IR 05000324/2013005

IR 05000325-13-005, 05000324-13-005, 05000325-13-502, 05000324-13-502; 10/01/13 - 12/31/13; Brunswick Steam Electric Plant, Units 1 & 2; Operability Determinations and Post Maintenance Testing

ML14035A190
Person / Time
Site:	Brunswick
Issue date:	02/04/2014
From:	Hopper G NRC/RGN-II/DRP/RPB4
To:	Hamrick G Duke Energy Progress
References
IR-13-005, IR-13-502
Download: ML14035A190 (35)

Text

UNITED STATES bruary 4, 2014

SUBJECT:

BRUNSWICK STEAM ELECTRIC PLANT - NRC INTEGRATED INSPECTION REPORT NOS.: 05000325/2013005, 05000324/2013005, 05000325/2013502 AND 05000324/2013502

Dear Mr. Hamrick:

On December 31, 2013, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Brunswick Unit 1 and 2 facilities. The enclosed integrated inspection report documents the inspection findings, which were discussed on January 16, 2014, with you and other members of your staff.

The inspection examined activities conducted under your license as they relate to safety and compliance with the Commissions rules and regulations and with the conditions of your license.

The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel.

One NRC-identified finding and one self-revealing finding of very low safety significance (Green)

were identified during this inspection. These two findings were determined to involve a violation of NRC requirements. Additionally, a licensee-identified violation which was determined to be of very low safety significance is listed in this report. The NRC is treating these findings as non-cited violations (NCVs) consistent with Section 2.3.2.a of the Enforcement Policy.

If you contest the violations or the significance of the violations, 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 Brunswick Steam Electric Plant.

If you disagree with the 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 Brunswick Steam Electric Plant. 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 0310. Cross-cutting aspects identified in the last six months of 2013 using the previous terminology will be converted to the latest revision in accordance with the cross-reference in IMC 0310. The revised cross-cutting aspects will be evaluated for cross-cutting themes and potential substantive cross-cutting issues in accordance with IMC 0305 starting with the CY 2014 mid-cycle assessment review.

In accordance with 10 Code of Federal Regulations 2.390, Public Inspections, Exemptions, Requests for Withholding, of the NRC's Rules of Practice, a copy of this letter, its enclosure, and your response (if any) will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records System (PARS) component of NRC's Agencywide Documents Access and Management System (ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,

/RA/

George T. Hopper, Chief Reactor Projects Branch 4 Division of Reactor Projects Docket Nos.: 50-325, 50-324 License Nos.: DPR-71, DPR-62

Enclosure:

Inspection Report 05000325, 324/2013005, 325/2013502, 324/2013502 w/Attachment: Supplemental Information

REGION II==

Docket Nos.: 50-325, 50-324 License Nos.: DPR-71, DPR-62 Report Nos.: 05000325/2013005, 05000324/2013005, 05000325/2013502, 05000324/2013502 Licensee: Duke Energy Progress, Inc.

Facility: Brunswick Steam Electric Plant, Units 1 & 2 Location: 8470 River Road, SE Southport, NC 28461 Dates: October 1, 2013 through December 31, 2013 Inspectors: M. Catts, Senior Resident Inspector M. Schwieg, Resident Inspector J. Austin, Senior Resident Inspector (Section 1R12Q)

J. Dodson, Senior Project Engineer (Section 1R07, 1R12, 1R22, 4OA2 4OA3, 4OA7)

D Jackson, Project Engineer (Section 1R05)

J. Laughlin, Emergency Preparedness Inspector (Section 1EP4)

P. Lessard, Resident Inspector (Section 1R15)

M. Bates, Senior Operations Engineer (Section 1R11.3)

Approved by: George T. Hopper, Chief Reactor Projects Branch 4 Division of Reactor Projects Enclosure

SUMMARY OF FINDINGS

IR 05000325/2013005, 05000324/2013005, 05000325/2013502, 05000324/2013502; 10/01/13 - 12/31/13; Brunswick Steam Electric Plant, Units 1 & 2; Operability Determinations and Post Maintenance Testing.

This report covers a three-month period of inspection by resident inspectors, regional inspectors, and by one emergency preparedness inspector. Two Green findings were identified.

The significance of most findings is indicated by their color (Green, White, Yellow, Red) using Inspection Manual Chapter (IMC) 0609, issued June 19, 2012, Significance Determination Process (SDP). The cross-cutting aspects were determined using IMC 0310, Components Within the Cross-Cutting Areas, issued October 28, 2011. All violations of NRC requirements are dispositioned in accordance with the NRCs Enforcement Policy dated January 28, 2013.

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

Cornerstone: Mitigating Systems

Green.

An NRC-identified Green NCV of 10 CFR Part 50, Appendix B, Criterion III,

Design Control, was identified for the failure of the licensee to verify the adequacy of design of the emergency diesel generator (EDG) service water flow. Specifically, from May 1, 1989, until October 28, 2013, Calculation M-89-0008, contained non-conservative values for EDG maximum loading, service water inlet temperatures, and heat exchanger fouling factor, resulting in a non-conservative calculation for required service water flow to the EDG jacket water heat exchanger, which called into question the operability of EDG 3. The licensee re-performed Calculation M-89-0008 and determined EDG 3 was operable. The licensee entered this issue into the corrective action program (CAP) as nuclear condition report (NCR) 592035.

The inspectors determined that the failure of the licensee to have an accurate calculation for required service water flow to the EDG jacket water heat exchanger was a performance deficiency. The finding was more than minor because it was associated with the design control attribute of the Mitigating Systems Cornerstone and adversely affects the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the non-conservative calculation called into question the operability of EDG 3. Using IMC 0609, Appendix A, issued June 19, 2012, the SDP for Findings At-Power, the inspectors determined the finding was of very low safety significance (Green) because the finding did not affect the design or qualification of a mitigating structures, systems, and components (SSC), the finding did not represent a loss of system and/or function, the finding did not represent an actual loss of a function of a single train for greater than the technical specification (TS) allowed outage time, the finding did not represent an actual loss of a function of one or more non-TS trains of equipment, and did not screen as potentially risk-significant due to a seismic, flooding, or severe weather initiating event. The finding has a cross-cutting aspect in the area of human performance associated with the resources attribute because the licensee did not have complete, accurate and up-to-date design documentation for EDG service water flow. Specifically, due to the inspectors questions, Calculation M-89-0008 required revision due to non-conservatisms in August 2013 and in November 2013. H.2(c) (Section 1R15.1)

Green.

A self-revealing Green NCV of TS 5.4.1a, Procedures, was identified for the failure of the licensee to have an adequate procedure for preventative maintenance on the 1B residual heat removal (RHR) room cooler damper limit switch.

