turn Motor Operated Valves, Revision 28, and 0-EPM-1503-01, Motor Operated Valve Operator Inspection, Revision 8, periodic MOV testing on 1-SW-MOV-105B, B RSHX SW outlet isolation valve.

• 1-OPT-EG-009, OTO 1, #1 EDG Major Maintenance Operability Test, Revision 53, following a major maintenance outage

• 0-MCM-0300-10, Valve Repack, Revision 7, following the repack of 1-RH-MOV-1700, the Unit 1 residual heat removal inlet isolation valve

• 1-MOP-EP-007, Removal and Return to Service of UPS 1B-1, Revision 3, following its 10 year preventative maintenance outage

• 0-OPT-ZZ-008, ASME System Pressure Tests, Revision 11, following the repair and return to service of RS SW expansion joint, 1-SW-REJ-105B

• 1-OPT-FW-001, Motor Driven Auxiliary Feedwater Pump 1-FW-P-3A Performance Test, Revision 36, following removal and reinstallation of the Unit 1 A MDAFW pump motor

• 0-OPT-ZZ-008, ASME System Pressure Tests, Revision 11, following through wall leak repair on main control room chiller SW backwash piping.

b. Findings

No findings were identified.

==1R20 Refueling and Other Outage Activities

a. Inspection Scope

==

The inspectors reviewed the stations work schedule and outage risk plan for the Unit 1 refueling outage, which was conducted April 19 through May 27, 2015, to confirm that the licensee had appropriately considered risk, industry experience, and previous site-specific problems in developing and implementing a plan that assured maintenance of defense-in-depth. The inspectors used IP 71111.20, Refueling and Outage Activities, to observe portions of the maintenance and startup activities to verify that the licensee maintained defense-in-depth commensurate with the outage risk plan and applicable TS.

The inspectors monitored licensee controls over the outage activities listed below.

• Licensee configuration management, including daily outage reports, to evaluate maintenance of defense-in-depth commensurate with the outage risk plan for key safety functions and compliance with the applicable TS when taking equipment out of service.

• Implementation of clearance activities and confirmation that tags were properly hung and equipment appropriately configured to safely support the work or testing.

• Controls over the status and configuration of electrical systems to ensure that TS and outage safety plan requirements were met, and controls over switchyard activities.

• Controls over activities that could affect reactivity.

• Monitoring of decay heat removal operations.

• Spent fuel cooling operations to verify that outage work was not impacting the ability of the operations staff to operate the spent fuel cooling system during and after core offload.

• Reactor coolant inventory controls, including flow paths, configurations, alternative means for inventory additions, and controls to prevent inventory loss.

• The control of containment penetrations and containment entries to verify that the licensee controlled those penetrations and activities in accordance with the appropriate TS and could achieve/maintain containment closure for required conditions.

• Refueling activities, including fuel handling and fuel receipt inspections.

• Startup and ascension to full power operation, tracking of startup prerequisites, and walkdown of the primary containment to verify that debris had not been left which could block emergency core cooling system strainers.

• Fatigue management.

• Licensee identification and resolution of problems related to forced outage activities.

b. Findings

No findings were identified.

==1R22 Surveillance Testing

a. Inspection Scope

==

For the seven surveillance tests listed below, the inspectors examined the test procedures, witnessed testing, or reviewed test records and data packages, to determine whether the scope of testing adequately demonstrated that the affected equipment was functional and operable, and that the surveillance requirements of TS were met. The inspectors also determined whether the testing effectively demonstrated that the systems or components were operationally ready and capable of performing their intended safety functions.

In-Service Testing:

• 1-OPT-RH-003, RHR System Operability Test, Revision 23 Surveillance Testing:

• 0-OSP-AAC-001, Alternate AC Diesel Quarterly Test, Revision 44

• 1-EPT-0106-06, Main Station Battery 1A Performance Test, Revision 19

• 1-OPT-ZZ-001, 1H Bus Logic Testing, Revision 39

• 1-OPT-SI-008, Refueling Test of the High Head SI Check Valve to the Hot legs, Revision 21

• CH-11.202, RCS Specific Activity Chemistry Sample, Revision 9

Appendix J Leak Rate Determination

• 1-OPT-CT-201, Containment Isolation Valve Local Leak Rate Testing (Type C):

1-RS-MEJ-2B, 1-RS-11 and 1-RS-MOV-156B, Revision 22

b. Findings

No findings were identified.

