IR 05000280/2014005

IR 05000280/2014005, 05000281/2014005; on 10/01/2014 - 12/31/2014; Surry Power Station, Units 1 and 2, Followup of Events and Notices of Enforcement Discretion

ML15033A248
Person / Time
Site:	Surry
Issue date:	02/02/2015
From:	Steven Rose NRC/RGN-II/DRP/RPB5
To:	Heacock D Virginia Electric & Power Co (VEPCO)
References
IR 2014005
Download: ML15033A248 (39)

Text

UNITED STATES bruary 2, 2015

SUBJECT:

SURRY POWER STATION - NRC INTEGRATED INSPECTION REPORT 05000280/2014005, 05000281/2014005

Dear Mr. Heacock:

On December 31, 2014, the United States Nuclear Regulatory Commission (NRC) completed an inspection at your Surry Power Station, Units 1 and 2. On January 28, 2015, the NRC inspectors discussed the results of this inspection with Mr. L. Lane and other members of your staff. Inspectors documented the results of this inspection in the enclosed inspection report.

NRC inspectors documented one finding of very low safety significance (Green) in this report.

This finding involved a violation of NRC requirements. Additionally, two licensee-identified violations which were determined to be of very low safety significance are listed in this report.

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

If you contest the violations or significance of these NCVs, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the 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. In accordance with Title 10 of the Code of Federal Regulations (CFR) 2.390, Public Inspections, Exemptions, Requests for Withholding, of the NRCs Rules of Practice, 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 05000280/2014005, 05000281/2014005 w/Attachment: Supplementary Information

REGION II==

Docket Nos.: 50-280, 50-281 License Nos.: DPR-32, DPR-37 Report No: 05000280/2014005, 05000281/2014005 Licensee: Virginia Electric and Power Company (VEPCO)

Facility: Surry Power Station, Units 1 and 2 Location: 5850 Hog Island Road Surry, VA 23883 Dates: October 1, 2014 through December 31, 2014 Inspectors: P. McKenna, Senior Resident Inspector C. Jones, Resident Inspector A. Butcavage, Reactor Inspector (Section 1R07)

D. Bacon, Senior Operations Engineer (Section 1R11)

Approved by: Steven D. Rose, Chief Reactor Projects Branch 5 Division of Reactor Projects Enclosure

SUMMARY

IR 05000280/2014005, 05000281/2014005; 10/01/2014-12/31/2014; Surry Power Station, Units and 2: Followup of Events and Notices of Enforcement Discretion The report covered a three-month period of inspection by resident inspectors and region-based inspectors. Inspectors identified one non-cited violation (NCV) 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 June 2, 2011. The cross-cutting aspect was determined using IMC 0310, Components Within The Cross-Cutting Areas, dated December 04, 2014. All violations of NRC requirements are dispositioned in accordance with the NRCs Enforcement Policy, dated July 9, 2013. The NRCs program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process Revision 5.

Cornerstone: Initiating Events

Green.

An NRC-identified, non-cited violation (NCV) of Surry Technical Specification (TS)6.4, Unit Operating Procedures and Programs, Section A.7 was identified because Surry procedure 0-ECM-1801-01, Westinghouse Type BF - BFD - or NBFD65NR Relay Replacement did not include a torque value for the reactor protection system (RPS) relay terminal screws to a field wiring connection. Subsequently, Unit 2 tripped on October 13, 2014, when a field wire connection became loose from the terminal end of a RPS trip relay and caused a reactor trip breaker to open. The issue was documented in Surrys corrective action program (CAP) as condition report (CR) 561820.

The licensees failure to specify a torque value in procedure 0-ECM-1801-01 was a performance deficiency (PD) that was within the licensees ability to foresee and correct.

Specifically, the licensee removed the correct torque value from the procedure based on a licensee procedure action request (PAR) that was incorrectly implemented. The inspectors determined that the PD was more than minor because it was associated with the procedural quality attribute of the Initiating Events Cornerstone and adversely affected the cornerstone objective to limit the likelihood of events that upset stability and challenge critical safety functions during shutdown as well as power operations. Specifically, the procedure that controlled the connection of electrical termination to RPS relays did not specify a torque value and therefore, left it up to the technician to determine the tightness of the connection.

Using Manual Chapter 0609.04, Initial Characterization of Findings, Table 2, dated June 19, 2012, the finding was determined to affect the Initiating Events Cornerstone. The inspectors screened the finding using Manual Chapter 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 cause a loss of mitigation equipment relied upon to transition the plant to a stable shutdown condition. This finding has a cross-cutting aspect in the documentation component of the human performance area, H.7, because the organization failed to maintain complete, accurate and up-to-date documentation for the replacement of RPS relays. (Section 4OA3)

Two violations of very low safety significance that were identified by the licensee have been reviewed by the NRC. Corrective actions taken or planned by the licensee have been entered into the licensees corrective action program. These violations and corrective action tracking numbers are listed in Section 4OA7 of this report.

