Text

IR 05000313/2014005; 05000368/2014005; on 10/01/2014 - 12/31/2014; Arkansas Nuclear One, Units 1 and 2, Integrated Inspection Report; Equipment Alignment, Maintenance Rule, Exercise Evaluation, Problem Identification and Resolution
	ML15044A256
Person / Time
Site:	Arkansas Nuclear
Issue date:	02/13/2015
From:	Ryan Lantz; NRC/RGN-IV/DRP/RPB-E
To:	Jeremy G. Browning; Entergy Operations
	Lantz R
References
	IR 2014005
	Download: ML15044A256 (48)
	v • d • e

UNITED STATES ary 13, 2015

SUBJECT:

ARKANSAS NUCLEAR ONE - NRC INSPECTION REPORT 05000313/2014005 and 05000368/2014005

Dear Mr. Browning:

On December 31, 2014, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Arkansas Nuclear One facility, Units 1 and 2. On January 6, 2015, the NRC inspectors discussed the results of this inspection with you and other members of your staff.

Inspectors documented the results of this inspection in the enclosed inspection report.

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

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

If you contest the violations or significance of these NCVs, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001; with copies to the Regional Administrator, Region IV; the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC resident inspector at Arkansas Nuclear One.

If you disagree with a cross-cutting aspect assignment in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your disagreement, to the Regional Administrator, Region IV; and the NRC resident inspector at Arkansas Nuclear One. In accordance with Title 10 of the Code of Federal Regulations (10 CFR) 2.390, Public Inspections, Exemptions, Requests for Withholding, a copy of this letter, its enclosure, and your response (if any) will be available electronically for public inspection in the NRCs Public Document Room or from the Publicly Available Records (PARS) component of the NRC's Agencywide Documents Access and Management System (ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,

/RA/

Ryan E. Lantz, Chief Project Branch E Division of Reactor Projects Docket Nos. 50-313, 50-368 License Nos. DRP-51; NPF-6

Enclosure:

Inspection Report 05000313/2014005 and 05000368/2014005 w/ Attachments:

1. Supplemental Information 2. Temporary Instruction 2515/189 Request for Information 3. Detailed Risk Evaluation

REGION IV==

Docket: 05000313; 05000368 License: DPR-51; NPF-6 Report: 05000313/2014005; 05000368/2014005 Licensee: Entergy Operations Inc.

Facility: Arkansas Nuclear One, Units 1 and 2 Location: Junction of Hwy. 64 West and Hwy. 333 South Russellville, Arkansas Dates: October 1 through December 31, 2014 Inspectors: B. Tindell, Senior Resident Inspector M. Young, Resident Inspector J. Drake, Senior Reactor Inspector P. Elkmann, Senior Emergency Preparedness Inspector G. Guerra, CHP, Emergency Preparedness Inspector S. Hedger, Operations Engineer J. Melfi, Project Engineer J. Rollins, Physical Security Inspector Approved R. Lantz, Chief By: Project Branch E Division of Reactor Projects-1- Enclosure

SUMMARY

IR 05000313/2014005; 05000368/2014005; 10/01/2014 - 12/31/2014; Arkansas Nuclear One,

Units 1 and 2, Integrated Inspection Report; Equipment Alignment, Maintenance Rule, Exercise Evaluation, Problem Identification and Resolution.

The inspection activities described in this report were performed between October 1 and December 31, 2014, by the resident inspectors at Arkansas Nuclear One and inspectors from the NRCs Region IV office. Four findings of very low safety significance (Green) are documented in this report. All of these findings involved violations of NRC requirements. The significance of inspection findings is indicated by their color (Green, White, Yellow, or Red),

which is determined using Inspection Manual Chapter 0609, Significance Determination Process. Their cross-cutting aspects are determined using Inspection Manual Chapter 0310,

Aspects within the Cross-Cutting Areas. Violations of NRC requirements are dispositioned in accordance with the NRC Enforcement Policy. The NRCs program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process.

Cornerstone: Mitigating Systems

Green.

The inspectors identified a noncited violation of 10 CFR 50.54(hh)(2) for the failure to develop mitigating strategy guidance that would successfully maintain or restore Unit 2 core cooling after the loss of large areas of the plant. Specifically, the guidance did not ensure the capability of the mitigating strategy because an unisolated flow diversion could have prevented water from reaching the steam generators and cooling the core. The issue was documented in Condition Report CR-ANO-2-2014-03277, and the procedure was revised to correct the condition.

The licensees failure to develop mitigating strategy guidance that would successfully maintain or restore Unit 2 core cooling after loss of large areas of the plant, as required by 10 CFR 50.54(hh)(2), was a performance deficiency. The performance deficiency was more than minor, and therefore a finding, because it was associated with the procedure quality attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems. Specifically, the guidance did not ensure the capability of the mitigating strategy because an unisolated flow diversion could have prevented water from reaching the steam generators and cooling the core. Using NRC Manual Chapter 0609, Attachment 4, Initial Characterization of Findings, dated June 19, 2012, and NRC Manual Chapter 0609, Appendix L, B.5.b Significance Determination Process, dated December 24, 2009, Table 1, SDP Screening Worksheet for B.5.b, the finding was determined to be of very low safety significance because the performance deficiency represented the unrecoverable unavailability of an individual mitigating strategy; other core cooling mitigating strategies were available. This finding has a human performance crosscutting aspect associated with avoid complacency, in that the licensee failed to recognize and plan for the possibility of latent issues, even while expecting successful outcomes [H.12]. (Section 1R04)

Green.

Inspectors identified a noncited violation of Unit 1 Technical Specification 5.4,

Procedures, for the licensees failure to establish adequate emergency operating procedures. Specifically, the licensees emergency operating procedures failed to establish minimum flow protection for the Unit 1 auxiliary feedwater pump, which could result in catastrophic failure of the pump. The issue was documented in Condition Report CR-ANO-1-2014-00286 and the procedures were revised to correct the condition.

The failure to establish minimum flow protection for the Unit 1 auxiliary feedwater pump in emergency and abnormal operating procedures in accordance with the emergency operating procedure writers guide was a performance deficiency. The performance deficiency was more than minor, and therefore a finding, because it was associated with the procedure quality attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, inadequate emergency and abnormal operating procedures could have resulted in failure of the auxiliary feedwater pump, a mitigating system for a loss of main and emergency feedwater. Using Manual Chapter 0609, Attachment 4, Initial Characterization of Findings, June 19, 2012, and Appendix A, The Significance Determination Process (SDP) for Findings at Power,

June 19, 2012, Exhibit 2, Mitigating Systems Screening Questions, the inspectors determined that the finding required a detailed risk evaluation because the finding represented a loss of system function. A Region IV senior reactor analyst performed the detailed risk evaluation and determined that the change to the core damage frequency was less than 4.2E-7/year (Green). The dominant core damage sequences included losses of one of the safety related 4160 volt electrical buses, steam generator tube ruptures, and plant transients. The equipment that helped mitigate the risk included the high pressure injection system (for feed and bleed) and the main and emergency feedwater systems. This finding did not have a cross-cutting aspect because the most significant contributing cause was not indicative of current performance. Specifically, the emergency and abnormal operating procedures for operating auxiliary feedwater had not changed for at least 20 years. (Section 1R12)

Green.