Specifically, between May 1990 and September 26, 2013, the licensee did not have an adequate preventative maintenance procedure to replace the 1B RHR room cooler damper limit switch and to tighten the paddle arm on the limit switch. This resulted in the failure of the 1B RHR room cooler to start and the inoperability of the 1B RHR train. The licensee replaced the limit switch on the damper, tightened the paddle arm on the limit switch, returned the room cooler to operable, and entered this issue into the CAP as NCR 607986.

The inspectors determined that the failure of the licensee to have an adequate procedure to replace the 1B RHR room cooler limit switch and tighten the limit switch paddle arm was a performance deficiency. The finding was more than minor because it was associated with the equipment performance attribute of the Mitigating Systems Cornerstone and adversely affects the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the failure to replace the limit switch and tighten the limit switch paddle arm resulted in a failure of the cooler fan and damper, and the inoperability of the 1B RHR train. Using IMC 0609, Appendix A, issued June 19, 2012, the SDP for Findings At-Power, the inspectors determined the finding was of very low safety significance (Green) because the finding did not affect the design or qualification of a mitigating SSC, the finding did not represent a loss of system and/or function, the finding did not represent an actual loss of a function of a single train for greater than the TS allowed outage time, the finding did not represent an actual loss of a function of one or more non-TS trains of equipment, and did not screen as potentially risk-significant due to a seismic, flooding, or severe weather initiating event. The finding does not have a cross-cutting aspect since the performance deficiency is not indicative of current plant performance. Vendor Manual QTR155, NAMCO Controls, which required periodic replacement of the limit switch and checking the limit switch for tightness, was provided to the licensee in May 1990. (Section 1R19)

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

REPORT DETAILS

Summary of Plant Status

Unit 1 began the inspection period at rated thermal power (RTP). On November 22, 2013, power was reduced to 70 percent for a control rod sequence exchange and returned to RTP on November 24, 2013. Unit 1 operated at or near RTP for the remainder of the inspection period.

Unit 2 began the inspection period at RTP. On October 25, 2013, power was reduced to 70 percent for a control rod sequence exchange and returned to RTP on October 26, 2013. On October 28, 2013, power was reduced to 73 percent for a control rod sequence exchange and returned to RTP on October 29, 2013. On November 16, 2013, power was reduced to 78 percent to recover degraded control rod 38-31 and returned to RTP on November 17, 2013.

On December 27, 2013, power was reduced to 20 percent to repair the no load disconnect switch (NLDS). Power was returned to RTP on December 31, 2013, and remained at or near RTP for the remainder of the inspection period.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R01 Adverse Weather Protection

.1 Winter Seasonal Readiness Preparations (71111.01 - 1 cold weather sample)

a. Inspection Scope

The inspectors conducted a review of the licensees preparations for winter conditions to verify that the plants design features and implementation of procedures were sufficient to protect mitigating systems from the effects of adverse weather. Documentation for selected risk-significant systems was reviewed to ensure that these systems would remain functional when challenged by inclement weather. During the inspection, the inspectors focused on plant-specific design features and the licensees procedures used to mitigate or respond to adverse weather conditions. Additionally, the inspectors reviewed the Updated Final Safety Analysis Report (UFSAR) and performance requirements for systems selected for inspection, and verified that operator actions were appropriate as specified by plant-specific procedures. Cold weather protection, such as heat tracing and area heaters, was verified to be in operation where applicable. The inspectors also reviewed CAP items to verify that the licensee was identifying adverse weather issues at an appropriate threshold and entering them into their CAP in accordance with station corrective action procedures. The inspectors reviews focused specifically on the following plant areas due to their risk significance or susceptibility to cold weather issues:

• Service Water Building

• Intake Structure and Circulating Water Pump Bay

• EDG Building Documents reviewed are listed in the Attachment.

b. Findings

No findings were identified.

.2 Readiness for Impending Adverse Weather Condition (71111.01 - 1 adverse weather

sample)

a. Inspection Scope

On November 26, 2013, the national weather service issued a severe weather advisory for the plant area and inspectors reviewed the licensees overall preparations/protection for tornado warning conditions. The inspectors walked down areas of the plant susceptible to high winds, including the licensees emergency alternating current (AC)power systems. The inspectors evaluated the licensee staffs preparations against the sites procedures and determined that the staffs actions were adequate. During the inspection, the inspectors focused on plant-specific design features and the licensees procedures used to respond to specified adverse weather conditions. The inspectors also toured the plant grounds to look for any loose debris that could become missiles during a tornado. The inspectors evaluated operator staffing and accessibility of controls and indications for those systems required to control the plant. Additionally, the inspectors reviewed the UFSAR and performance requirements for systems selected for inspection, and verified that operator actions were appropriate as specified by plant specific procedures. The inspectors also reviewed a sample of CAP items to verify that the licensee identified adverse weather issues at an appropriate threshold and dispositioned them through the corrective action program in accordance with station corrective action procedures. Documents reviewed are listed in the Attachment.

b. Findings

No findings of were identified.

1R04 Equipment Alignment

Quarterly Partial System Walkdowns (71111.04Q - 3 samples)

a. Inspection Scope

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

• Unit 2 standby liquid control system on October 31, 2013

• EDG 1 on November 4, 2013

• Unit 1 standby gas treatment system on November 14, 2013 The inspectors selected these systems based on their risk-significance relative to the reactor safety cornerstones at the time they were inspected. The inspectors attempted to identify any discrepancies that could impact the function of the system, and, therefore, potentially increase risk. The inspectors reviewed applicable operating procedures, system diagrams, UFSAR, TS requirements, outstanding work orders, NCRs, and the impact of ongoing work activities on redundant trains of equipment in order to identify conditions that could have rendered the systems incapable of performing their intended functions. The inspectors also walked down accessible portions of the systems to verify that system components and support equipment were aligned correctly and were operable. The inspectors examined the material condition of the components and observed operating parameters of equipment to verify that there were no obvious deficiencies. The inspectors also verified that the licensee had properly identified and resolved equipment alignment problems that could cause initiating events or impact the capability of mitigating systems or barriers and entered them into the corrective action program with the appropriate significance characterization. Documents reviewed are listed in the Attachment.

b. Findings

No findings were identified.