REPORT DETAILS

Summary of Plant Status

Unit 1 operated at or near rated thermal power (RTP) throughout the inspection period.

Unit 2 operated at or near RTP from the beginning of the inspection period until October 13, 2014, when it was shut down due to an automatic trip caused by a loose electrical termination on a RPS trip relay. It remained offline until October 15, when the main turbine was synchronized to the grid. Unit 2 operated at or near RTP from October 15 until November 5 when reactor power was reduced to 80% due to a stuck open 2A feedwater heater relief valve.

Unit 2 returned to RTP on November 5 and remained there for the remainder of the inspection period.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R01 Adverse Weather Protection

.1 External Flooding

a. Inspection Scope

The inspectors performed an inspection of the external flood protection measures for Surry. The inspectors reviewed TS, procedures, design documents, and the Updated Final Safety Analysis Report (UFSAR), which depicted the design flood levels and protection areas containing safety-related equipment to identify areas that may be affected by external flooding. The inspectors conducted a site walkdown of the common low level intake structure, including doors, flood protection barriers, penetrations, and the integrity of the perimeter structure to ensure the licensee erected flood protection measures in accordance with design specifications. The inspectors also reviewed operating procedures for mitigating external flooding during severe weather to determine if the licensee planned or established adequate measures to protect against external flooding events.

b. Findings

No findings were identified.

.2 Seasonal Readiness Reviews for Cold Weather

a. Inspection Scope

The inspectors reviewed the licensees preparations for seasonal cold weather. The inspection focused on verification of design features and implementation of the licensees procedure for cold weather conditions, 0-OSP-ZZ-001, Cold Weather Preparation, Revision 15. The inspectors walked down key structures including the turbine and auxiliary buildings, safeguards buildings, the emergency switchgear rooms, and emergency battery rooms and verified heating, ventilation, and cooling (HVAC)systems were operating properly and that area temperatures remained within design requirements specified in the UFSAR. The mitigating systems reviewed during this inspection include: the auxiliary feedwater systems, the refueling water storage tanks, emergency diesel generators, alternate alternating current (AAC) diesel generator, and emergency switchgear.

b. Findings

No findings were identified.

1R04 Equipment Alignment

.1 Partial Walkdown

a. Inspection Scope

The inspectors conducted five 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 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.

• Diesel Driven Fire Pump while Motor Driven Fire Pump was being tested

• Unit 1 "B" train of Low Head Safety Injection (LHSI) System while "A" train of LHSI was out of service for testing

• 1 and 2 EDGs during corrective maintenance on the AAC Diesel

• Unit 2 "C" Charging Pump after completed planned maintenance

• Unit 1 Auxiliary Feedwater (AFW) pumps after AFW motor operated valve (MOV)testing

b. Findings

No findings were identified.

.2 Complete Walkdown

a. Inspection Scope

The inspectors performed a detailed walkdown and inspection of the Unit 2 charging pump service water (SW) system to verify the system was properly aligned and capable of performing its safety function, and to assess its 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 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 7, 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 Cable Spreading Room

• Unit 2 Cable Spreading Room

• Emergency Service Water (ESW) Low Level Pump House

• Fuel Oil Pump House

• Unit 1 Cable Vault

b. Findings

No findings were identified.

.2 Drill Observation

a. Inspection Scope

The inspectors observed unannounced fire drills on September 9, 2014, and November 18, 2014, (one sample total) that took place in the #3 emergency diesel generator (EDG) enclosure and the nine foot elevation of the Unit 1 emergency switchgear room (ESGR), respectively. The drills were 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.

b. 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 Unit 2 turbine buildings. The inspectors conducted a walkdown of the affected area 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. The inspectors reviewed the corrective action program and verified internal flooding related problems were being identified and properly addressed.

b. Findings

No findings were identified.

1R07 Heat Sink Performance

.1 Triennial Review of Heat Sink Performance

a. Inspection Scope

The inspectors reviewed three samples of completed surveillances, associated calculations, performance test results, and cooler inspection results associated with the B component cooling water (CCW) heat exchanger, the Unit 1 A recirculation spray (RS) heat exchanger, and the Unit 2 A charging pump lube oil cooler and one ultimate heat sink sample. The heat exchangers/coolers were chosen based on their risk significance in the licensees safety analysis, their important safety-related mitigating system support functions, and existing margins.