Inspectors identified a noncited violation of 10 CFR Part 50, Appendix B,

Criterion III, Design Control, for the licensees failure to maintain design control of the Unit 2 vital switchgear ventilation system. Specifically, in 2002, the licensee failed to ensure that the ventilation system was capable of cooling the switchgear under design basis conditions. The licensee documented the issue in Condition Report CR-ANO-2-2014-00352 and conducted an evaluation to verify the capability of the ventilation system.

Failure to ensure that the ventilation system was capable of cooling the switchgear under design basis conditions was a performance deficiency. The performance deficiency was more than minor, and therefore a finding, because it was associated with the design control attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Using Manual Chapter 0609,

Attachment 4, Initial Characterization of Findings, June 19, 2012, and Appendix A, The Significance Determination Process (SDP) for Findings at Power, June 19, 2012, Exhibit 2,

Mitigating Systems Screening Questions, the inspectors determined that the finding was of very low safety significance (Green) because the finding was a deficiency affecting the design of a mitigating system, and the system maintained its functionality. The inspectors determined that there was no cross-cutting aspect associated with this finding because the cause of the performance deficiency occurred more than three years ago, and was not representative of current licensee performance. (Section 4OA2.3)

Cornerstone: Emergency Preparedness

Green.

The inspectors identified a non-cited violation of 10 CFR Part 50.47(b)(14) for the failure to correct a deficiency identified in a 2013 simulator drill. Specifically, control room operators did not implement the procedure that describes how the site will maintain continuous communication with threat notification sources during a drill conducted August 7, 2013, and also during the September 16, 2014, biennial exercise. The inspectors determined that the licensees corrective actions for this issue were incomplete and did not address the extent of condition. The licensee has entered the issue into the corrective action program in corrective action documents WT-WTANO-2014-00189 and Condition Report CR-ANO-C-2014-02478.

The failure to correct weaknesses occurring in drills and exercises is a performance deficiency within the licensees ability to foresee and correct. The performance deficiency is more than minor because it is associated with the emergency response organization performance attribute of the Emergency Preparedness Cornerstone and it adversely impacted the cornerstone objective. The licensees ability to implement adequate measures to protect the health and safety of the public in the event of hostile action and a radiological emergency is degraded when it fails to correct performance that precludes the effective implementation of the emergency plan. This finding was evaluated using Manual Chapter 0609, Appendix B, Emergency Preparedness Significance Determination Process (SDP), Attachment 2, dated February 24, 2012, and was determined to be of very low safety significance (Green) because it was a failure to comply with NRC requirements, was not associated with a risk-significant planning standard, and was not a loss of planning standard function. The finding was not a loss of function because the deficiency that was identified was not associated with classification, notifications to state and local agencies, or the development of protective action recommendations.

The finding was assigned a cross-cutting aspect in the area of problem identification and resolution, associated with the resolution of issues because the licensee failed to evaluate the initial performance issues to ensure that resolutions adequately addressed the extent of condition commensurate with their safety significance. The licensee failed to recognize in August 2013 that continuous communications with threat notification sources is required by regulation and that performance issues with the implementing procedure should be communicated to the entire control room staff population [P.2]. (Section 1EP7.1)

PLANT STATUS

Unit 1 began the period at 100 percent power. On December 9, 2014, Unit 1 commenced a rapid plant downpower at the order of the transmission grid operator due to a switchyard breaker issue. The unit stabilized at 55 percent power. On December 9, 2014, the breaker was removed from service and the unit increased power to 100 percent. On December 21, 2014, Unit 1 commenced a rapid plant downpower at the order of the transmission grid operator due to a switchyard breaker issue. The unit stabilized at 75 percent power. On December 22, 2014, the breaker was repaired and the unit increased power to 100 percent and remained at 100 percent power the rest of the inspection period.

Unit 2 began the period at 100 percent power. On December 9, 2014, Unit 2 commenced a rapid plant downpower at the order of the transmission grid operator due to a switchyard breaker issue. The unit stabilized at 45 percent power. On December 9, 2014, the breaker was removed from service and the unit increased power, reaching 100 percent power on December 10, 2014. On December 21, 2014, Unit 2 commenced a rapid plant downpower at the order of the transmission grid operator due to a switchyard breaker issue. The unit stabilized at 55 percent power. On December 22, 2014, the breaker was repaired and the unit increased power, reaching 100 percent power on December 23, 2014, and remained at 100 percent power the rest of the inspection period.

REPORT DETAILS

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R01 Adverse Weather Protection

Main article: IP 71111.01

Readiness for Seasonal Extreme Weather Conditions

a. Inspection Scope

On October, 24, 2013, the inspectors completed an inspection of the stations readiness for seasonal extreme weather conditions. The inspectors reviewed the licensees adverse weather procedures for cold temperatures and evaluated the licensees implementation of these procedures. The inspectors verified that, prior to the onset of cold weather, the licensee had corrected weather-related equipment deficiencies identified during the previous weather season.

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

Unit 1, borated water storage tank

Unit 1, boric acid addition tank

Units 1 and 2, alternate ac diesel generator

Unit 2, refueling water storage tank The inspectors reviewed the licensees procedures and design information to ensure the systems and components would remain functional when challenged by cold weather.

The inspectors verified that operator actions described in the licensees procedures were adequate to maintain readiness of these systems. The inspectors walked down portions of these systems to verify the physical condition of the cold weather protection features.

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

b. Findings

No findings were identified.

1R04 Equipment Alignment

Main article: IP 71111.04

a. Inspection Scope

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

October 1, 2014, Unit 2, emergency diesel generator train A while train B was out of service for preventative maintenance during an extended allowed outage time

October 16, 2014, Unit 1, BW-1, borated water storage tank outlet valve for both trains of emergency core cooling systems and reactor building spray

November 18, 2014, Units 1 and 2, core cooling strategies for potential loss of large areas of the plant

December 29, 2014, Units 1 and 2, alternate ac diesel generator while protected for switchyard work The inspectors reviewed the licensees procedures and system design information to determine the correct lineup for the systems. They visually verified that critical portions of the systems were correctly aligned for the existing plant configuration.

These activities constituted four partial system walk-down samples as defined in Inspection Procedure 71111.04.

b. Findings

Introduction.

The inspectors identified a Green noncited violation of 10 CFR 50.54(hh)(2) for the failure to develop mitigating strategy guidance that would successfully maintain or restore Unit 2 core cooling after the loss of large areas of the plant. Specifically, the guidance did not ensure the capability of the mitigating strategy because an unisolated flow diversion could have prevented water from reaching the steam generators and cooling the core.

Description.