1EP6 Drill Evaluation

Emergency Preparedness (EP) Drill

a. Inspection Scope

On April 2, 2015, the inspectors reviewed and observed a licensee EP drill involving a failed open steam generator relief valve, a steam generator tube rupture, the loss of two AFW pumps, and an unisolable radioactive air release. The inspectors assessed the licensee emergency procedure usage, emergency plan classifications, notifications, and protective actions recommendation development. The inspectors evaluated the adequacy of the licensees conduct of the drill and post-drill critique performance. The inspectors verified that the drill critique identified drill performance weaknesses and entered these items into the licensees CAP.

b. Findings

No findings were identified.

RADIATION SAFETY

Cornerstones: Public Radiation Safety

2RS6 Radioactive Gaseous and Liquid Effluent Treatment

a. Inspection Scope

Event and Effluent Program Reviews: The inspectors reviewed recent liquid and gaseous release permits including pre-release sampling results, effluent monitor setpoints, and public dose calculations. The inspectors reviewed the 2013 and 2014 annual effluent reports to evaluate reported doses to the public, review any anomalous events, evaluate groundwater sampling results, and to review Offsite Dose Calculation Manual (ODCM) changes. The inspectors also reviewed compensatory sampling data for time periods when selected radiation monitors were out of service.

Walk-Downs and Observations: The inspectors walked-down selected components of the gaseous and liquid radioactive waste processing and discharge systems, the protected area, and auxiliary building. To the extent practical, the inspectors observed and evaluated the material condition of in-place waste processing equipment for indications of degradation or leakage that could constitute a possible release pathway to the environment. Inspected components included waste monitor tanks, laundry waste tanks, evaporation equipment, waste gas decay tanks, ventilation filtration systems, vendor-supplied liquid waste processing equipment, and associated piping and valves.

The inspectors interviewed licensee staff regarding radwaste equipment configuration and effluent monitor operation. The inspectors also reviewed surveillance testing records for auxiliary building ventilation filtration systems and for effluent flow rate measuring devices.

Sampling and Analyses: The inspectors observed sampling, analysis, and effluent release permit generation for the condensate air ejector and ventilation vent #1 release points. Quality control activities for count room equipment were discussed with health physics (HP) technicians and results of the 2013 and 2014 radiochemistry cross-check program were reviewed. The inspectors discussed effluent source term evaluation, changes to effluent release points with licensee staff and evaluated recent land use census results. Meteorological data used to calculate doses to the public was evaluated as part of IP 71124.07.

Ground Water Protection: The inspectors reviewed the licensees continued implementation of the industrys Ground Water Protection Initiative (NEI 07-07) and discussed any changes to the program. The inspectors discussed program guidance for dealing with spills, leaks, and unexpected discharges with licensee staff and reviewed recent entries into the 10 CFR 50.75(g) decommissioning file. The inspectors reviewed and discussed the licensees program for monitoring of structures, systems, and components (SSCs) with the potential to release radioactive material to the environment including the liquid radioactive waste system, spent fuel pool liner, boron recovery valve gallery, storm drains, and refueling water storage tanks. Potential effluent release points due to onsite surface water bodies were also evaluated. The inspectors discussed the status of site initiatives to rehabilitate site drainage and groundwater mitigation systems including, floor drains, curtain drain pumps, piezometer wells, and installation of wells in the sand layer above the engineered backfill with the capability to use the wells for stabilization and future remediation of site groundwater tritium concentrations.

Radioactive waste system operation, effluent processing activities, and groundwater protection efforts were evaluated against requirements and guidance documented in the following: 10 CFR 20; 10 CFR 50 Appendix I; Offsite Dose Calculation Manual (ODCM);

UFSAR Section 11; Regulation Guide (RG) 1.21, Measuring, Evaluating, and Reporting Radioactivity in Solid Wastes and Releases of Radioactive Materials in Liquid and Gaseous Effluents from Light-Water-Cooled Nuclear Power Plants; RG 1.109, Calculation of Annual Doses to Man from Routine Releases of Reactor Effluents for the Purpose of Evaluating Compliance with 10 CFR Part 50 Appendix I; and Surry TS Section 6. Procedures and records reviewed during the inspection are listed in the

.

Problem Identification and Resolution: The inspectors reviewed selected CAP documents in the areas of gaseous and liquid effluent processing and release activities.

The inspectors evaluated the licensees ability to identify and resolve the identified issues in accordance with procedure PI-AA-200, Corrective Action, Rev. 23. The inspectors also discussed the scope of the licensees internal audit program and reviewed recent assessment results. Documents reviewed are listed in the attachment.