For the CCW and RS heat exchangers, the inspectors sample determined whether testing, inspection, maintenance, and monitoring of biotic-fouling and macro-fouling programs were considered in order to provide reasonable assurance that the CCW and RS heat exchangers could perform their intended heat transfer function. This was accomplished by determining whether the test method used was consistent with accepted industry practices or equivalent, the test procedure conditions were consistent with the selected methodology, and the test acceptance criteria were consistent with the design basis values. The inspectors also reviewed intake canal water level normal and abnormal control room procedural requirements, in order to provide reasonable assurance that the intake canal levels were procedurally maintained in accordance with predicted inventory, and head requirements determined by the RS heat exchanger (RSHX) design calculations. Additionally, discussions with the system engineer reviewed differences between testing conditions and canal design conditions, and trending of test results, in order to provide reasonable assurance that testing and trending, was sufficient to detect degradation in the canal prior to loss of heat removal capabilities below design basis values.

For the charging pump lubricating oil cooler, the inspectors reviewed a sample of the methods and results of heat exchanger inspections. The inspectors evaluated whether the methods used to inspect, clean, or replace heat exchangers were consistent with industry standards, and the as-found results were recorded, evaluated, and appropriately dispositioned so that the as-left condition was acceptable.

In addition, the inspectors evaluated whether the condition and operation of the RS and CCW heat exchangers were consistent with design assumptions in heat transfer calculations, and as described in the USFAR. The inspectors evaluated whether the licensee had considered issues such as tube plugging, water hammer, and flow induced vibration during operation. In addition, a sample of eddy current test reports (ECT) and visual inspection records were reviewed for the RS heat exchanger to assess the acceptability of the heat exchanger as-found conditions during previous inspections.

For the CCW heat exchanger, the inspectors evaluated whether the condition and operation of the heat exchanger were consistent with design assumptions in heat transfer calculations. The inspectors had discussions with system engineering to verify that the licensee evaluated the potential for heat exchanger degradation, and that controls to prevent heat exchanger degradation were considered. In addition, ECT reports and test criteria were reviewed in order to provide reasonable assurance that the heat exchanger heat transfer model included uncertainty corrections and the original heat exchanger specification data sheet design conditions.

The inspectors reviewed the performance of ultimate heat sink (UHS) and their subcomponents, such as piping, intake screens, pumps, valves, etc., to verify the licensee had appropriately evaluated by tests or other equivalent methods, to ensure availability and accessibility to the in-plant cooling water systems.

The inspectors evaluated whether the licensees inspection of the UHS was thorough, and of sufficient depth, to identify degradation or the loss of structural integrity. This included determination that vegetation present along the slopes was trimmed, maintained, and did not adversely impact the embankment. In addition, the inspectors determined that the licensee ensured sufficient reservoir capacity in the intake canal, as described in a sample for the licensing basis calculations of the RSHX.

The inspectors reviewed a sample of the licensees maintenance work orders for the alternate service raw water supply pump that provides the backup water source to the intake canal. This included a review of the licensees maintenance of the pump, diesel driver, and strainer in order to provide reasonable assurance that the diesel-driven pump can perform its intended function.

The inspectors performed a system walkdown on SW and closed cooling water systems, to determine whether the licensees assessment of structural integrity was adequate.

The inspectors reviewed a sample of the licensees pressure testing results for buried piping downstream of the RS heat exchangers 1-RS-E-1B and 1-RS-E-1C. For closed cooling water systems, the inspectors also interviewed the system engineer to identify adverse conditions, such as makeup trends, that could be indicative of excessive leakage out of the closed system. A walkdown of the SW intake structures was also performed in order to determine whether the licensees assessment of structural integrity, and component functionality, was adequate and that the licensee ensured proper functioning of traveling screens and strainers, and structural integrity of component mountings. In addition, the inspectors determined whether the low level intake structure silt accumulation was monitored, trended, and maintained at a level required by the licensing basis. Additional discussions were held with system engineering in order to provide reasonable assurance that the intake canal level is maintained consistent with licensing basis calculations associated with the RS heat exchangers, and that demands on the intake canal such as the demand for an alternate fire water source for the adjacent fossil unit, were identified and considered in control room abnormal operating procedures. The inspectors also reviewed a sample of the licensees abnormal weather procedures to provide reasonable assurance that functionality of required systems during adverse weather conditions had been addressed. Chemistry control of SW and circulating water systems procedures were also discussed with system engineering in order to provide reasonable assurance that bio-fouling conditions were being addressed.

The inspectors also reviewed a sample of CRs related to the heat exchangers/coolers, heat sink performance issues, and river bottom maintenance at the low level intake in order to determine whether the licensee had an appropriate threshold for identifying issues, and to evaluate the effectiveness of the corrective actions. The documents that were reviewed are included in the Attachment to this report.

These inspection activities constituted four heat sink inspection samples as defined in IP 71111.07-05.

b. Findings

No findings were identified.