The inspectors performed a walkdown of Procedure OP-1203.048 Security Event, Revision 29, Attachment J, Section J, Part 6.0. The inspectors found that valves in the startup and blowdown system critical to the Unit 2 core cooling mitigating strategy were not addressed in the guidance. Specifically, 2CV-1074-1, a pressure controlling valve, may fail open on loss of instrument air so that water from the portable pump intended for the steam generators would be diverted to the hotwell. The licensee documented the issue in Condition Report CR-ANO-2-2014-03277 and modified the guidance so that potential diversion flowpaths would be isolated.

The inspectors determined that, due to the inadequate guidance, the Unit 2 core cooling mitigating strategy using the startup and blowdown system was unavailable and unrecoverable due to the significant diagnosis and action time that would be necessary to recover the strategy. However, the inspectors determined that a Unit 2 core cooling mitigating strategy using the turbine driven emergency feedwater pump was unaffected and available, so that the function could be met.

The inspectors reviewed the change history for the guidance and interviewed operations personnel that had recently performed a walkdown of the guidance in order to determine the cause of the performance deficiency. The inspectors concluded that the licensee had failed to consider the possibility of valves changing position and diverting flow away from the mitigating strategy during the postulated event.

Analysis.

The licensees failure to develop mitigating strategy guidance that would successfully maintain or restore Unit 2 core cooling after loss of large areas of the plant, as required by 10 CFR 50.54(hh)(2), was a performance deficiency. The performance deficiency was more than minor, and therefore a finding, because it was associated with the procedure quality attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events. Specifically, the guidance did not ensure the mitigating strategy could cool the core because an unisolated flow diversion could have prevented water from the portable pump reaching the steam generators. Using NRC Manual Chapter 0609, Attachment 4, Initial Characterization of Findings, dated June 19, 2012, and NRC Manual Chapter 0609, Appendix L, B.5.b Significance Determination Process, dated December 24, 2009, Table 1, SDP Screening Worksheet for B.5.b, the finding was determined to be of very low safety significance because the performance deficiency represented the unrecoverable unavailability of an individual mitigating strategy and other core cooling mitigating strategies were available. This finding has a human performance crosscutting aspect associated with avoid complacency, in that the licensee failed to recognize and plan for the possibility of latent issues, even while expecting successful outcomes [H.12].

Enforcement.

Title 10 CFR 50.54(hh)(2), requires, in part, that each licensee shall develop guidance intended to maintain or restore core cooling under the circumstances associated with loss of large areas of the plant due to explosions or fire. Contrary to the above, as of November 17, 2014, the licensee had failed to develop guidance intended to maintain or restore core cooling under the circumstances associated with loss of large areas of the plant due to explosions or fire. Specifically, the licensee failed to ensure that the Unit 2 core cooling guidance directed isolation of potential flow diversion flowpaths so that the cooling water would flow to the steam generators. The licensee corrected the condition by revising the guidance to isolate the potential flow diversion flowpaths. This violation is being treated as a noncited violation (NCV), consistent with Section 2.3.2 of the Enforcement Policy. The violation was entered into the licensees corrective action program as Condition Report CR-ANO-2-2014-03277.

(NCV 05000368/2014005-01; Failure to Develop Adequate Guidance for Extreme Damage Mitigation)

1R05 Fire Protection

Main article: IP 71111.05

Quarterly Inspection

a. Inspection Scope

The inspectors evaluated the licensees fire protection program for operational status and material condition. The inspectors focused their inspection on four plant areas important to safety:

October 1, 2014, Unit 2, Fire Area SS, south switchgear room, east DC equipment room, and east battery room

October 9, 2014, Unit 2, Fire Area AA, east pump area and gallery

October 9, 2014, Unit 1, Fire Area C, radwaste processing area, lower north piping penetration area, and penetration ventilation area

November 21, 2014, Unit 1, Fire Area B-1, controlled access area For each area, the inspectors evaluated the fire plan against defined hazards and defense-in-depth features in the licensees fire protection program. The inspectors evaluated control of transient combustibles and ignition sources, fire detection and suppression systems, manual firefighting equipment and capability, passive fire protection features, and compensatory measures for degraded conditions.

These activities constituted four quarterly inspection samples, as defined in Inspection Procedure 71111.05.

b. Findings

No findings were identified.

1R06 Flood Protection Measures

Main article: IP 71111.06

a. Inspection Scope

On December 23, 2014, the inspectors completed an inspection of the stations ability to mitigate flooding due to internal causes. After reviewing the licensees flooding analysis, the inspectors chose the Unit 2 emergency diesel generator rooms which contain risk-significant structures, systems, and components that were susceptible to flooding.

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

These activities constitute completion of one flood protection measures sample as defined in Inspection Procedure 71111.06.

b. Findings

No findings were identified.

1R11 Licensed Operator Requalification Program and Licensed Operator Performance

Main article: IP 71111.11

.1 Review of Licensed Operator Requalification

a. Inspection Scope

On October 8, 2014, the inspectors observed an evaluated simulator scenario performed by an operating crew on Unit 2. On November 13, 2014, the inspectors observed simulator training for an operating crew on Unit 1. The inspectors assessed the performance of the operators and the evaluators critique of their performance.

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

b. Findings

No findings were identified.

.2 Review of Licensed Operator Performance

a. Inspection Scope

The inspectors observed the performance of on-shift licensed operators in the plants main control room. At the time of the observations, the plant was in a period of heightened activity. The inspectors observed the operators performance of the following activities:

October 2, 2014, Unit 1, turbine driven emergency feedwater valve post-maintenance test and surveillance

October 2, 2014, Unit 2, control element assembly surveillance test

November 12, 2014, Unit 1, high pressure injection pump post-maintenance and surveillance test In addition, the inspectors assessed the operators adherence to plant procedures, including conduct of operations procedure and other operations department policies.

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

b. Findings

No findings were identified.

1R12 Maintenance Effectiveness

Main article: IP 71111.12

a. Inspection Scope

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

December 17, 2014, Unit 1, high pressure injection pump, P-36B, outboard seal failure and inboard seal leakage

December 30, 2014, Unit 1, auxiliary feedwater pump The inspectors reviewed the extent of condition of possible common cause SSC failures and evaluated the adequacy of the licensees corrective actions. The inspectors reviewed the licensees work practices to evaluate whether these may have played a role in the degradation of the SSCs. The inspectors assessed the licensees characterization of the degradation in accordance with 10 CFR 50.65 (the Maintenance Rule), and verified that the licensee was appropriately tracking degraded performance and conditions in accordance with the Maintenance Rule.

These activities constituted completion of two maintenance effectiveness samples, as defined in Inspection Procedure 71111.12.

b. Findings

Introduction.

Inspectors identified a Green noncited violation of Unit 1 Technical Specification 5.4, Procedures, for the licensees failure to establish adequate emergency operating procedures. Specifically, the licensees emergency operating procedures failed to establish minimum flow protection for the Unit 1 auxiliary feedwater pump, which could result in failure of the pump.