1R05 Fire Protection

Quarterly Resident Inspector Tours (71111.05Q - 5 samples)

a. Inspection Scope

The inspectors conducted fire protection walkdowns which were focused on availability, accessibility, and the condition of firefighting equipment in the following risk-significant plant areas:

• 1PFP-CB3 and 1PFP-CB4, Unit 1 and Unit 2 stairwell 23 foot and 49 foot elevation

• 1PFP-RB1-1k and 1PFP-RB1-1m, Unit 1 Reactor Building east 80 foot elevation and Refuel Floor 117 foot elevation

• 1 PFP-RB2-1k and 1PFP-RB2-1m, Unit 2 Reactor Building east 80 foot elevation and Refuel Floor 117 foot elevation

• 0PFP-DG-1, DGB basement 2 foot elevation

• 1PFP-TB1-1o, turbine operating floor 70 foot elevation The inspectors reviewed areas to assess if the licensee had implemented a fire protection program that adequately controlled combustibles and ignition sources within the plant, effectively maintained fire detection and suppression capability, maintained passive fire protection features in good material condition, and had implemented adequate compensatory measures for out of service, degraded or inoperable fire protection equipment, systems, or features in accordance with the licensees fire plan.

The inspectors selected fire areas based on their overall contribution to internal fire risk as documented in the plants Individual Plant Examination of External Events with later additional insights, their potential to impact equipment which could initiate or mitigate a plant transient, or their impact on the plants ability to respond to a security event. The inspectors verified that fire hoses and extinguishers were in their designated locations and available for immediate use; that fire detectors and sprinklers were unobstructed, that transient material loading was within the analyzed limits; and that fire doors, dampers, and penetration seals were in satisfactory condition. The inspectors also verified that minor issues identified during the inspection were entered into the licensees CAP. Documents reviewed are listed in the Attachment.

b. Findings

No findings were identified.

1R06 Flood Protection Measures

Annual Review of Cables Located in Underground Bunkers/Manholes

a. Inspection Scope

The inspectors conducted an inspection of underground bunkers/manholes subject to flooding that contain cables whose failure could disable risk-significant equipment. The inspectors performed walkdowns of risk-significant areas, including manhole MH-6NW, to verify that the cables were not submerged in water, that cables and/or splices appear intact and to observe the condition of cable support structures. When applicable, the inspectors verified proper dewatering device (sump pump) operation and verified level alarm circuits are set appropriately to ensure that the cables would not be submerged.

Where dewatering devices were not installed; the inspectors ensured that drainage was provided and was functioning properly. Documents reviewed are listed in the

.

b. Findings

No findings were identified.

1R07 Heat Sink Performance

a. Inspection Scope

The EDG 3 jacket water heat exchanger was selected as a sample. Inspectors reviewed the data/reports for the tests for any obvious problems or errors, verified that the licensee utilized the periodic maintenance method outlined in EPRI NP-7552, Heat Exchanger Performance Monitoring Guidelines, reviewed the biofouling controls, reviewed heat exchanger inspection and cleanliness of tubes, reviewed operations data, determined if heat exchanger was correctly categorized under the Maintenance Rule and verified if it was receiving the required maintenance. Documents reviewed are listed in the Attachment.

b. Findings

The enforcement aspects associated with this issue are discussed in Section 1R15.1 of this report.

1R11 Licensed Operator Requalification Program

.1 Quarterly Review of Licensed Operator Requalification Testing and Training

(71111.11Q - 1 sample)

a. Inspection Scope

On December 10, 2013, the inspectors observed a crew of licensed operators in the plants simulator during licensed operator requalification examinations to verify that operator performance was adequate, evaluators were identifying and documenting crew performance problems, and to ensure that training was being conducted in accordance with licensee procedures. The inspectors evaluated the following areas:

• Licensed operator performance

• Crews clarity and formality of communications

• Ability to take timely actions in the conservative direction

• Prioritization, interpretation, and verification of annunciator alarms

• Correct use and implementation of abnormal and emergency procedures

• Control board manipulations

• Oversight and direction from supervisors

• Ability to identify and implement appropriate TS actions and Emergency Plan actions and notifications The crews performance in these areas was compared to pre-established operator action expectations and successful critical task completion requirements. Documents reviewed are listed in the Attachment.

b. Findings

No findings were identified.

.2 Quarterly Review of Licensed Operator Performance in the Main Control Room

(71111.11Q - 1 sample)

a. Inspection Scope

Inspectors observed and assessed licensed operator performance in the plant and main control room, particularly during periods of heightened activity or risk and where the activities could affect plant safety. Specifically, on October 1, 2013, the inspectors observed Unit 1 evolutions following the loss of the 1A RFP lube oil temperature control.

The inspectors reviewed various licensee policies and procedures listed in the

. The inspectors evaluated the following areas:

• Operator compliance and use of procedures

• Control board manipulations

• Communication between crew members

• Use and interpretation of plant instruments, indications and alarms

• Use of human error prevention techniques

• Documentation of activities, including initials and sign-offs in procedures

• Supervision of activities, including risk and reactivity management

• Pre-job briefs and crew briefs

b. Findings

No findings were identified.

.3 Annual Review of Licensee Requalification Examination Results

a. Inspection Scope

On December 23, 2013, the licensee completed the comprehensive biennial requalification written examinations and annual requalification operating tests required to be administered to all licensed operators in accordance with 10 CFR 55.59(a)(2). The inspectors performed an in-office review of the overall pass/fail results of the written examinations, individual operating tests and the crew simulator operating tests. These results were compared to the thresholds established in Inspection Manual Chapter (IMC)0609, Significance Determination Process, Appendix I, Operator Requalification Human Performance Significance Determination Process.

b. Findings

No findings were identified.

1R12 Maintenance Effectiveness

a. Inspection Scope

The inspectors evaluated degraded performance issues involving the following risk-significant systems:

• Unit 1 and Unit 2 safety-related 480V transformer replacements in April - May 2013

• Unit 2 safety relief valves (SRVs), four of eleven setpoint failures on April 30, 2013

• Unit 1 rod position information system, more than nine control rods declared inoperable on May 29, 2013

• Unit 2 EDG 3 heat exchanger fouling on November 14, 2013 The inspectors reviewed events where ineffective equipment maintenance may have resulted in equipment failure or invalid automatic actuations of Engineered Safeguards Systems and independently verified the licensee's actions to address system performance or condition problems in terms of the following:

• Implementing appropriate work practices

• Identifying and addressing common cause failures

• Scoping of systems in accordance with 10 CFR 50.65(b) of the maintenance rule

• Characterizing system reliability issues for performance

• Charging unavailability for performance

• Trending key parameters for condition monitoring

• Ensuring 10 CFR 50.65(a)(1) or (a)(2) classification or re-classification; and verifying appropriate performance criteria for SSCs, /functions classified as (a)(2) or appropriate and adequate goals and corrective actions for systems classified as (a)(1)

The inspectors assessed performance issues with respect to the reliability, availability, and condition monitoring of the system. In addition, the inspectors verified maintenance effectiveness issues were entered into the CAP with the appropriate significance characterization. Documents reviewed are listed in the Attachment.

.1 (Opened) URI 05000325/2013005-01, Failure of Transformer Common C and Loss of

Emergency Core Cooling System Keepfill

Introduction.