.2 Annual Review by Resident Inspectors

a. Inspection Scope

The inspectors reviewed the Unit 2 A and D RSHXs to determine their readiness and availability to perform their safety functions. The inspectors reviewed the system data maintained by the system engineer, maintenance rule information, specific commitments, and design basis information. The inspectors reviewed testing procedures and inspection results to confirm that the RSHXs were still able to perform their functions and that planned corrective actions were appropriate. The inspectors verified that significant heat exchanger performance issues were being entered into the licensees CAP and appropriately addressed.

b. Findings

No findings were identified.

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 December 9, 2014. The scenario was intended to exercise the entire operations crew and assess the ability of the operators to shut down and cool down the reactor plant while the site was undergoing a hostile action base (HAB) incident. 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.

• Unit 2 reactor trip due to unexpected opening of a reactor trip breaker.

• Unit 2 reactor startup.

b. Findings

No findings were identified.

.3 Annual Review of Licensee Requalification Examination Results

a. Inspection Scope

On March 21, 2014, the licensee completed the comprehensive biennial requalification written examinations and the annual requalification operating examinations required to be administered to all licensed operators in accordance with Title 10 of the CFR 55.59(a)(2), Requalification Requirements, of the NRCs Operators Licenses. The inspectors performed an in-office review of the overall pass/fail results of the individual operating examinations and the crew simulator operating examinations in accordance with Inspection Procedure (IP) 71111.11, Licensed Operator Requalification Program.

These results were compared to the thresholds established in Section 3.02, Requalification Examination Results, of IP 71111.11.

b. Findings

No findings were identified.

1R12 Maintenance Effectiveness

a. Inspection Scope

For the three 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 problems. 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 6.

• CR 563628, Missing bolts on #3 EDG piston cooling oil pipe cylinders 14 and 16

• CR 563028, "B" ESW pump tripped on high coolant temperature

• CR 564480, Unit 2 Main Turbine #4 Stop Valve Limit Switch intermittent indications

b. Findings

No findings were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

The inspectors evaluated, as appropriate, the five 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 October 21, Unit 1 and Unit 2 risk with the Unit 1 "A" charging (CH) pump, the Unit 2 EDG #2 air compressor, and the "B" ESW pump out for maintenance and Consequence Limiting System (CLS) logic testing in-progress.

• On October 27, Unit 1 and Unit 2 risk with #3 EDG out of service for an 18 month maintenance availability.

• On November 4, Unit 1 and Unit 2 risk with the auxiliary building "A" filtered exhaust fan tagged out for maintenance and CLS logic testing in-progress.

• On November 24, Unit 1 risk with 4KV emergency bus underfrequency testing in-progress.

• On 10 December, Unit 1 and Unit 2 risk while replacing the Unit 2 "A' CH/SW pump strainer.

b. Findings

No findings were identified.

1R15 Operability Evaluations

a. Inspection Scope

The inspectors reviewed the six 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 12. The inspectors reviewed the licensees corrective action program to verify deficiencies in operability determinations were being identified and corrected.

• CR 561802, Unit 2 Intermediate Range Nuclear Instruments under compensated

• CR 557706, ESGR Flooding with higher SW flow rate from chiller SW discharge piping

• CR 563897, 2-VS-F-42, ESGR emergency ventilation fan airflow readings unsatisfactory

• CR 566139, #2 EDG load control stopped while attempting to increase load

• CR 566486, #1 EDG output breaker indication indicates green and red concurrently

• CR 564824, Unit 1 "A" Outside RS Pump Seal Tank isolated

b. Findings

No findings were identified.

1R19 Post Maintenance Testing

a. Inspection Scope

The inspectors reviewed six 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.

• 2-OPT-EG-007, EDG 2 Starting Air System Refueling Interval Test, Revision 14, following compressor pressure switch calibration

• 0-ECM-1801-01, Westinghouse Type BF-BFD-or NBFD65NR Relay Replacement, Revision 28, after RPS relay replacement

• 0-OPT-SW-002, Emergency Service Water Pump 1-SW-P-1B Periodic Test, Revision 59, after suction bowl cleaning

• 0-OPT-EG-009, #3 EDG Major Maintenance Operability Test, Revision 54, after #3 EDG 18 month maintenance availability

• 1-ICM-RD-RPI-002, Computer Enhanced Rod Position Indication (CERPI)

Adjustments, Revision 4, after CERPI card replacement

• 2-PT-18.8, Charging Pump Service Water Performance Test, Revision 34, after SW strainer replacement

b. Findings

No findings were identified.