Description.

The inspectors performed a walkdown of the Unit 1 auxiliary feedwater system, a nonsafety-related system that is a backup to main feedwater and the safety-related emergency feedwater system. The inspectors noted that the minimum flow valve for the auxiliary feedwater system was a normally closed and manually operated valve. The normal procedure for using the auxiliary feedwater pump, Procedure OP-1106.016, Condensate, Feedwater, and Steam System Operation, Revision 68, directed the minimum flow valve to be open when the pump was running.

The inspectors reviewed the emergency and abnormal operating procedures and discovered that the procedures directed operators to start the pump without opening the minimum flow valve or establishing a forward flow path within any specific time. The inspectors concluded that the licensees emergency and abnormal operating procedures did not establish minimum flow protection for the pump, which could result in pump failure. The licensee documented the issue as Condition Report CR-ANO-1-2014-00286 and corrected the affected procedures.

The affected procedures included:

OP-1202.002, Loss of Subcooling Margin, Revision 8

OP-1202.004, Overheating, Revision 7

OP-1202.006, Tube Rupture, Revision 15

OP-1202.012, Repetitive Tasks, Revision 12

OP-1203.013, Natural Circulation Cooldown, Revision 19

OP-1203.029, Remote Shutdown, Revision 11

OP-1203.040, Forced Flow Cooldown, Revision 7 The affected procedure sections had not been modified in over 20 years, and the inspectors determined that there were no other opportunities to identify the issue.

Analysis.

The failure to provide minimum flow protection for the Unit 1 auxiliary feedwater pump in emergency and abnormal operating procedures in accordance with the emergency operating procedure writers guide was a performance deficiency. The performance deficiency was more than minor because it was associated with the procedure quality attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences, and was therefore a finding. Specifically, inadequate emergency and abnormal operating procedures could have resulted in failure of the auxiliary feedwater pump, a mitigating system for a loss of main and emergency feedwater. Using Manual Chapter 0609, 4, Initial Characterization of Findings, June 19, 2012, and Appendix A, The Significance Determination Process (SDP) for Findings at Power, June 19, 2012, Exhibit 2, Mitigating Systems Screening Questions, the inspectors determined that the finding required a detailed risk evaluation because the finding represented a loss of system function. A Region IV senior reactor analyst performed the detailed risk evaluation and determined that the change to the core damage frequency was less than 4.2E-7/year (Green). The dominant core damage sequences included losses of one of the safety related 4160 volt electrical buses, steam generator tube ruptures, and plant transients. The equipment that helped mitigate the risk included the high pressure injection system (for feed and bleed) and the main and emergency feedwater systems. The detailed analysis is contained in Attachment 3. This finding did not have a cross-cutting aspect associated with it because the most significant contributing cause was not indicative of present performance. Specifically, the emergency and abnormal operating procedures for operating auxiliary feedwater had not changed for at least 20 years.

Enforcement.

Technical Specification 5.4.1.b requires, in part, that the licensee establish written emergency operating procedures required to implement the requirements of NUREG-0737, Supplement 1, Clarification of TMI Action Plan Requirements: Requirements for Emergency Response Capability, January 1983.

NUREG-0737, Supplement 1, Section 7.1, Item c, requires, in part, emergency operating procedures to be consistent with an appropriate procedure Writers Guide. Procedure OP-1015.029, Unit One Emergency Operating Procedure Writers Guide, Revision 003-03-0, Step 6.1.5, states, in part, that the procedure is to be written so that the safety of the equipment is not compromised. Contrary to the above, as of July 16, 2014, the licensee failed to establish written emergency operating procedures, consistent with an appropriate procedure writers guide, so that the safety of the equipment was not compromised. Specifically, the licensees Unit 1 emergency operating procedures compromised the safety of the auxiliary feedwater pump by not establishing minimum flow protection. The licensee subsequently revised the procedures to establish a flow path before starting the pump. This violation is being treated as a noncited violation (NCV), consistent with Section 2.3.2 of the Enforcement Policy. The violation was entered into the licensees corrective action program as Condition Report CR-ANO-1-2014-00286. (NCV 05000313/2014005-02, Failure to Provide Flow Protection for Auxiliary Feedwater Pump in Emergency Operating Procedures)

1R13 Maintenance Risk Assessments and Emergent Work Control

Main article: IP 71111.13

a. Inspection Scope

The inspectors reviewed three risk assessments performed by the licensee prior to changes in plant configuration and the risk management actions taken by the licensee in response to elevated risk:

October 2, 2014, Unit 2, high risk due to a planned emergency diesel generator train B outage and a severe weather warning

December 1, 2014, Unit 1, acceptable risk due to switchyard work

December 19, 2014, Units 1 and 2, acceptable risk due to 500 kV cross-tie breaker B-5106 removal in the switchyard The inspectors verified that these risk assessment were performed timely and in accordance with the requirements of 10 CFR 50.65 (the Maintenance Rule) and plant procedures. The inspectors reviewed the accuracy and completeness of the licensees risk assessments and verified that the licensee implemented appropriate risk management actions based on the result of the assessments.

Additionally, on October 2, 2014, the inspectors observed portions of an emergent work activity on Unit 2 involving an unplanned control element assembly surveillance which had the potential to cause an initiating event during an emergency diesel generator outage. The inspectors verified that the licensee appropriately developed and followed a work plan for these activities. The inspectors verified that the licensee took precautions to minimize the impact of the work activities on unaffected SSCs.

These activities constitute completion of four maintenance risk assessments and emergent work control inspection samples, as defined in Inspection Procedure 71111.13.

b. Findings

No findings were identified.

1R15 Operability Determinations and Functionality Assessments

Main article: IP 71111.15

a. Inspection Scope

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

November 14, 2014, Unit 1, operability determination for a gas void in the decay heat system

October 30, 2014, Unit 2, operability determination of service water leak

December 4, 2014, Unit 1, operability determination of fuel thermal conductivity model error

December 24, 2014, Unit 2, operability determination for low pressure safety injection pump breaker excessive plunger gap The inspectors reviewed the timeliness and technical adequacy of the licensees evaluations. Where the licensee determined the degraded SSC to be operable, the inspectors verified that the licensees compensatory measures were appropriate to provide reasonable assurance of operability. The inspectors verified that the licensee had considered the effect of other degraded conditions on the operability of the degraded SSC.

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

b. Findings

No findings were identified.

1R18 Plant Modifications

Main article: IP 71111.18

a. Inspection Scope

The inspectors reviewed two temporary plant modifications that affected risk-significant SSCs:

October 2, 2014, Unit 2, temporary hose installed to support recirculation and cleanup of emergency diesel fuel oil storage tank

December 4, 2014, Unit 1, temporary seismic support for service water piping while section of pipe removed for replacement The inspectors verified that the licensee had installed and removed these temporary modifications in accordance with technically adequate design documents. The inspectors verified that these modifications did not adversely impact the operability or availability of affected SSCs. The inspectors reviewed design documentation and plant procedures affected by the modifications to verify the licensee maintained configuration control.