The inspectors completed one

(1) sample as required by Inspection Procedure (IP)71124.06.

b. Findings

No findings were identified.

2RS7 Radiological Environmental Monitoring Program (REMP)

a. Inspection Scope

REMP Status and Results: The inspectors reviewed and discussed planned changes to the ODCM and results presented in the Annual Environmental Radiological Environmental Operating Report issued for 2013 and 2014. The REMP contract laboratory (Teledyne Brown Engineering) cross-check program results and current procedural guidance for offsite collection, processing and analysis of airborne particulate and iodine, broadleaf vegetation, and surface water samples were reviewed and discussed. The Annual Environmental Radiological Environmental Operating Report environmental measurement results were reviewed for consistency with licensee effluent data and evaluated for radionuclide concentration trends. The inspectors reviewed and discussed detection level sensitivity requirements and results for selected environmental media analyzed by the offsite environmental laboratory.

Site Inspection and Equipment Walk-down: The inspectors discussed implementation of selected REMP monitoring and sample collection activities for atmospheric, broadleaf vegetation samples, and water and milk samples as specified in the current ODCM and applicable procedures. The inspectors observed equipment material condition and verified operability, including verification of flow rates and total sample volume results for the weekly airborne particulate filter and iodine cartridge change-outs at eight atmospheric sampling stations. In addition, the inspectors discussed broadleaf vegetation sampling for selected stations. Thermo-luminescent dosimeter (TLD)material condition and placement were verified by direct verification at eight ODCM locations. Land use census results, actions for missed samples including compensatory measures, sediment sample collection/processing activities, and availability of replacement equipment were discussed with knowledgeable licensee staff. In addition, sample pump calibration and maintenance records for selected environmental air samplers were reviewed. The current status and completeness of the licensees 10 CFR 50.75(g) decommissioning files were reviewed and discussed, as well as the licensees assessment of SSCs that could potentially leak material into the groundwater. Additional assessment of the ground water protection program, including sampling of wells and the curtain drain systems, was completed and is documented in Section 2RS6.

Meteorological Monitoring Program: The inspectors conducted a tour of the meteorological tower and observed the local data collection equipment computer used to provide local readout if required. The inspectors observed the physical condition of the tower and associated instruments and discussed equipment operability, maintenance history, and backup power supplies with responsible licensee staff. The inspectors evaluated transmission of locally generated meteorological data from the meteorological tower to the main control room operators. For the meteorological measurements of wind speed, wind direction, and temperature, the inspectors reviewed applicable tower instrumentation calibration records for 2013 and 2014 and evaluated meteorological measurement data recovery for 2013 and 2014.

Procedural guidance, program implementation, quantitative analysis sensitivities, and environmental monitoring results were reviewed against 10 CFR Part 20; Appendix I to 10 CFR Part 50; TS Sections 6.4, and 6.6; ODCM, Rev. 18; RG 4.15, Quality Assurance for Radiological Monitoring Programs (Normal Operation) - Effluent Streams and the Environment; and the Branch Technical Position, An Acceptable Radiological Environmental Monitoring Program - 1979. Licensee procedures and activities related to meteorological monitoring were evaluated against: ODCM; UFSAR Chapter 11; RG 1.23, Meteorological Monitoring Programs for Nuclear Power Plants, and ANSI/ANS-2.5-1984, Standard for Determining Meteorological Information at Nuclear Power Sites.

Procedures and records reviewed during the inspection are listed in the Attachment.

Problem Identification and Resolution: The inspectors reviewed selected CAP documents in the areas of environmental and meteorological monitoring. The inspectors evaluated the licensees ability to identify, characterize, prioritize, and resolve the identified issues in accordance with PI-AA-200, Corrective Action, Revision 23.

Documents reviewed are listed in the attachment.

The inspectors completed 1 sample as required by IP 71124.07.

b. Findings

No findings were identified.

OTHER ACTIVITIES

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

4OA1 Performance Indicator (PI) Verification

.1 Safety System Functional Failures

a. Inspection Scope

The inspectors sample the licensees submittals for the Safety System Functional Failures performance indicator for both Unit 1 and Unit 2 (2 samples) for the period of April 1, 2014 through March 31, 2015, to assess the accuracy and completeness of the submitted data and whether the performance indicators were calculated in accordance with the guidance contained in NEI 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7. The inspection was conducted in accordance with NRC Inspection Procedure 71151, Performance Indicator Verification. The inspectors reviewed the applicable NRC inspection reports and the licensees event reports, operator logs, station performance indicators, and related CRs.

b. Findings

No findings were identified.