1R22 Surveillance Testing

a. Inspection Scope

For the six 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:

• 0-OPT-SW-002, Emergency Service Water Pump 1-SW-P-1B Performance Test, Revision 59 Surveillance Testing:

• 1-OSP-TM-001, Turbine Inlet Valve Freedom Test, Revision 40

• 2-PT-8.2, Reactor Protection Logic Test, Revision 26

• Change of engineering safety features (ESF) logic testing technical specification surveillance frequency from 18 month interval to 36 month interval RCS Leak Rate Determination:

• 0-NSP-RC-004, Establishing and Updating Reactor Coolant System (RCS)

Unidentified Leakage Baseline, Revision 3, Unit 1

• 0-NSP-RC-004, Establishing and Updating RCS Unidentified Leakage Baseline, Revision 3, Unit 2

b. Findings

No findings were identified.

1EP6 Drill Evaluation Emergency Preparedness (EP) Drill

a. Inspection Scope

On December 9, 2014, the inspectors reviewed and observed a licensee hostile action base EP drill involving a single unit reactor trip and reactor plant cooldown, loss of #1 and #2 EDGs, and a radioactive release from the spent fuel pool. 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.

OTHER ACTIVITIES

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

4OA1 Performance Indicator (PI) Verification

a. Inspection Scope

The inspectors performed a periodic review of the six following Unit 1 and 2 PIs 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. Specifically, the inspectors reviewed the Unit 1 and Unit 2 data reported to the NRC for the period October 1, 2013 through September 30, 2014. Documents reviewed included applicable NRC inspection reports, licensee event reports, operator logs, station performance indicators, and related CRs.

• Unit 1 & 2 High Pressure Injection MSPI

• Unit 1 & 2 Residual Heat Removal MSPI

• Unit 1 & 2 Cooling Water MSPI

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 CR 505930 Fire in Unit 2 RPS Due to Relay Failure

a. Inspection Scope

The inspectors performed a review regarding the licensees assessments and corrective actions associated with CR 505930, Fire in Unit 2 RPS Due to Relay Failure.

Specifically, on February 19, 2013, during the performance of 2-PT-8.1, RPS Logic Test, licensee instrument technicians working in the vicinity of the Unit 2 reactor protection A-train channel III rack reported that relay 2-RP-RLY-PRBYA started to smoke, caught fire, and then failed. 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 heavy reliance on monthly surveillance of relays in the reactor protection, safety injection (SI), and CLS systems as an alternative to a preventative maintenance program that included periodic replacement. 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 noted; however, that one additional corrective action is no longer scheduled to be accomplished. This corrective action was to initiate a long-term project to replace all the relays in the reactor protection, SI, and CLS systems. Although the project was initiated, it was cancelled before implementation. The apparent cause corrective action to develop a maintenance strategy to periodically replace relays in the reactor protection, SI, and CLS systems has been implemented. This action involves the periodic replacement of single point vulnerability and critical 1 relays. Critical 2 and non-critical relays will be replaced as needed. 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 reactor protection, SI and CLS systems.

.3 Annual Sample: Review of CRs 546028 and 553658 Failure of the "A" and "C" RSST

Load Tap Changers

a. Inspection Scope

The inspectors performed an in-depth review regarding the licensees evaluation and corrective actions associated with CRs 546028 and 553658, Failure of the "A" and "C" reserve station service transformer (RSST) Load Tap Changers (LTCs). Specifically, on April 22, 2014, the RSST C LTC stepped out of its calibrated bandwidth to its maximum level before moving back down to its normal operating band. On July 10, 2014, the RSST A LTC stepped out to increase 1J bus voltage to 4800 VAC and had to be manually adjusted back to its normal operating band. 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 and Observations

No findings were identified.

The licensee determined that the apparent cause was that the Beckwith Electric M-0067E LTC controller preventative maintenance strategy did not include a time-based replacement activity. The LTC controllers were approximately 30 years old and most likely had degraded electrical components which caused the LTC improper operation.

Additionally, the licensee determined from the manufacturer that the useful life of the controllers to be approximately 20 years. The licensees corrective actions involved the replacement of all RSST LTC controllers and updating the equipment reliability strategies for large power transformers to include time-based LTC controller replacement. The inspectors reviewed the corrective actions and all condition reports associated with the RSST LTC failures to verify that the corrective actions taken were effective. The inspectors did not identify any additional issues from this review. The inspectors determined the licensees evaluation of the issue appropriately identified the apparent and contributing causes. Additionally, 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 RSSTs.

.4 Annual Sample: Review of Operator Work Arounds

a. Inspection Scope

The inspectors performed a review regarding the licensees assessments and corrective actions for operator workarounds (OWAs). The inspectors reviewed the cumulative effects of the licensees OWAs and licensee procedure OP-AA-1700, Operations Aggregate Impact, Revision 6. The inspectors reviewed the data package associated with this procedure which included an evaluation of the cumulative effects of the OWAs on the operators ability to safely operate the plant and effectively respond to abnormal and emergency plant conditions. The inspectors reviewed and monitored licensee planned and completed corrective actions to address underlying equipment issues causing the OWAs. The inspectors also evaluated OWAs against the requirements of the licensees CAP as specified in PI-AA-200, Corrective Action, Revisions 23, 10 CFR 50, Appendix B, and OP-AA-100, "Conduct of Operations," Revision 28.

b. Findings and Observations

No findings were identified.