These activities constitute completion of two samples of temporary modifications, as defined in Inspection Procedure 71111.18.

b. Findings

No findings were identified.

1R19 Post-Maintenance Testing

Main article: IP 71111.19

a. Inspection Scope

The inspectors reviewed eight post-maintenance testing activities that affected risk-significant SSCs:

October 2, 2014, Unit 1, turbine driven emergency feedwater pump steam admission valve, CV-2613, Agastya time delay relay calibration and valve test

October 9, 2014, Unit 2, high pressure safety injection pump, 2P-89B, overcurrent relay calibrations and pump test

October 10, 2014, Unit 2, turbine driven emergency feedwater steam admission valve, 2CV-0340-2, relay calibration and valve test

October 29, 2014, Unit 2, emergency control room chiller service water inlet valve test

November 12, 2014, Unit 1, high pressure injection pump, P-36B, inboard seal replacement due to excessive leakage and pump test

November 20, 2014, Unit 2, high pressure safety injection pump 2P-89A, pump seal and bearing leak repairs and pump test

November 21, 2014, Unit 1, service water pump, P-4A, pump replacement and pump test

December 5, 2014, Unit 1, reactor building cooling service water return containment isolation valve test The inspectors reviewed licensing- and design-basis documents for the SSCs and the maintenance and post-maintenance test procedures. The inspectors observed the performance of the post-maintenance tests to verify that the licensee performed the tests in accordance with approved procedures, satisfied the established acceptance criteria, and restored the operability of the affected SSCs.

These activities constitute completion of eight post-maintenance testing inspection samples, as defined in Inspection Procedure 71111.19.

b. Findings

No findings were identified.

Cornerstone: Emergency Preparedness

1EP6 Drill Evaluation

Main article: IP 71114.06

a. Inspection Scope

On October 8, 2014, the inspectors observed Unit 2 simulator-based licensed operator requalification training that included implementation of the licensees emergency plan.

The inspectors verified that the licensees emergency classifications, off-site notifications, and protective action recommendations were appropriate and timely. The inspectors verified that any emergency preparedness weaknesses were appropriately identified by the evaluators and entered into the corrective action program for resolution.

These activities constitute completion of one training observation sample, as defined in Inspection Procedure 71114.06.

b. Findings

No findings were identified.

1EP7 Exercise Evaluation - Hostile Action Event

Main article: IP 71114.07

a. Inspection Scope

The inspectors observed the September 16, 2014, biennial emergency plan exercise to verify the exercise acceptably tested the major elements of the emergency plan, provided opportunities for the emergency response organization (ERO) to demonstrate key skills and functions, and demonstrated the licensees ability to coordinate with offsite emergency responders. The scenario simulated the following to demonstrate the licensees capability to implement its emergency plan under conditions of uncertain physical security:

An airborne threat to the plant which ended in a plane crash before reaching the station

A subsequent land-based attack in the site switchyard that destroyed switchyard equipment and made offsite power unavailable to both units

An armed attack on a licensee building in the owner-controlled area which resulted in taking plant employees hostage

An armed adversary inside the protected area who engaged the site security force

A lube-oil system problem on diesel generator 1

An air pressure problem on the alternate ac diesel generator During the exercise the inspectors observed activities in the control room simulator and the following emergency response facilities:

Alternate Technical Support Center

Alternate Operations Support Center

Emergency Operations Facility

Central and/or Secondary Alarm Station(s)

Incident Command Post The inspectors focused their evaluation of the licensees performance on event classification, offsite notification, recognition of offsite dose consequences, development of protective action recommendations, staffing of alternate emergency response facilities, and the coordination between the licensee and offsite agencies to ensure reactor safety under conditions of uncertain physical security.

The inspectors also assessed recognition of, and response to, abnormal and emergency plant conditions, the transfer of decision-making authority and emergency function responsibilities between facilities, onsite and offsite communications, protection of plant employees and emergency workers in an uncertain physical security environment, emergency repair evaluation and capability, and the overall implementation of the emergency plan to protect public health and safety and the environment. The inspectors reviewed the current revision of the facility emergency plan, emergency plan implementing procedures associated with operation of the licensees primary and alternate emergency response facilities, and procedures for the performance of associated emergency and security functions.

The inspectors attended the post-exercise critiques in each emergency response facility to evaluate the initial licensee self-assessment of exercise performance. The inspectors also attended the licensees subsequent formal presentation of critique items to plant management conducted September 29, 2014. The specific documents reviewed during this inspection are listed in the attachment.

The inspectors reviewed the scenario of previous biennial exercises and licensee drills conducted between January 2013 and August 2014 to determine whether the September 16, 2014, exercise was independent and avoided participant preconditioning, in accordance with the requirements of 10 CFR 50, Appendix E, IV.F(2)(g). The inspectors also compared observed exercise performance with corrective action program entries and after-action reports for drills and exercises conducted between January 2013 and August 2014 to determine whether identified weaknesses had been corrected in accordance with the requirements of 10 CFR 50.47(b)(14), and 10 CFR 50, Appendix E, IV.F.

These activities constituted completion of one exercise evaluation sample as defined in Inspection Procedure 71114.07.

b. Findings

.1 Failure to Correct Weaknesses During an Evaluated Exercise

Introduction.

The inspectors identified a non-cited violation of 10 CFR Part 50.47(b)(14),for the failure to correct deficiencies identified in an August 7, 2013, drill. Specifically, the licensee did not implement Procedure 1203.048, Security Event, Change 022, during a drill conducted August 7, 2013, and also did not implement Procedure 1203.048, Change 28, during the September 17, 2014, biennial exercise.

The licensees corrective actions for the August 7, 2013, drill were ineffective because the licensee did not recognize that operators were not proficient with Procedure 1203.048 and, therefore, did not train all control room crews.

Description.

The inspectors observed the September 16, 2014, biennial exercise and determined that control room operators failed to maintain continuous communication with threat notification sources during a simulated potential aircraft threat. Specifically, communicators in the simulator control room did not establish open-line communication with exercise controllers acting as the NRC headquarters operation officer following two threat communications as directed by Procedure 1203.048, Security Event, Change 022, and discontinued communications. During a hostile action-based drill conducted on August 7, 2013, the simulator control room communicators also discontinued communications with the drill controller representing the NRC following each threat communication. This was identified by the licensee in their critique process and documented in Condition Report CR-ANO-C-2013-02107.

When a licensee is notified of a potential aircraft threat, they are required by 10 CFR Part 50.54(hh)(1)(ii) to implement procedures that describe how they will maintain continuous communications with threat notification sources. Continuous communication during a potential aircraft threat provides the licensee with up-to-date information on the threat. Failing to maintain continuous information may delay the recognition of changes in threat status and delay the licensees implementation of protective actions for on-site personnel, and potentially affect the safe shutdown of the reactor and implementation of the site emergency plan. The licensees requirement is Procedure 1203.048, Security Event, Change 022, Section 2.0, Sub-Sections 1.C),2.C), and 3.B), which state, Ensure that continuous communications are maintained with the notifying agency and the NRC Headquarters Operation Center for the duration of the event.