The inspectors opened an unresolved item (URI) to determine if a performance deficiency exists with the loss of Transformer Common C and the emergency core cooling system (ECCS) keepfill system.

Description.

On February 22, 2012, the Common C 4160/480V transformer failed. This resulted in a loss of power to the circulating water intake pump (CWIP) traveling screen motors, which lead to high delta-pressure across the traveling screens. The CWIP 1B tripped due to high delta-pressure across its associated traveling screen. In anticipation of a loss of condenser vacuum, the licensee inserted a manual reactor SCRAM on Unit 1. As a result of the SCRAM, reactor water level reached the Reactor Water Level -

Low Level 1 actuation set point and the Primary Containment Isolation System (PCIS)

Groups 2 and 6 isolations occurred. Additionally, the Main Steam Isolation Valves (MSIVs) (PCIS Group 1) were manually closed prior to reaching the Condenser Vacuum

- Low actuation set point.

Also, a loss of the Common C Transformer resulted in the loss of the demineralized water transfer pumps, which is the source of keepfill for the ECCS piping. With the loss of keepfill, ECCS systems started to depressurize, with Unit 1 ECCS depressurizing in 17 minutes and Unit 2 ECCS depressurizing in 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> and 29 minutes. With depressurized ECCS, both units entered TS 3.0.3. The licensee provided temporary power to a single demineralized water pump and successfully filled and vented the ECCS within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> and 16 minutes of the event.

The inspectors opened an URI to determine if a performance deficiency exists with the loss of Transformer Common C and the ECCS keepfill. The licensee entered this issue in the CAP as NCR 519193. This issue is being tracked as URI 05000325/2013005-01, Failure of Transformer Common C and Loss of Emergency Core Cooling System Keepfill.

.2 Unit 2 SRV Setpoint Failures

The enforcement aspects associated with this issue are discussed in Section 40A7 of this report.

1R13 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

The inspectors reviewed the licensee's evaluation and management of plant risk for the maintenance and emergent work activities affecting risk-significant equipment listed below to verify that the appropriate risk assessments were performed prior to removing equipment for work:

• Unit 1 elevated risk due to planned surveillance test 0MST-RHR26Q, RHR Core Spray Low Reactor Pressure Permissive Trip Unit Channel Calibration on October 9, 2013

• Unit 2 elevated risk due to EDG 3 outage on November 13, 2013

• Unit 1 elevated risk due to EDG 1 repair on November 25, 2013

• Unit 1 elevated risk due to EDG 2 modifications on December 9, 2013

• Unit 1 elevated risk due to 1B-2 cell 55 replacement on December 20, 2013 These activities were selected based on their potential risk-significance relative to the reactor safety cornerstones. As applicable for each activity, the inspectors verified that risk assessments were performed as required by 10 CFR 50.65(a)(4) and were accurate and complete. When emergent work was performed, the inspectors verified that the plant risk was promptly reassessed and managed. The inspectors reviewed the scope of maintenance work, discussed the results of the assessment with the licensee's probabilistic risk analyst or shift technical advisor, and verified plant conditions were consistent with the risk assessment. The inspectors also reviewed TS requirements and walked down portions of redundant safety systems, when applicable, to verify risk analysis assumptions were valid and applicable requirements were met. Documents reviewed are listed in the Attachment.

b. Findings

No findings were identified.

1R15 Operability Evaluations

.1 Operability Evaluations

a. Inspection Scope

The inspectors reviewed the following issues:

• Low service water flow to EDG 3 on January 12, 2013

• High Pressure Coolant Injection/Reactor Core Isolation Cooling condenser drain line back pressure orifice bypass valve 2-MVD-V5002 found open when normally closed on June 24, 2013

• Unit 2 2B RHR seal cooler failure on October 11, 2013

• EDG 3 starting air flange pitting on October 15, 2013

• 2D RHR service water motor oil cloudiness on October 24, 2013

• Unit 2 control rod 38-31 degraded condition on November 7, 2013 The inspectors selected these potential operability issues based on the risk-significance of the associated components and systems. The inspectors evaluated the technical adequacy of the evaluations to ensure that TS operability was properly justified and the subject component or system remained available such that no unrecognized increase in risk occurred. The inspectors compared the operability and design criteria in the appropriate sections of the TS and UFSAR to the licensees evaluations, to determine whether the components or systems were operable. Where compensatory measures were required to maintain operability, the inspectors determined whether the measures in place would function as intended and were properly controlled. The inspectors determined, where appropriate, compliance with bounding limitations associated with the evaluations. Additionally, the inspectors also reviewed a sampling of corrective action documents to verify that the licensee was identifying and correcting any deficiencies associated with operability evaluations. Documents reviewed are listed in the

.

b. Findings

Inadequate Design Control for Required Service Water Flow to the Emergency Diesel Generators

Introduction.

An NRC-identified Green NCV of 10 CFR Part 50, Appendix B, Criterion III, Design Control, was identified for the failure of the licensee to verify the adequacy of design of the EDG service water flow. Specifically, from May 1, 1989, until October 28, 2013, Calculation M-89-0008, contained non-conservative values for EDG maximum loading, service water inlet temperatures, and heat exchanger fouling factor, resulting in a non-conservative calculation for required service water flow to the EDG jacket water heat exchanger, which called into question the operability of EDG 3.

Description.

On May 1, 1989, the licensee performed Calculation M-89-0008, Revision 0, to determine the required service water flow rate to the EDG jacket water heat exchanger when the service water inlet temperature was at a maximum of 90 degrees Fahrenheit. The calculation assumed an EDG loading of 3500 kilowatt (kW).

The required service water flow rate during a design basis accident was determined to be 350 gallons per minute (gpm).

On January 14, 2013, the licensee measured the service water flow rate to the EDG 3 jacket water heat exchanger and found flow to be in the range of 351 to 358 gpm. The expected flow rate was 900 gpm to 1100 gpm. After visual inspection, it was determined EDG 3 service water outlet valve 2-SW-V208 was throttled to 1-1.25 turns instead of the required 2.25 turns. The licensee entered this issue into the CAP as NCR 582572, and an operability determination was performed. EDG 3 was determined to be operable based on Calculation M-89-0008 Revision 0, because the measured service water flow rate was above the 350 gpm limit and service water inlet temperature was 54 degrees Fahrenheit. After further investigation, the licensee determined the service water outlet valve 2-SW-V208 had been out of position since April 2010. The licensee performed a past operability evaluation and determined the maximum service water inlet temperature experienced between April 2010 and January 2013 was 89.2 degrees Fahrenheit on August 2, 2011, and August 6, 2012. Since the inlet temperature was still below 90 degrees Fahrenheit and the service water flow rate was above 350 gpm, EDG 3 was considered operable.

