IR 05000416/2013003

IR 05000416-13-003; 04/07/2013 - 06/28/2013; Grand Gulf Nuclear Station, Unit 1, Integrated Resident and Regional Report; Fire Protection, Evaluations of Changes, Tests, and Experiments and Permanent Plant Modifications, Surveillance Testin

ML13224A057
Person / Time
Site:	Grand Gulf
Issue date:	08/12/2013
From:	Jessie Quichocho NRC/RGN-IV/DRP/RPB-C
To:	Kevin Mulligan Entergy Operations
Quichocho J
References
IR-13-003
Download: ML13224A057 (68)

Text

UNITED STATES NUC LEAR REGULATOR Y C OMMI SSI ON ust 12, 2013

SUBJECT:

GRAND GULF NUCLEAR STATION - NRC INTEGRATED INSPECTION REPORT 05000416/2013003

Dear Mr. Mulligan:

On June 29, 2013, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at the Grand Gulf Nuclear Station, Unit 1. The enclosed inspection report documents the inspection results, which were discussed on July 18, 2013, with you and other members of your staff.

The inspections 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.

Four NRC-identified findings of very low safety significance (Green) were identified during this inspection. These findings were determined to involve violations of NRC requirements.

Additionally, the NRC has determined that a traditional enforcement Severity Level IV violation occurred. This traditional enforcement violation was identified with an associated finding. The NRC is treating these violations as non-cited violations (NCVs) consistent with Section 2.3.2a of the Enforcement Policy.

If you contest these non-cited 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 IV; the Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at Grand Gulf Nuclear Station.

If you disagree with a cross-cutting aspect assignment in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your disagreement, to the Regional Administrator, Region IV; and the NRC Resident Inspector at Grand Gulf Nuclear Station. In accordance with 10 CFR 2.390 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 (PARS) component of NRC's Agencywide Document 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/

Jessie Quichocho, Chief (Acting)

Project Branch C Division of Reactor Projects Docket No.: 50-416 License No.: NPF-29

Enclosure:

Inspection Report 05000416/2013003 w/ Attachment: Supplemental Information

REGION IV==

Docket: 05000416 License: NPF-29 Report: 05000416/2013003 Licensee: Entergy Operations, Inc.

Facility: Grand Gulf Nuclear Station, Unit 1 Location: 7003 Baldhill Road Port Gibson, MS 39150 Dates: April 7 through June 28, 2013 Inspectors: R. Smith, Senior Resident Inspector B. Rice, Resident Inspector R. Kopriva, Senior Reactor Inspector, Lead J. Braisted, Reactor Inspector C. Hale, Reactor Inspector Approved Jessie Quichocho, Chief (Acting)

By: Reactor Project Branch C Division of Reactor Projects-1- Enclosure

SUMMARY OF FINDINGS

Inspection Report 05000416/2013003; 04/07/2013 - 06/28/2013; Grand Gulf Nuclear Station,

Unit 1, Integrated Resident and Regional Report; Fire Protection, Evaluations of Changes,

Tests, and Experiments and Permanent Plant Modifications, Surveillance Testing, and Problem Identification and Resolution.

The report covered a 3-month period of inspection by resident inspectors and announced baseline inspections by region-based inspectors. Four Green non-cited violations and one Severity Level IV non-cited violation of significance were identified. The significance of most findings is indicated by their color (Green, White, Yellow, or Red) using Inspection Manual Chapter 0609, Significance Determination Process. The cross-cutting aspect is determined using Inspection Manual Chapter 0310, Components Within the Cross-Cutting Areas.

Findings for which the significance determination process does not apply may be Green or be assigned a severity level after Nuclear Regulatory Commission (NRC) management review.

The NRC's program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process, Revision 4, dated December 2006.

Cornerstone: Mitigating Systems

Green.