Procedure 1203.048, Change 022, was the current revision during the August 7, 2013, drill; the inspectors determined that Change 022 contained directions to maintain continuous communications with threat notification sources in accordance with 10 CFR Part 50.54(hh)(1)(ii). The inspectors determined that the licensees corrective action following the August 7, 2013, drill consisted of a communication (email) to the simulator control room drill crew participating that day to sensitize them to the need to follow procedures with respect to ensuring continuous communications and initiation of Condition Report CR-ANO-C-2013-02107. However, the deficiency identified in the condition report was primarily characterized as an emergency preparedness drill controller issue rather than a drill performance issue. This was because the licensee determined that the failure of the simulator control room communicators to establish continuous communications resulted from the drill controller acting as the NRC not requesting continuous communications. The licensee completed these corrective actions by August 19, 2013.

During the September 16, 2014, exercise the controller, acting as the NRC Headquarters Operation Center, called the control room at 7:38 a.m., speaking to the shift manager.

After receiving credible information about an aircraft threat, the shift manager discontinued phone communications with the simulated NRC Headquarters Operations Officer. The controller called the control room again at 7:45 a.m. with additional information about the threat; this call was also discontinued. When the Unit 1 shift manager called the simulated NRC at 7:53 a.m., continuous communication was established. According to Exercise Guide Message No. 2, the licensee controller acting as the NRC was directed as part of the initial (7:38 a.m.) message to the control room to say, The NRC requests that you maintain an open line of communication from this time. The licensee identified failures to establish continuous communications with the NRC during their management critique conducted September 28, 2014, and entered the issues into the corrective action program in corrective action documents WT-WTANO-2014-00189 and Condition Report CR-ANO-C-2014-02478.

The inspectors determined that licensee staff is responsible for implementing Procedure 1203.048 regardless of whether the (simulated) NRC communicator requests continuous communication. The failure to provide continuous communications could have affected the licensees ability to effectively implement the site emergency plan by delaying necessary actions to protect the reactor core and implement protective actions for plant personnel. Therefore, the failure to implement continuous communication with the threat source is a weakness that must be corrected in accordance with the requirements of 10 CFR 50.47(b)(14).

Analysis.

A weakness is defined in Section 2.0(l) of Manual Chapter 0609, Appendix B, Emergency Preparedness Significance Determination Process (SDP), dated February 24, 2012, as performance during an exercise that would have precluded the effective implementation of the emergency plan had the circumstances occurred. The failure to correct weaknesses occurring in drills and exercises is a performance deficiency within the licensees ability to foresee and correct. The performance deficiency is more than minor because it is associated with the ERO performance attribute of the Emergency Preparedness Cornerstone and it adversely impacted the cornerstone objective. The licensees ability to implement adequate measures to protect the health and safety of the public in the event of hostile action and a radiological emergency is degraded when it fails to correct performance that precludes the effective implementation of the emergency plan. This finding was evaluated using Manual Chapter 0609, Appendix B, Emergency Preparedness Significance Determination Process (SDP), Attachment 2, dated February 24, 2012, and was determined to be of very low safety significance (Green) because it was a failure to comply with NRC requirements, was not associated with a risk-significant planning standard, and was not a loss of planning standard function. The finding was not a loss of function because the deficiency that was identified was not associated with classification, notifications to state and local agencies, or the development of protective action recommendations.

The finding was assigned a cross-cutting aspect in the area of problem identification and resolution, associated with the resolution of issues because the licensee failed to evaluate the initial performance issues to ensure that resolutions adequately addressed the causes and extent of condition commensurate with their safety significance. When the deficiency was first identified in August 2013, the licensee failed to recognize that continuous communications with threat notification sources is required by regulation and that performance issues with the implementing procedure should be communicated to the entire control room staff population (e.g., inadequate extent of condition) [P.2].

Enforcement.

Title 10 of the Code of Federal Regulations, Part 50.47(b)(14) requires, in part, that deficiencies identified as a result of exercises or drills are (will be) corrected.

Part 50.54(hh)(1)(ii) requires, that if a licensee is notified of a potential aircraft threat, a licensee shall develop, implement and maintain procedures that describe how they will address maintenance of continuous communication with threat notification sources.

Contrary to the above, on September 17, 2014, the licensee failed to correct weaknesses in ERO performance associated with their implementation of 10 CFR 50.54(hh)(1)(ii). Specifically, the licensee did not correct failures to maintain continuous communications with threat notification sources when notified of a potential aircraft threat. This violation is being treated as a noncited violation (NCV), consistent with Section 2.3.2 of the Enforcement Policy. The violation was entered into the licensees corrective action program under corrective action documents WT-WTANO-2014-00189 and Condition Report CR-ANO-C-2014-02478. (NCV 05000313; 368/2014005-03, Failure to Correct Weaknesses During Drills and Exercises)

.2 Failure to Identify Weaknesses During an Evaluated Exercise

The inspectors identified a Green non-cited violation of 10 CFR 50.47(b)(14) during an exercise conducted September 16, 2014. Title 10 of the Code of Federal Regulations, Part 50.47(b)(14) requires, in part, that deficiencies identified as a result of exercises be corrected. Because the performance deficiency includes information about the licensees physical security program the details are not publicly available. The performance deficiency is documented in NRC Inspection Report 05000313/2014403, 05000368/2014403.

1EP8 Exercise Evaluation - Scenario Review

Main article: IP 71114.08

a. Inspection Scope

The licensee submitted the preliminary exercise scenario for the September 16, 2014, biennial exercise to the NRC on July 14, 2014, in accordance with the requirements of 10 CFR 50, Appendix E, IV.F(2)(b). The inspectors performed an in-office review of the proposed scenario to determine whether it would acceptably test the major elements of the licensees emergency plan, and provide opportunities for the ERO to demonstrate key skills and functions.

b. Findings

No findings were identified.

The inspectors reviewed the licensees records of Alert and Notification System tests conducted between April 2013 and June 2014 to verify the accuracy of the licensees data for siren system testing opportunities. The inspectors reviewed procedural guidance on assessing Alert and Notification System opportunities and the results of periodic alert and notification system operability tests. The inspectors used definitions and guidance contained in Nuclear Energy Institute Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7, to determine the accuracy of the data reported. The specific documents reviewed are described in the attachment to this report.

These activities constituted verification of the alert and notification system reliability performance indicator as defined in Inspection Procedure 71151.

b. Findings

No findings were identified.