In general, the inspectors verified that the licensee has identified operator workaround problems at an appropriate threshold, entered them in the corrective action program, and has proposed or implemented appropriate corrective actions.

4OA3 Follow-up of Events and Notices of Enforcement Discretion (71153 - 1 Sample)

.1 (Closed) Licensee Event Report, 05000-281/2014-001-00, Reactor Trip Due to Loose

Termination on Reactor Trip Relay

a. Inspection Scope

On October 13, 2014, with Unit 2 at 100 percent power, Unit 2 experienced a reactor trip due to a spurious opening of the Unit 2 B reactor trip breaker. All three auxiliary feedwater pumps automatically started on low-low steam generator (SG) water level.

The rapid increase in SG pressure on the relief valve setpoints resulted in the lifting of all three SG power operated relief valves. The direct cause of the reactor trip was a loose screw on a reactor protection trip relay for the reactor trip breaker. The loose screw on the reactor protection trip breaker relay was tightened and the breaker was closed successfully. The inspectors reviewed the Licensee Event Report (LER), the associated root cause evaluation (RCE) and corrective actions, interviewed the license staff, and walked down associated components. This LER is closed.

b. Findings

Introduction:

An NRC-identified Green, NCV of Surry TS 6.4.A.7 was identified because Surry procedure 0-ECM-1801-01, Westinghouse Type BF - BFD - or NBFD65NR Relay Replacement, did not include a torque value for the RPS relay terminal screws to a field wiring connection. Subsequently, Unit 2 tripped on October 13, 2014, when a field wire connection became loose from the terminal end of a RPS trip relay and caused a reactor trip breaker to open.

Description:

On October 13, 2014, Surry Unit 2 automatically tripped from 100 percent power. The licensee conducted a post-trip review and discovered that the annunciator Turbine Tripped by Reactor Trip occurred approximately 0.6 seconds before an over power differential temperature (OPDT) trip signal was received by the RPS. This alarm occurs when either reactor trip breaker opens initiating a turbine trip signal. The B reactor trip breaker opened causing the control rods to drop to the bottom of the core.

Consequentially, delta flux became very negative, inducing a penalty on the OPDT and over temperature differential temperature (OTDT) setpoints. The second A reactor trip breaker opened due to OPDT and OTDT setpoints being exceeded.

Based on indications that a reactor trip breaker opened without a reactor trip signal, the licensee concentrated their troubleshooting efforts in the reactor trip breaker control circuitry. Voltage readings found that there was a zero volt output on RPS trip relay 2-RP-RLY-RT2YB (indicating a trip signal was present). Further investigation found a loose wiring connection on the 2-RP-RLY-RT2YB relay terminal that was causing the zero volt condition. The licensee tightened the terminal screw of the relay and verified voltage was present at the contact point. After voltage readings were determined to be satisfactory, the reactor trip breaker was checked and functioned normally. As part of extent of condition testing, the licensee checked the tightness of all terminals on all 28 of the Unit 2 RPS trip relays and found that 8 of the 28 relays had loose terminations anywhere from 1/4 to 3/4 turns loose on the termination screw. The issue was documented in the CAP as CR 561820.

The licensee conducted a RCE and determined the root cause to be that RPS relay terminal screws were tightened hand tight resulting in inconsistent torque applied to the terminal screws. The amount of tightness of the electrical wiring termination was left up to the skill of the craft of the technician when relay wiring was disconnected and then reconnected. Surrys procedure for RPS relay installation stated to tighten all relay contact terminal screws without specifying a torque value. Surry also discussed in their RCE that Westinghouse (the relay vendor) had a proprietary torque specifications for the relay terminal screws, but did not discuss why Surry did not have this value in procedure 0-ECM-1801-01.

The resident inspectors conducted further inspection on the issue and performed a historical review of the 0-ECM-1801-01 procedure revisions. The residents discovered that the correct Westinghouse torque specification had been added to procedure 0-ECM-1801-01 in revision 10 that was issued in 1995, but had been removed when revision 13 was issued in 1999. The licensee procedure action request (PAR) for revision 10 had attached to it the Westinghouse equipment qualification data sheet (EQDS) which stated the correct torque value for relay terminal screws on the Westinghouse relays. The PAR for revision 13 requested the removal of the torque value from the procedure for the spare contacts on the relays, but the procedure revision, when issued, had removed any mention of the torque specification and instead inserted the words tighten all relay contact terminal screws. This wording exists in the current revision (Rev 28) of the procedure. The residents also asked the licensee to check the spare relays in stock in the supply warehouse on site. The licensee found that the EQDS was in each spare relay box, but the warehouse process when issuing these relays as a replacement part was to pull the EQDS out of the box and file it with other certification paperwork. This warehouse process prevented the EQDS from being included in the work package and the potential for the licensee to recognize that a torque value did exist.