.2 Reactor Coolant System (RCS) Specific Activity and RCS Leak Rate

a. Inspection Scope

The inspectors reviewed the licensees submittals for the RCS specific activity and RCS leak rate performance indicators for both Unit 1 and Unit 2 for the period of April 1, 2014 through March 31, 2015 (4 samples) to assess the accuracy and completeness of the submitted data and whether the performance indicators were calculated in accordance with the guidance contained in NEI 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7. The inspection was conducted in accordance with NRC Inspection Procedure 71151, Performance Indicator Verification. The inspectors observed a chemistry technician obtain and analyze an RCS sample. The inspectors also reviewed RCS sample analysis and control room logs of daily RCS leakage, and compared that information to the data reported by the performance indicator.

b. Findings

No findings were identified

.3 Occupational Radiation Safety Cornerstone

a. Inspection Scope

The inspectors reviewed the Occupational Exposure Control Effectiveness PI results for the Occupational Radiation Safety Cornerstone from June, 2013, through March, 2015.

For the assessment period, the inspectors reviewed ED alarm logs and selected CRs related to controls for exposure significant areas. The inspectors also reviewed licensee procedural guidance for collecting and documenting PI data. Documents reviewed are listed in of the report Attachment.

b. Findings

No findings were identified.

.4 Public Radiation Safety Cornerstone

a. The inspectors reviewed the Radiological Control Effluent Release Occurrences PI results for the Public Radiation Safety Cornerstone from June, 2013, through March, 2015. For the assessment period, the inspectors reviewed cumulative and projected doses to the public and CRs related to Radiological Effluent TS/ODCM issues. The inspectors also reviewed licensee procedural guidance for collecting and documenting PI data. Documents reviewed are listed in the Attachment.

b. Findings

No findings were identified.

4OA2 Identification and Resolution of Problems

.1 Daily Reviews of items Entered into the Corrective Action Program:

a. Inspection Scope

As required by NRC Inspection Procedure 71152, Identification and Resolution of Problems, and in order to help identify repetitive equipment failures or specific human performance issues for follow-up, the inspectors performed a daily screening of items entered into the licensees CAP. This review was accomplished by reviewing daily CR report summaries and periodically attending daily CR Review Team meetings.

b. Findings

No findings were identified.

.2 Annual Sample: Review of CRs 533401 and 534883, RCS Make-Up Connection to LHSI

Piping not Missile Protected

a. Inspection Scope

The inspectors performed an in-depth review regarding the licensees evaluation and corrective actions associated with CRs 533401 and 534883, RCS Make-Up Connection to Low Head Safety Injection (LHSI) Piping not Missile Protected. Specifically, on November 21, 2013, while answering a NRC inspectors questions about the seismic supports for the diverse and flexible coping strategies (FLEX) modification connection to LHSI piping, the licensee concluded that the newly installed FLEX modification make-up connection was not protected against external missiles. The inspectors assessed the licensees problem identification threshold, cause analyses, extent of condition reviews, compensatory actions, and the prioritization and timeliness of the licensees corrective actions to determine whether the licensee was appropriately identifying, characterizing, and correcting problems associated with this issue and whether the planned or completed corrective actions were appropriate. The inspectors compared the actions taken to the requirements of the licensees CAP as specified in procedure, PI-AA-200, Corrective Action Program, Revision 23, and 10 CFR 50, Appendix B. In addition, the inspectors reviewed the corrective action program for similar issues, and interviewed engineering personnel to assess the effectiveness of the implemented corrective actions.

b. Findings

No findings were identified.

The licensee determined that the apparent cause was that the Beyond Design Basis (BDB) project team had an incorrect mindset in that the only the FLEX portion of piping was not fully missile protected. The project team failed to evaluate the design change with regards to protecting the FLEX connection to the LHSI piping. The licensees correction actions included changing procedure CM-AA-DDC-201, Design Changes, to include a requirement to review missile protection analysis during pre-job briefs as well as a requirement that interfaces between new and existing equipment be specifically identified and verified. The inspectors verified that the licensee had identified problems with this issue at an appropriate threshold and entered them into the CAP; and had proposed or implemented appropriate corrective actions. The inspectors determined that the corrective actions developed as a result of the apparent cause analysis were reasonable commensurate with the safety significance of the LHSI system.