The inspectors reviewed Calculation M-89-0008 and determined that the EDG loading of 3500 kW and the heat sink temperature of 90 degrees Fahrenheit were non-conservative values. The inspectors determined the EDGs have a 2000 hour0.0231 days <br />0.556 hours <br />0.00331 weeks <br />7.61e-4 months <br /> load rating of 3850 kW and a TS Surveillance Requirement (SR) 3.8.1.11 to operate up to a maximum load of 3850 kW for 60 minutes. The inspectors determined the calculation should have considered the EDG loading of 3850 kW to determine the required service water flow rate. The inspectors also reviewed TS 3.7.2, Service Water System and Ultimate Heat Sink, and identified the maximum ultimate heat sink temperature is 90.5 degrees Fahrenheit.

On August 31, 2013, the licensee re-performed Calculation M-89-0008, Revision 1, using more accurate test data and more limiting engine load data 3850 kW and determined the required service water flow was 330 gpm.

In October 2013, inspectors reviewed the revised calculation for required service water flow to the EDG jacket water heat exchangers. The inspectors determined the calculation used a non-conservative value for the fouling factor. A fouling factor of 0.00015 was used in the calculation; however, this value is for less than demineralized water. The inspectors determined the service water system draws water from the intake canal which is mixture of freshwater and saltwater (brackish water). The inspectors determined the calculation should have considered a higher fouling factor to account for the brackish water.

As a result of the NRC inspectors questions on the fouling factor, the licensee revised the Calculation M-89-0008, Revision 2, on October 28, 2013, to consider a more conservative fouling factor. A fouling factor of 0.001 was used, which is consistent with brackish water.

On November 22, 2013, the inspectors observed the inspection of the EDG 3 jacket water heat exchanger which contained shells on the inlet side of the heat exchanger.

The licensee identified 16 heat exchanger tubes partially obstructed by shells and five tubes plugged. Inspectors questioned the fouling of tubes and the impact of the fouling on past operability.

Inspectors reviewed the Revision 2 calculation which assumes 134 out of 149 tubes in service or 15 blocked tubes. Inspectors determined the tube blocking value was reasonable, since the as-found condition of the EDG jacket water heat exchanger had fewer block tubes.

On January 14, 2014, the licensee completed a past operability review due to the shell fouling and the reduced flow conditions for EDG 3. The licensee reviewed the delta temperature (delta T) across the EDG 3 heat exchanger and determined the valve mis-positioning must have occurred between September 17, 2012, and October 17, 2012. This was based on the increase in change of temperature during this period. It was determined the maximum service water inlet temperature was 74 degrees Fahrenheit during periods of low flow. The licensee calculated that a minimum of 80 tubes out of 144 were adequate to ensure EDG operation at 3850 kilowatt load. Given the large margin calculated, it was determined the EDG 3 was operable during this period. The inspectors reviewed this conclusion and agreed that EDG 3 would have been operable.

Analysis.

The inspectors determined that the failure of the licensee to have an accurate calculation for required service water flow to the EDG jacket water heat exchanger was a performance deficiency. The finding was more than minor because it was associated with the design control attribute of the Mitigating Systems Cornerstone and adversely affects the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences.

Specifically, the non-conservative calculation called into question the operability of EDG 3. Using IMC 0609, Appendix A, issued June 19, 2012, the SDP for Findings At-Power, the inspectors determined the finding was of very low safety significance (Green)because the finding did not affect the design or qualification of a mitigating structures, systems, and components (SSC), the finding did not represent a loss of system and/or function, the finding did not represent an actual loss of a function of a single train for greater than the TS allowed outage time, the finding did not represent an actual loss of a function of one or more non-TS trains of equipment, and did not screen as potentially risk-significant due to a seismic, flooding, or severe weather initiating event. The finding has a cross-cutting aspect in the area of human performance associated with the resources attribute because the licensee did not have complete, accurate and up-to-date design documentation for EDG service water flow. Specifically, due to the inspectors questions, Calculation M-89-0008 required revision due to non-conservatisms in August 2013 and in November 2013. H.2(c)

Enforcement.

10 CFR Part 50, Appendix B, Criterion III, Design Control, requires, in part, that design control measures shall provide for verifying or checking the adequacy of design, such as by the performance of design reviews, by the use of alternate or simplified calculational methods. Contrary to the above, from May 1, 1989, until October 28, 2013, Calculation M-89-0008 used non-conservative values for EDG maximum loading, service water inlet temperatures, and heat exchanger fouling factor, resulting in a non-conservative calculation for required service water flow to the EDG jacket water heat exchanger, and calling into question the operability of EDG 3. The licensee re-performed Calculation M-89-0008 and determined EDG 3 was operable.

Because this finding is of very low safety significance (Green) and was entered into the licensees CAP as NCR 592035, consistent with Section 2.3.2.a of the NRCs Enforcement Policy, this violation is being treated as a NCV: NCV 05000325/2013005-02 and 05000324/2013005-02, Inadequate Design Control for Required Service Water Flow to the Emergency Diesel Generators.

.2 (Closed) Unresolved Item URI 05000325/2013003-06 and 05000324/2013003-06, Non-

Conservative Calculation for Service Water Flow Rate to the Emergency Diesel Generators

a. Inspection Scope

The inspectors completed an evaluation of URI 05000325; 324/2013003-06, opened to review revisions to Calculation M-89-0008 Revision 0, Heat Balance on DG 2 Jacket Water Service Heat Exchanger, for service water flow rate required for EDG operability during a design basis event, to determine if the performance deficiency associated with this issue is more than minor. The inspectors reviewed two revisions to Calculation M-89-0008 to determine if conservative valves were considered and if the EDG 3 was operable during periods of high service water inlet temperature. Documents reviewed are listed in the Attachment.

b. Findings

The inspectors evaluated the adequacy of the licensees calculation and determined that the calculation used non-conservative valves for the diesel loading, service water inlet temperature and heat exchanger fouling factor. The enforcement aspects associated with this issue are discussed in Section 1R15.1 of this report. This URI is closed.