The residents also reviewed the vendor technical manual (VTM), 38-W893-00025, Instruction Manual for the Reactor Protection Relay Cabinets and the Engineered Safeguards Relay Cabinets. This manual had not been revised for the Westinghouse EQDS for the BF and BFD relays. Revision 0 of EQDS-1030 was dated January, 1988.

The latest revision (Rev 5) to 38-W893-00025 was dated August, 2007. When the PAR was initiated in 1995 for the 0-ECM-1801-01 procedure change to provide the torque specification for the relays, a vendor technical manual control change to 38-W893-00025 should have been initiated at about the same time in accordance with Surry procedure VPAP-0602, Vendor Technical Manual Control. Of note, this procedure has since been changed to ER-AA-VTI-101, Vendor Technical Information Program.

Analysis:

The inspectors concluded that the failure of the licensee to specify a torque value in procedure 0-ECM-1801-01, Westinghouse Type BF - BFD - or NBFD65NR Relay Replacement, was a performance deficiency that was within the licensees ability to foresee and correct. Specifically, the licensee removed the correct torque value from the procedure based on a licensee PAR that was incorrectly implemented. The licensee had opportunity to correct this deficiency when replacing RPS relays. The Westinghouse documentation that stated the correct torque value was not issued with the replacement part when it was drawn from the warehouse; nor was the documentation included in W893-00025, the VTM for the RPS relay cabinets. As a consequence of not specifying a torque value for RPS relay electrical terminations and leaving the torque value applied up to the technician completing the work, an RPS trip relay was inadequately torqued and subsequently was the direct cause of the Unit 2 reactor trip on October 13, 2014. The inspectors determined that the PD was more than minor because it was associated with the procedural quality attribute of the Initiating Events Cornerstone and adversely affected the cornerstone objective to limit the likelihood of events that upset stability and challenge critical safety functions during shutdown as well as power operations. Specifically, the procedure that controlled the connection of electrical termination to RPS relays did not specify a torque value and left it up to the technician to determine the tightness of the connection.

Using Manual Chapter 0609.04, Initial Characterization of Findings, Table 2, dated June 19, 2012; the finding was determined to affect the Initiating Events Cornerstone.

The inspectors screened the finding using Manual Chapter 0609, Appendix A, Significance Determination Process for Findings at-Power, dated June 19, 2012, and determined that it screened as Green because the deficiency did not cause a loss of mitigation equipment relied upon to transition the plant to a stable shutdown condition.

This finding has a cross-cutting aspect in the documentation component of the human performance area, H.7, because the organization failed to maintain complete, accurate and up-to-date documentation for the replacement of RPS relays. The cross-cutting aspect is considered present performance because the licensee had recently replaced RPS relays (one on Unit 1 in May 2014 and six on Unit 2 in January 2014) and had the opportunity to review the replacement relay EQDS in the supply warehouse, which contained the relay torque specification.

Enforcement:

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. Maintenance on the RPS relays is implemented by Surry procedure 0-ECM-1801-01, Westinghouse Type BF - BFD - or NBFD65NR Relay Replacement.

Contrary to the above, the licensee did not include a torque value for the RPS relay terminal screws to a field wiring connection. Specifically, the licensee removed the correct torque value from procedure 0-ECM-1801-01 based on a PAR that was incorrectly implemented. As a result, maintenance on RPS relays, specifically the torque applied to relay terminal screws, was left up to the skill of the craft of the technician, and directly resulted in the loose RPS wire connection and Unit 2 trip on October 13, 2014.

Because the licensee entered the issue into their corrective action program as CR 561820 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 05000281/2014005-01, Unit 2 Trip Due to Loose RPS Wire Connection.

4OA5 Other Activities

Independent Spent Fuel Storage Installation (ISFSI) Inspections (IP 60855.1)

a. Inspection Scope

The inspectors reviewed reported changes made to the licensees procedures and programs for the Independent Spent Fuel Storage Installation (ISFSI) to verify the changes made were consistent with the license and certificate of compliance, and did not reduce the effectiveness of the program. The inspectors, through direct observation and independent evaluation, verified cask loading activities were performed in a safe manner and in compliance with approved procedures. Based on direct observation and review of selected records, the inspectors verified the licensee had properly identified each fuel assembly and insert placed in the ISFSI, had recoded the parameters and characteristics of each fuel assembly and insert, and had maintained a record of each as a controlled document. Inspection activities were associated with casks DOM-32PTH-044-C and DOM-32PTH-045-C. Activities observed include: transport and storage of cask DOM-32PTH-045-C, loading of spent fuel in cask DOM-32PTH-044-C and DOM-32PTH-045-C, drying and seal welding activities on DOM-32PTH-044-C, and the heavy lift to remove DOM-32PTH-044-C from the spent fuel building.