4OA5

OTHER ACTIVITIES

(Closed) Unresolved Item 05000280/2013005-01: Application of American Society of Mechanical Engineers,Section XI, Table IWB 2500-1, Item B10.10, Inspection Requirements and Note 1 Exemptions (ML14041A449)

a. Inspection Scope

The inspectors followed up on an unresolved item (URI) concerning lack of surface examinations by the licensee for the reactor pressure vessel (RPV) supports attachment welds. ASME Section XI Code includes inspection requirements for the RPV supports attachment welds (Subsection IWB). Subsection IWB, Table IWB-2500-1, Item number B10.10, Note 1, describes the examination requirements for welded attachments for vessels, piping, pumps, and valves. Note 1 of Table IWB-2500-1 states that attachment welds (weld buildup) on nozzles that are in compression under normal load conditions, and provide only component support, are excluded from the surface examination requirements. During the inservice inspection in 2013 for Surry Unit 1 documented in inspection report 05000280/2013005, the inspectors identified that the licensee excluded the surface examination requirements based on the exemptions provided by Note 1.

The licensees position was that the surface examinations were not required based on the exclusion criteria provided in Note 1, for attachment welds under compressive loads during normal conditions. At the time of the inspection, the inspectors identified that in addition to compressive loads, shear type loadings appeared to exist for the normal load case based on calculations provided to the inspectors. This configuration did not appear to meet the intent of the exclusion criteria provided by Note 1 of the Table IWB 2500-1.

The inspectors also identified that the support was relied upon in the RCS model analysis to restrain substantial multi-directional seismic and loss of coolant accident (LOCA) type loading cases. The inspectors initiated a URI pending resolution of apparent differences in the loading cases described in the licensee calculations, and the Note 1 criteria for compressive loadings. Subsequently, the Region II staff, after consulting the Office of Nuclear Reactor Regulation (NRR) and reviewing several regulatory as well as licensee-specific documents, developed a Task Interface Agreement (TIA) 2014-02 (ML14296A336). In a final response to the TIA (ML15139A283), the NRR staff concluded that there is no need for the licensee to perform a surface examination, as shear stresses for the normal load case were calculated to be negligible. This URI is closed.

b. Findings

No findings were identified.

4OA6 Meetings, Including Exit

Exit Meeting Summary

On July 29, 2015, the inspection results were presented to Mr. R. Simmons and other members of his staff, who acknowledged the findings. The inspectors asked the licensee whether any of the material examined during the inspection should be considered proprietary. No proprietary information was identified.

ATTACHMENT:

SUPPLEMENTARY INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

J. Abbott, Health Physicist

J. Ashley, Licensing Engineer

L. Baker, Training Manager

P. Blount, Health Physicist

D. Cobb, Manager, Nuclear Oversight

J. Eggart, Manager, Radiation Protection & Chemistry

A. Fletcher, Surry PM-Ground Water Protection Project

M. Gabriel, Supervisor, Instrumentation and Controls

B. Garber, Supervisor, Station Licensing

M. Haduck, Manager, Outage and Planning

P. Harris, Supervisor, Radiological Analysis and Instrumentation

R. Johnson, Manager, Operations

P. Jurewicz, Boric Acid Corrosion Control Program Owner

L. Lane, Site Vice President

D. Lawrence, Director, Station Safety and Licensing

T. Mayer, Surry SG ISI Program Owner

L. Ragland, Health Physics Operations Supervisor

M. Ringler, Site Welding Engineer

J. Rosenberger, Director, Station Engineering

R. Scanlan, Manager, Maintenance

B. Shelton, Station Engineering, Radiation Monitoring

R. Simmons, Plant Manager

M. Smith, Manager, Nuclear Organizational Effectiveness

W. Terry, Supervisor, Health Physics Technical Services

E. Turko, ISI Supervisor

N. Turner, Supervisor, Emergency Preparedness

LIST OF ITEMS

Opened and Closed

05000280, 281/2015002-01 NCV Failure to conduct a detailed visual examination of the concrete-liner interface for the Unit 1 containment (Section 1R08)

05000280/2015002-02 NCV A MDAFW Pump Motor Outboard Bearing Damaged (Section 1R12)

Closed

05000280/2013005-01 URI Application of ASME Section XI, Table IWB 2500-1, Item B10.10, Inspection Requirements and Note 1 Exemptions (Section 1R08)