1R19 Post Maintenance Testing

a. Inspection Scope

The inspectors reviewed the following post-maintenance activities to verify that procedures and test activities were adequate to ensure system operability and functional capability:

• 0PT-08.1.4a, RHR Service Water Service System Operability Test - Loop A on June 9, 2013

• 2OP-17, Generator and Exciter System Operating Procedure, after 2C main power transformer repair on August 12, 2013

• 1OP-43, Service Water Operating Procedure, after maintenance to the 1A RHR service water booster pump on October 5, 2013

• 0PT-12.2C, EDG 3 Monthly Load Test, following the starting air modification on October 19, 2013

• WO13311007, backseat and verify the 2-FW-V8 leak was stopped on November 1, 2013

• 0PT-12.2B, EDG 2 Monthly Load Test, to verify the starting air modification on December 12, 2013 These activities were selected based upon the structure, system, or component's ability to impact risk. The inspectors evaluated these activities for the following: the effect of testing on the plant had been adequately addressed; testing was adequate for the maintenance performed; acceptance criteria were clear and demonstrated operational readiness; test instrumentation was appropriate; tests were performed as written in accordance with properly reviewed and approved procedures; equipment was returned to its operational status following testing; and test documentation was properly evaluated. The inspectors evaluated the activities against TS and the UFSAR to ensure that the test results adequately ensured that the equipment met the licensing basis and design requirements. In addition, the inspectors reviewed corrective action documents associated with post-maintenance tests to determine whether the licensee was identifying problems and entering them in the corrective action program and that the problems were corrected commensurate with their importance to safety. Documents reviewed are listed in the Attachment.

b. Findings

Inadequate Procedure to Perform Preventative Maintenance on the Residual Heat Removal Room Coolers

Introduction.

A self-revealing Green NCV of TS 5.4.1a, Procedures, was identified for the failure of the licensee to have an adequate procedure for preventative maintenance on the 1B RHR room cooler damper limit switch. Specifically, between May 1990 and September 26, 2013, the licensee did not have an adequate preventative maintenance procedure to replace the 1B RHR room cooler damper limit switch and to tighten the paddle arm on the limit switch. This resulted in the failure of the 1B RHR room cooler to start and the inoperability of the 1B RHR train.

Description.

On May 22, 2012, the licensee attempted to place the 1B RHR room cooler in service, but the room cooler did not start. The licensee declared the 1B RHR room cooler and associated 1B RHR loop inoperable, and inspected the room cooler. The licensee found the paddle arm, which actuates the limit switch for the room cooler damper, to be loose, resulting in the intermittent and inconsistent operation of the room cooler. The licensee entered this issue into the CAP as NCR 607986.

The licensee performed a cause evaluation and determined that the cause of the failure of the 1B RHR room cooler to be that a preventative maintenance (PM) schedule did not exist to verify that the paddle arm was tight and in the correct position and a PM did not exist to replace the limit switch per the vendor manual. The licensee determined that the 1B RHR loop was inoperable but available since the 1A RHR room cooler could provide sufficient cooling to the 1B RHR loop.

The inspectors reviewed vendor manual QTR155, NAMCO Controls, dated May 1990, which requires in Section 11.12 (3.1.2) that for periodic surveillances, the licensee by direct observation, should check the limit switch, operating lever, mounting plate, operating device, and other related items for looseness or misalignment that might prevent actuation of the limit switch. The inspectors also determined that the vendor manual provided a replacement schedule for the limit switch in Section 11.12 (4.0) of 18 years and this limit switch had been in service for greater than 18 years.

The licensees corrective actions included replacing the limit switch on the 1B RHR room cooler damper, adjusting and tightening the paddle arm on the 1B RHR room cooler limit switch, inspecting the paddle arms on the other RHR room cooler limit switches, and replacing the other room cooler limit switches. The licensee revised Procedure 0PM-DMP500, HVAC Damper Inspection, to ensure the limit switch paddle arms are properly tightened. The licensee also created PM requests 612245 and 612268, to add to the current room cooler damper lubrication PM, to replace the limit switches every 15 years.

Analysis.

The inspectors determined that the failure of the licensee to have an adequate preventative maintenance procedure to replace the 1B RHR room cooler limit switch and tighten the limit switch paddle arm was a performance deficiency. The finding was more than minor because it was associated with the equipment performance attribute of the Mitigating Systems Cornerstone and affects the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the failure to replace the limit switch and tighten the limit switch paddle arm resulted in a failure of the cooler fan and damper, and the inoperability of the 1B RHR train. Using IMC 0609, Appendix A, issued June 19, 2012, the SDP for Findings At-Power, the inspectors determined the finding was of very low safety significance (Green) because the finding did not affect the design or qualification of a mitigating SSC, the finding did not represent a loss of system and/or function, the finding did not represent an actual loss of a function of a single train for greater than the TS allowed outage time, the finding did not represent an actual loss of a function of one or more non-TS trains of equipment, and did not screen as potentially risk-significant due to a seismic, flooding, or severe weather initiating event. The finding does not have a cross-cutting aspect since the performance deficiency is not indicative of current plant performance. Vendor manual QTR155, NAMCO Controls, requiring periodic replacement of the limit switch and checking the limit switch for tightness was provided to the licensee in May 1990.

Enforcement.

TS 5.4.1, Procedures, states that written procedures shall be established, implemented, and maintained covering the following activities: a. The applicable procedures recommended in Regulatory Guide 1.33, Appendix A, November 1972 (Safety Guide 1.33). Safety Guide 1.33,Section I.2 states, that preventative maintenance schedules should be developed to specify lubrication schedules, inspections of equipment, replacement of such items and filters and strainers, and inspection or replacement of parts that have a specific lifetime. Contrary to the above, between May 1990 and September 26, 2013, the licensee did not have an adequate preventative maintenance procedure to replace the 1B RHR room cooler damper limit switch and to tighten the paddle arm on the limit switch. This resulted in the failure of the 1B RHR room cooler to start and the inoperability of the 1B RHR train. The licensee replaced the limit switch on the damper, tightened the paddle arm on the limit switch, and returned the room cooler to operable. Because this finding is of very low safety significance (Green) and was entered into the licensees CAP as NCR 607986, consistent with Section 2.3.2.a of the NRCs Enforcement Policy, this violation is being treated as a NCV: NCV 05000325/2013005-03, Inadequate Procedure to Perform Preventative Maintenance on the Residual Heat Removal Room Coolers.

1R22 Surveillance Testing

.1 Routine Surveillance Testing (71111.22 - 5 ST samples)

a. Inspection Scope

The inspectors either observed surveillance tests or reviewed the test results for the following activities to verify the tests met TS surveillance requirements, UFSAR commitments, in-service testing requirements, and licensee procedural requirements.

The inspectors assessed the effectiveness of the tests in demonstrating that the SSCs were operationally capable of performing their intended safety functions. Documents reviewed are listed in the Attachment.

• 0PT-19.5, Nuclear Steam System Safety / Relief Valve Test, April 30, 2013

• WO13309397 Fuel Oil Transfer Cell 2 check valve testing on October 30, 2013

• 0MST-DG24M, Emergency Bus Degraded Voltage Channel Functional Test, on November 5, 2013

• 0PT-12.2C, EDG 3 Monthly Load Test, on November 15, 2013

• 0MST-RHR22Q - Residual Heat Removal - Low Pressure Coolant Injection, Automatic Depressurization System, Core Spray Low Level 3, Division I Train, Unit Channel Calibration Test, on December 13, 2013

b. Findings

The enforcement aspects for 0PT-19.5, Nuclear Steam System Safety/Relief Valve Test, are discussed in Section 4OA7 of this report.