The inspectors reviewed the design limitations for each dry shielded cask and compared the specified cask loading to the casks loading limitations and Technical Specification requirements. The inspectors verified limitations for heavy load lifts in and around the spent fuel pool were adhered to and incorporated into the licensees procedures.

b. Findings

No findings were identified.

4OA6 Meetings, Including Exit

Exit Meeting Summary

On January 28, 2015, the inspection results were presented to Mr. L. Lane 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.

4OA7 Licensee-Identified Violation

The following findings of very low significance (Green) were identified by the licensee and are violations of NRC requirements which meet the criteria of the NRC Enforcement Policy for characterization as NCVs.

• Surry TS 6.4.A.3 requires, in part, that detailed written procedures with appropriate instructions shall be provided for conditions that include: action to be taken for specific and foreseen malfunctions of systems or components including alarms, primary system leaks and abnormal reactivity changes. Contrary to the above, on September 4, 2014, the licensee discovered that the annunciator response procedure, 0-VSP-M4, Flood Control Panel Trouble, used to mitigate ESGR flooding, did not have specific steps to direct an operator on how to isolate a leak.

This was revealed when the licensee discovered that their current PRA model assumed an incorrect low flow rate for a break in SW piping in mechanical equipment room MER-3. Consequentially, the licensee had to take compensatory actions to isolate the SW flow path by shutting 1-SW-846, MER-3 chiller SW to Unit 1 discharge tunnel, until the PRA model was analyzed with the new flow rate and 0-VSP-M4 was changed. This finding is of very low safety significance (Green)because the completed PRA analysis did not affect the design or qualification of the SW system and it did not represent a loss of system or train safety function. This issue was entered into the licensees CAP as CR 557706 and the annunciator response procedure was revised with the correct operator actions.

• Surry TS 6.4.D requires, in part, that procedures described in section 6.4.A shall be followed. Surry TS 6.4.A.1 requires, in part, that detailed written procedures with appropriate check-off lists and instructions shall be provided for conditions which include: normal startup, operation, and shutdown of a unit, and of all systems and components involving nuclear safety of the station. These requirements are implemented, in part, by Dominion procedure 1-OP-RS-001A, Outside Recirculation Spray System Alignment, Revision 9, and independently verified, in part, by using Dominion procedure PI-AA-500, Verification Practices, Revision 3. Contrary to the above, on November 13, 2013, Dominion personnel failed to independently verify, in accordance with PI-AA-500, 1-RS-92 and 1-RS-97, the Unit 1 A OSRS pump seal tank inlet and outlet isolation valves were tie-wrapped open when performing procedure 1-OP-RS-001A. Consequentially, on November 9, 2014, the licensee found both of these valves tie-wrapped shut while performing a check of all Unit 1 valve locking devices. The licensee declared the Unit 1 A OSRS pump inoperable until the valves were repositioned opened. This finding is of very low safety significance (Green) because it did not affect the design or qualification of the recirculation spray system and it did not represent a loss of system or train safety function. This issue was entered into the licensees CAP as CR 564824.

ATTACHMENT:

SUPPLEMENTARY INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

J. Eggart, Manager, Radiation Protection & Chemistry

B. Ferlis, Auxiliary System Engineer

B. Garber, Supervisor, Station Licensing

C. Grady, Supervisor, Auxiliary Systems

A. Harrow, Manager, Organizational Effectiveness

R. Hebert, Manager, Nuclear Systems Engineering

L. Hilbert, Manager, Outage and Planning

R. Johnson, Manager, Operations

L. Lane, Site Vice President

D. Lawrence, Director, Station Safety and Licensing

C. Olsen, Director, Station Engineering

J. Pollard, Station Licensing

R. Rosenberger, Manager, Design Engineering

R. Scanlan, Manager, Maintenance

R. Simmons, Plant Manager

M. Smith, Manager, Nuclear Oversight

K. Spencer, Assistant Manager, Maintenance

E. Turko, Supervisor, ISI/IST Materials

N. Turner, Supervisor, Emergency Preparedness

LIST OF ITEMS

Opened and Closed

05000281/2014005-01 NCV Unit 2 Trip Due to Loose RPS Wire Connection (Section 4OA3)

Closed

05000281/2014-002-00 LER Reactor Trip Due to Loose Termination on Reactor Trip Relay (Section 4OA3)