4OA2 Problem Identification and Resolution

Main article: IP 71152

.1 Routine Review

a. Inspection Scope

Throughout the inspection period, the inspectors performed daily reviews of items entered into the licensees corrective action program and periodically attended the licensees condition report screening meetings. The inspectors verified that licensee personnel were identifying problems at an appropriate threshold and entering these problems into the corrective action program for resolution. The inspectors verified that the licensee developed and implemented corrective actions commensurate with the significance of the problems identified. The inspectors also reviewed the licensees problem identification and resolution activities during the performance of the other inspection activities documented in this report.

b. Findings

No findings were identified.

.2 Semiannual Trend Review

a. Inspection Scope

On October 7, 2014, the inspectors reviewed condition reports associated with entry conditions for abnormal operating procedures. The inspectors reviewed the licensees corrective action program, performance indicators, system health reports, operator logs, and other documentation to identify trends that might indicate the existence of a more significant safety issue. The inspectors verified that the licensee was taking corrective actions to address identified adverse trends.

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

b. Observations and Assessments The inspectors noted that several condition reports discussed issues that met the Unit 2 abnormal operating procedure (AOP) entry criteria, however the licensee only referenced the procedures. Procedure, OP-1015.021, ANO-2 EOP/AOP User Guide, Revision 012, that states, If any Entry Conditions Not discussed in the brief are met, then the AOP should be entered. The licensee initiated condition reports ANO-CR-C-2014-02049 and ANO-CR-2-2014-02448 to document the concern and provided training to operators on entry conditions for abnormal operating procedures.

The inspectors verified that all procedurally required actions were taken during the abnormal condition.

c. Findings

No findings were identified.

.3 Annual Follow-up of Selected Issues

a. Inspection Scope

The inspectors selected two issues for an in-depth follow-up:

On December 16, 2014, inspectors reviewed operator workarounds for Units 1 and 2.

The inspectors assessed the licensees problem identification threshold, cause analyses, extent of condition reviews and compensatory actions. The inspectors verified that the licensee appropriately prioritized the planned corrective actions and that these actions were adequate to correct the condition.

On December 30, 2014, inspectors reviewed an operating experience evaluation for manual actions credited for operability for Units 1 and 2.

The inspectors assessed the licensees problem identification threshold, cause analyses, extent of condition reviews and compensatory actions. The inspectors verified that the licensee appropriately prioritized the planned corrective actions and that these actions were adequate to correct the condition.

These activities constitute completion of two annual follow-up samples, which included one operator work-around sample, as defined in Inspection Procedure 71152.

b. Findings

Introduction.

Inspectors identified a Green noncited violation of 10 CFR Part 50, Appendix B, Criterion III, Design Control, for the licensees failure to maintain design control of the Unit 2 vital switchgear ventilation system. Specifically, the licensee failed to ensure that the ventilation system was capable of cooling the switchgear under design basis conditions.

Description.

The inspectors reviewed Unit 2 Procedure OP-2107.002, ESF Electrical System Operation, Change 30, and noted that Section 10, ESF Switchgear 2A3 and 2A4 Room Cooling Requirements specified manual actions to start exhaust fans 2VEF-56A and 2VEF-56B in order to cool vital switchgear 2A3 and 2A4. The inspectors then noted that Engineering Report ER-ANO-2002-0141-000, Remove Autostart Capability of 2VEF-56A/B While Maintaining Control Room Alarms on 2A3/2A4 Switchgear Room, Revision 0, removed the automatic start function for the exhaust fans in 2002 and credited manual operator actions without adequate evaluation of the design basis room cooling requirements for the vital switchgear. Specifically, the licensee failed to evaluate the design basis for automatic room cooling and the remaining room coolers to verify they could automatically cool the vital switchgear. As a result of the inspectors observations, the licensee initiated Condition Report CR-ANO-2-2014-00352 and submitted Licensee Event Report 05000368/2014-001-00, Operation of Switchgear Rooms Ventilation Prohibited by Technical Specifications. The licensee also completed an evaluation of the vital switchgear room coolers to verify that they could adequately cool the Unit 2 vital switchgear under design basis conditions. The analysis showed that a single room cooler with service water supplied by the emergency cooling pond could cool the switchgear with approximately one degree Fahrenheit margin. Under design basis conditions, the exhaust fan could cool the room with approximately 20 degrees Fahrenheit margin. The inspectors concluded that this was a significant reduction in margin.

Analysis.

The licensees failure to ensure that the ventilation system was capable of cooling the Unit 2 vital switchgear under design basis conditions was a performance deficiency. The performance deficiency was more than minor because it was associated with the design control attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences, and was therefore a finding. Specifically, the licensee failed to ensure that the Unit 2 vital electrical equipment ventilation system could automatically cool the switchgear. Using Manual Chapter 0609, Attachment 4, Initial Characterization of Findings, June 19, 2012, and Appendix A, The Significance Determination Process (SDP) for Findings at Power, June 19, 2012, Exhibit 2, Mitigating Systems Screening Questions, the inspectors determined that the finding was of very low safety significance (Green)because the finding was a deficiency affecting the design of a mitigating system, and the system maintained its functionality. The inspectors determined that there was no cross-cutting aspect associated with this finding because the cause of the performance deficiency occurred more than three years ago, and was not representative of current licensee performance.

Enforcement.

Title 10 CFR Part 50, Appendix B, Criterion III, Design Control, states, in part, that design control measures shall provide for verifying or checking the adequacy of design, such as by the use of alternate or simplified calculational methods, and that design changes shall be subject to design control measures commensurate with those applied to the original design. Contrary to the above, between March 13, 2002, and February 13, 2014, the licensee failed to verify or check the adequacy of design during a design change. Specifically, the licensee failed to verify adequacy of the design of the Unit 2 vital switchgear ventilation to cool the vital switchgear during a design change that removed an automatic start of the exhaust fans. The licensee performed design calculations that showed the remaining automated ventilation equipment could support function of the vital switchgear. This violation is being treated as a noncited violation (NCV), consistent with Section 2.3.2 of the Enforcement Policy. The violation was entered into the licensees corrective action program as Condition Report CR-ANO-2-2014-00352. (NCV 05000368/2014005-04, Failure to Verify Ventilation Design for Vital Switchgear)

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

Main article: IP 71153

(Closed) Licensee Event Report 05000368/2014-001-00, Operation of Switchgear Rooms Ventilation Prohibited by Technical Specifications

a. Inspection Scope

The licensee replaced an automatic start for the Unit 2 vital switchgear room exhaust fans with manual action in 2002 without adequate justification. The licensee determined that the substituted manual action was inadequate, by itself, to maintain operability of the switchgear. In addition, the licensee discovered that the switchgear room coolers had been removed from service on February 13, 2014, leaving the switchgear without required room cooling, and therefore inoperable for longer than the technical specification allowed outage time. See Section 4OA2.3 of this report for a finding related to this licensee event report. This licensee event report is closed.

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

b. Findings

No findings were identified.

4OA5 Other Activities

.1 (Closed) Unresolved Item 05000368/2014003-09, Reporting of Unit 2 Events as

Unplanned Scrams with Complications.