.2 In-Service Testing (IST) Surveillance (71111.22 - 1 IST sample)

a. Inspection Scope

The inspectors reviewed the performance of the following test:

• 0PT-08.2.2b, Low Pressure Coolant Injection/Residual Heat Removal System Operability Test - Loop B, on November 15, 2013 Inspectors evaluated the effectiveness of the licensees American Society of Mechanical EngineersSection XI testing program for determining equipment availability and reliability. The inspectors evaluated selected portions of the following areas: 1) testing procedures; 2) acceptance criteria; 3) testing methods; 4) compliance with the licensees IST program, TS, selected licensee commitments, and code requirements; 5) range and accuracy of test instruments; and 6) required corrective actions. Documents reviewed are listed in the Attachment.

b. Findings

No findings were identified.

1EP4 Emergency Action Level and Emergency Plan Changes

a. Inspection Scope

The NSIR headquarters staff performed an in-office review of the latest revisions of various Emergency Plan Implementing Procedures (EPIPs) and the Emergency Plan located under ADAMS accession numbers ML12361A017, ML13024A418, ML123630340, and ML13239A001 as listed in the Attachment.

The licensee determined that in accordance with 10 CFR 50.54(q), the changes made in the revisions resulted in no reduction in the effectiveness of the Plan, and that the revised Plan continued to meet the requirements of 10 CFR 50.47(b) and Appendix E to 10 CFR Part 50. The NRC review was not documented in a safety evaluation report and did not constitute approval of licensee-generated changes; therefore, these revisions are subject to future inspection. This inspection activity satisfied one inspection sample for the emergency action level and emergency plan changes on an annual basis.

Documents reviewed are listed in the Attachment.

b. Findings

No findings were identified.

4OA1 Performance Indicator (PI) Verification

Mitigating Systems Cornerstone (71151 - 4 samples)

a. Inspection Scope

The inspectors sampled licensee submittals for the Mitigating Systems Performance Index (MSPI) performance indicators listed above for the period from the fourth quarter 2012 through the third quarter of 2013. The inspectors reviewed the licensees operator narrative logs, issue reports, MSPI derivation reports, event reports and NRC Integrated Inspection reports for the period to validate the accuracy of the submittals. The inspectors also reviewed the licensees issue report database to determine if any problems had been identified with the PI data collected or transmitted for this indicator.

Documents reviewed are listed in the Attachment.

• Mitigating Systems Performance Index, Reactor Coolant Injection Systems

• Mitigating Systems Performance Index, High Pressure Injection Systems

b. Findings

No findings were identified.

4OA2 Identification and Resolution of Problems

.1 Routine Review of Items Entered Into the Corrective Action Program

a. Inspection Scope

To aid in the identification of repetitive equipment failures or specific human performance issues for follow-up, the inspectors performed frequent screenings of items entered into the licensees CAP. The review was accomplished by reviewing daily NC reports.

b. Findings

No findings were identified.

.2 Semi-Annual Trend Review (71152 - 1 trend sample)

a. Inspection Scope

The inspectors performed a review of the licensees CAP and associated documents to identify trends that could indicate the existence of a more significant safety issue. The inspectors review was focused on repetitive equipment issues, but also considered the results of daily inspector CAP item screening discussed in Section 4OA2.1 above, licensee trending efforts, and licensee human performance results. The inspectors review nominally considered the six-month period of July 1, 2013, through December 31, 2013, although some examples expanded beyond those dates where the scope of the trend warranted.

Inspectors also reviewed major equipment problem lists, repetitive and rework maintenance lists, departmental problem/challenges lists, system health reports, quality assurance audit/surveillance reports, self-assessment reports, and Maintenance Rule assessments. The inspectors compared and contrasted their results with the results contained in the licensees CAP trending reports. Corrective actions associated with a sample of the issues identified in the licensees trending reports were reviewed for adequacy. Documents reviewed are listed in the Attachment.

b. Findings and Observations

A finding was identified for failure to follow Procedure OPS-NGGC-1305, Operability Determinations, to perform functionality assessments on flood protection features will be documented in NRC Inspection Report 05000325/2013010 and 05000324/2013010.

The inspectors evaluated a sample of departments that are required to provide input into the quarterly trend reports, which included system engineering and operations departments. This review included a sample of issues and events that occurred over the course of the past two quarters to determine whether issues were appropriately considered or ruled as emerging or adverse trends, and in some cases, verified the appropriate disposition of resolved trends. The inspectors verified that these issues were addressed within the scope of the CAP, or through department review and documentation in the quarterly trend report for overall assessment.

The inspectors identified an adverse trend in the adequacy of functionality assessments.

The inspectors identified the following examples of flood protection equipment that did not have a functionality assessment as required by licensee procedure OPS-NGGC-1305, Operability Determinations. Examples include:

• Service water building unsealed conduit 6BL3DC (NCR 578407)

• Service water building unsealed conduit 6BC9S (NCR 578840)

• Unit 2 HPCI sump pump trip (NCR 578464)

• Unit 2 HPCI sump pump trip (NCR 581434)

The licensee entered this trend into the CAP as NCR 613442.

.3 Annual Follow-up of Selected Issues

Evaluation of U2 Reactor Startup May 4, 2013 Stalled due to Unexpected Period

a. Inspection Scope

The inspectors selected NCR 604857, U2 Reactor Startup on May 4, 2013 Stalled due to Unexpected Period, for detailed review. This NCR was associated with an Apparent Cause Evaluation of the beginning of cycle start-up on May 4, 2013, where a single notch control rod pull to establish a start-up rate of power increase following criticality resulted in a period less than the established licensee procedure 0GP-02, Approach to Criticality and Pressurization of the Reactor, limit of 100 seconds.

The inspectors reviewed this report to verify that the licensee identified the full extent of the issue, performed an appropriate evaluation, and specified and prioritized appropriate corrective actions. The inspectors evaluated the report against the requirements of the licensees CAP as delineated in corporate procedure CAP-NGGC-0200, Condition Identification and Screening Process, and 10 CFR Part 50, Appendix B. Documents reviewed are listed in the Attachment.

b. Findings

No findings were identified.

4OA3 Follow-up of Events

.1 (Closed) URI 5000325/2013003-10; Notice of Enforcement Discretion (NOED) for

Replacement of the E8 Transformer

a. Inspection Scope

On April 15, 2013, due to the inoperability of Division II emergency buses E4/E8, the licensee requested the NRC not enforce compliance with TS 3.7.3, Required Action A.1; TS 3.8.1, Required Action B.3; TS 3.8.4, Required Action A.1; and TS 3.8.7, Required Action A1 until April 17, 2013, at 3:15 am. The licensee requested and was granted the NOED on April 15, 2013, at 2:05 pm. The LCO extension allowed the licensee time to complete the replacement of and test the E8 transformer to restore operability. The licensee entered this issue in the CAP as NCR 601376.