The inspectors reviewed additional information provided by the licensee and confirmed that the Unit 2 main feedwater pumps could be restarted successfully within thirty minutes following a reactor trip or scram assuming the loss of emergency feedwater.

This meets the guidance in Nuclear Energy Institute Document 99-02, Regulatory Assessment Performance Indicator Guidance. Therefore, the events were uncomplicated and do not need to be reported under this performance indicator. This unresolved item is closed.

.2 (Closed) Temporary Instruction 2515/189: Inspection to Determine Compliance of

Dynamic Restraint (Snubber) Program with 10 CFR 50.55a Regulatory Requirements for Inservice Examination and Testing of Snubbers

a. Inspection Scope

The inspector reviewed the licensees snubber program against the requirements for the inservice examination and testing of snubbers under 10 CFR 50.55a, Codes and Standards, and paragraph 03.02 of the Temporary Instruction.

The inspector reviewed licensee documents detailing the snubber program, including licensee-controlled documents/procedures and any relief requests approved by the NRC for the snubber program. The inspector reviewed corrective action documents involving snubbers for the current 10-year interval, including any actions taken to address Regulatory Issue Summary 2010-06. In addition, the inspector observed snubber testing and conducted independent inspections of various snubber types.

b. Observations The inspector determined that the licensees snubber program complies with 10 CFR 50.55a regulatory requirements for inservice examination and testing of snubbers. In accordance with the Temporary Instruction, responses to specific questions were submitted to the NRC headquarters staff. Based upon the scope of the review described above, TI-2515/189 was completed.

c. Findings

No findings were identified.

.3 (Opened) Unit 2 Unplanned Scrams Performance Indicator

Introduction.

The inspectors identified an unresolved item associated with the Unit 2 unplanned scrams per 7,000 critical hours performance indicator related to a reactor trip.

Description.

On April 27, 2014, Unit 2 experienced an Axial Shape Index (ASI) trip when performing a rapid downpower at the request of the transmission grid operator due to severe weather affecting the grid. This unplanned reactor trip was caused by exceeding the Core Protection Calculator ASI limits. As noted in Licensee Event Report 05000368/2014-003-00, and NRC Inspection Report 2014004, the ASI limits were exceeded, due in part to plant operators not following the downpower reactivity plan.

The automatic trip occurred at approximately 50 percent power and was uncomplicated.

The unplanned scrams per 7000 critical hours performance indicator measures the rate of scrams per year of operation at power and provides an indication of initiating event frequency. The licensee did not include this scram as an input into the unplanned scram performance indicator and submitted a frequently asked question to the NRC Reactor Oversight Process Working Group. The frequently asked question is currently under review to decide whether the above event should be captured as an unplanned scram.

The licensee noted that anticipatory plant shutdowns to reduce the impact of external events are excluded from this performance indicator. The licensee believed the intent of the exclusion was met because the shutdown being performed at the time the reactor trip occurred had been requested by the transmission grid operator due to the impacts of weather conditions.

The inspectors noted that Nuclear Energy Institute Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7, guidance states that an unplanned scram is a scram that is not an intentional part of a planned evolution or test as directed by a normal operating or test procedure. This includes scrams that occurred during the execution of procedures or evolutions in which there was a high chance of a scram occurring but the scram was neither planned nor intended. The inspectors noted that the April 27, 2014 reactor trip was an automatic trip, which was not intended as part of the rapid downpower evolution that was being performed. The inspectors also noted that had the licensees reactivity plan been followed, the severity of the ASI transient would likely have been managed and a trip avoided.

The inspectors concluded that additional inspection was required to assess whether the scram should have been reported in the unplanned scrams per 7,000 critical hours performance indicator for Unit 2. This issue was identified as Unresolved Item URI 05000368/2014005-05, Unit 2 Unplanned Scrams Performance Indicator.

4OA6 Meetings, Including Exit

Exit Meeting Summary

On August 13, 2014, the inspectors discussed the in-office review of the preliminary scenario for the 2014 biennial exercise, submitted July 14, 2014, with Mr. R. Harris, Emergency Preparedness Manager, and other members of the licensee staff. The licensee acknowledged the issues presented.

On October 1, 2014, the inspectors presented the results of the onsite inspection of the biennial emergency preparedness exercise conducted September 16, 2014, to Mr. J. Browning, Site Vice President, and other members of the licensee staff. The licensee acknowledged the issues presented. The licensee confirmed that any proprietary information reviewed by the inspectors had been returned or destroyed.

On October 20, 2014, the inspectors conducted a telephonic exit meeting with Mr. J. Browning, Site Vice President, and other members of the licensee staff to discuss an additional issue associated with the September 16, 2014, biennial exercise. The licensee acknowledged the issues presented.

On December 22, 2014, the inspectors presented the TI-2515/189 inspection results to Mr. D. Edgell, System and Components Engineering Manager, and other members of the licensee staff. The licensee acknowledged the issues presented. The inspectors confirmed that any proprietary information provided had been returned or destroyed.

On January 6, 2014, the inspectors presented the inspection results to Mr. J. Browning, Site Vice President, and other members of the licensee staff. The licensee acknowledged the issues presented. The licensee confirmed that any proprietary information reviewed by the inspectors had been returned or destroyed.

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

J. Browning, Site Vice President

D. Edgell, Manager, System and Components Engineering

R. Harris, Manager, Emergency Preparedness

D. James, Director, Regulatory Recovery

N. Mosher, Licensing Specialist, Regulatory Assurance

S. Pyle, Manager, Regulatory Assurance

J. Tobin, Manager, Security

P. Williams, Director, Regulatory and Performance Improvement

NRC Personnel

R. Kahler, Branch Chief, NSIR/DPR/IRIB

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened

05000368/2014005-05 URI Unit 2 Unplanned Scrams Performance Indicator (Section 4OA5.3)

Opened and Closed

05000368/2014005-01 NCV Failure to Develop Adequate Guidance for Extreme Damage Mitigation (Section 1R04)

05000313/2014005-02 NCV Failure to Provide Flow Protection For Auxiliary Feedwater Pump in Emergency Operating Procedures (Section 1R12)

05000313/2014005-03 NCV Failure to Correct Weaknesses During Drills and Exercises

05000368/2014005-03 (Section 1EP7.1)

05000368/2014005-04 NCV Failure to Verify Ventilation Design for Vital Switchgear (Section 4OA2.3)

Closed

05000368/2014-01-00 LER Operation of Switchgear Rooms Ventilation Prohibited by Technical Specifications (Section 4OA3)

05000368/2014003-09 URI Reporting of Unit 2 Events as Unplanned Scams with Complications (Section 4OA5.1)

05000313/2515-189 TI Inspection to Determine Compliance of Dynamic Restraint

05000368/2515-189 (Snubber) Program with 10 CFR 50.55a Regulatory Requirements for Inservice Examination and Testing of Snubbers (Section 4OA5.2)

LIST OF DOCUMENTS REVIEWED