The inspectors completed an evaluation of URI 5000325/2013003-10, opened to determine if a performance deficiency exists. The inspectors performed a walkdown of the replacement of the safety-related transformers. The inspectors reviewed the licensees corrective actions for the degraded transformers. The inspectors discussed this issue with licensee personnel to understand the impact of the transformer degradation on the safety related transformers. Documents reviewed are listed in the

.

b. Findings

The inspectors reviewed the licensees evaluation of the degraded core to ground and core to secondary winding testing results and the impact on the transformers ability to perform their safety related functions. The inspectors evaluated the adequacy of the licensees corrective actions and determined that the corrective actions were adequate to replace the safety related transformers. No findings were identified associated with the replacement of the safety related transformers. This URI is closed.

.2 (Closed) Licensee Event Reports (LERs) 05000324/2013-003-00, Machining Surface

Leads to Setpoint Drift in Main Steam line Safety/Relief Valves

a. Inspection Scope

On May 21, 2013, the Brunswick Steam Electric Plant as-found testing of eleven safety/relief valves (SRVs), which had been removed from Unit 2 during the Spring 2013 refueling outage, was completed. The surveillance testing indicated that four of the eleven valves were found to lift at more than three percent above their TS required setpoints. Therefore, these four valves were determined to have been inoperable while the unit was in operation. Since TS 3.4.3, Safety/Relief Valves, requires at least ten of the eleven valves to be operable, this condition was reported in accordance with 10 CFR 50.73(a)(2)(i)(B) as operation prohibited by the plant's TS. The licensee submitted LER 05000324/2013-003-00 on July 22, 2013, for this issue. Documents reviewed are listed in the Attachment.

b. Findings

The enforcement aspects of this finding are discussed in Section 4OA7 of this report.

This LER is closed.

.3 Unit 1 A reactor feed pump (RFP) tripped due to a low oil pressure

a. Inspection Scope

On November 24, 2013, inspectors responded to the control room and performed observations after the Unit 1 A RFP tripped in the response to low oil pressure.

Inspectors evaluated operator performance compared to procedural guidance. After the plant was stabilized, inspectors reviewed operator logs, plant computer data, recorder data, plant procedures, and training to determine if personnel response was appropriate, if plant equipment responded as expected, if the cause of the RFP trip was accurately determined, and if appropriate immediate corrective actions were taken. Documents reviewed are listed in the Attachment.

b. Findings

No findings were identified.

4OA5 Other Activities

Quarterly Resident Inspector Observations of Security Personnel and Activities

a. Inspection Scope

During the inspection period the inspectors observed a security force drill to ensure that the activities were consistent with licensee security procedures and regulatory requirements relating to nuclear plant security. The inspectors also observed security personnel and activities during both normal and off-normal plant working hours. These quarterly resident inspector observations of security force personnel and activities did not constitute any additional inspection samples. Rather, they were considered an integral part of the inspectors' normal plant status reviews and inspection activities.

b. Findings

No findings were identified.

4OA6 Management Meetings

Exit Meeting Summary

On January 16, 2014, the inspector presented the inspection results to Mr. George Hamrick, and other members of the licensee staff. The inspectors verified that no proprietary information was retained by the inspectors or documented in this report.

4OA7 Licensee-Identified Violation

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

10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, states, in part, that activities affecting quality shall be prescribed by documented procedures and shall be accomplished in accordance with these procedures. Contrary to the above, from August 2010 until August 2013, when SRV pilot valve conical seating surface finish requirements were incorporated into licensee Procedure OCM-VSR509, Main Steam Relief Valves Target Rock Model 7567 Air Operators and Pilot Assembly, Disassembly, Inspection, and Reassembly, the licensee failed to prescribe procedural requirements for the SRV pilot valve conical seating surface finishes. This resulted in four of the eleven SRVs being out of tolerance, which was a violation of plant TS 3.4.3.,

Safety Relief Valves. The licensee took action to replace all of the pilot valves with valves that had the correct surface finish. This violation was determined to be of very low safety significance (Green) because the finding was a deficiency affecting the design or qualification of a mitigating SSC that maintained functionality. The licensee entered this issue into their CAP as NCR 607846. The licensee revised procedure OCM-VSR509 as a corrective action to prevent recurrence.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

K. Allen, Manager - Design Engineering

Y. Anagostopoulos, Manager - Major Projects

A. Brittain, Manager - Security

K. Crocker, Supervisor - Emergency Preparedness

P. Dubrouillet, Manager - Nuclear Systems Engineering

S. Gordy, Manager - Maintenance

L. Grzeck, Supervisor - Licensing

K. Hamm, Superintendent - Mechanical Maintenance

G. Hamrick, Site Vice President

B. Houston, Manager - Environmental and Radiological Controls

J. Kalamaja, Manager - Operations

G. Kilpatrick, Manager - Training

J. Krakuszeski, Plant General Manager

W. Murray, Licensing Specialist

J. Nolin, Director - Engineering

A. Padleckas, Manager - Shift Operations

F. Payne, Manager - Outage and Scheduling

D. Petrusic, Superintendent - Environmental and Chemistry

A. Pope, Manager - Nuclear Support Services

B. Raper, Supervisor - U1 Outage Manager

T. Sherrill, Licensing Specialist

M. Turkal, Licensing Specialist

E. Willis, Director - Site Operations

O. Wrisbon, Superintendent - Electrical, Instrumentation and Controls Maintenance

NRC Personnel

G. Hopper, Chief, Reactor Projects Branch 4

J. Dodson, Senior Project Engineer

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened

05000325/2013005-01 URI Failure of Transformer Common C and Loss of Emergency Core Cooling System Keepfill (Section 1R12.1)

Opened and Closed

05000325;324/2013005-02 NCV Inadequate Design Control for Required Service Water Flow to the Emergency Diesel Generators (Section 1R15.1)

05000325/2013005-03 NCV Inadequate Procedure to Perform Preventative Maintenance on the Residual Heat Removal Room Coolers (Section 1R19)

Closed

05000325;324/2013003-06 URI Non-Conservative Calculation for Service Water Flow Rate to the Emergency Diesel Generators (Section 1R15.2)

05000325/2013003-10 URI Notice of Enforcement Discretion for Replacement of the E8 Transformer (Section 4OA3.1)

05000324/2013-003-00 LER Machining Surface Leads to Setpoint Drift in Main Steam line Safety/Relief Valves (Section 4OA3.2)