The inspectors identified a non-cited violation of Facility Operating License Condition 2.C(41) for the failure to properly implement a compensatory fire watch per the station fire protection program. Following an inadvertent release of carbon dioxide from the Cardox automatic fire suppression system into a division 2 safety related switchgear room located in the auxiliary building, the operators isolated the auxiliary building from the Cardox system to prevent any future inadvertent releases. The inspectors accompanied the fire watch patrol, which was required due to the isolation of the Cardox system to the auxiliary building, and they noted that during the patrol, none of the 10 rooms requiring a fire watch were checked. The inspectors brought this concern to the shift manager who confirmed that each room was required to be checked per the established fire watch criteria and that the fire watch patrol misunderstood the requirement. The licensee took immediate corrective action to direct the fire watch to check all the rooms to restore compliance with the fire watch requirements. The licensee entered this issue into the corrective action program as Condition Report CR-GGN-2013-04058.

The failure to perform a fire watch in accordance with the fire protection program is a performance deficiency. The performance deficiency is more than minor and therefore a finding because it is associated with the protection against the external factors 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, failing to perform the fire watch correctly adversely impacted the plants capability to detect and suppress a fire in a timely manner.

Using NRC Inspection Manual Chapter 0609, Attachment 4, "Initial Characterization of Findings," the inspectors determined that the issue affected the Mitigating Systems Cornerstone. Using NRC Inspection Manual Chapter 0609, Attachment 4, Table 3, the inspectors were directed to NRC Inspection Manual Chapter 0609, Appendix F, Fire Protection Significance Determination Process. The inspectors determined that the finding had an adverse affect on the fixed fire protection systems element of fire watches posted as a compensatory measure for outages or degradations. The inspectors assigned a high degradation rating due to the automatic fire suppression system being tagged out of service. Because the system was degraded without compensatory actions for less than three days, the inspectors used a duration factor of 0.01. The inspectors used 2E-2 for a generic fire frequency area for a switchgear room. The resulting change in core damage frequency was 2E-4, which was greater than the high degradation Phase 1 Quantitative Screening Criteria of 1E-6. Therefore, a senior reactor analyst performed a detailed risk evaluation.

The analyst performed a bounding analysis of the performance deficiency (See Table 1R05-1). For each of the 10 affected fire areas, the analyst determined the probability of a fire occurring by multiplying the fire ignition frequency from the licensees fire hazards analysis by the 9.2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> that the performance deficiency impacted the plant. Because each fire area had a functional fire detection system throughout the exposure period, the analyst determined the non-detection probability by multiplying the fire probability by the generic failure probability for a detection system. The analyst made the bounding assumption that all fires postulated to initiate that were not detected would proceed to core damage. The sum of all the non-detection probabilities was 9.1 x 10-7 (See Table 1R05-1). Therefore, the bounding analysis indicates that this finding is of very low safety significance (Green).

The inspectors determined the apparent cause of this finding was that the security officers performing the fire watch patrols did not understand the requirement to visually check the affected rooms. Therefore, the finding has a cross-cutting aspect in the human performance area associated with the work practices component because the licensee did not communicate human error prevention techniques such as pre-job briefings and proper documentation of activities commensurate with the risk of the assigned task H.4(a) (Section 1R05.1.b).

Green.

The inspectors identified a non-cited violation of 10 CFR Part 50,

Appendix B, Criterion XVI, Corrective Action, which states, in part, that Measures shall be established to assure that conditions adverse to quality, such as failures, malfunctions, deficiencies, deviations, defective material and equipment, and nonconformances, are promptly identified and corrected.

Specifically, from November 3, 1988, until March 6, 2010, actions to correct known design deficiencies on the left and right banks intercooler inlet plenums of both the division 1 and 2 standby diesel generators were not fully implemented.

The design deficiency, identified by the vendor, could result in intercooler tube failure and jacket water leakage. The finding was entered into the licensees corrective action program as Condition Report CR-GGN-2013-02631.

The failure to correct a nonconforming condition in the division 1 and 2 standby diesel generators inlet plenums is a performance deficiency. The performance deficiency is more than minor and therefore a finding because it adversely affected the Mitigating Systems Cornerstone attribute of equipment performance and affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage), and if left uncorrected, the performance deficiency had the potential to lead to a more significant safety concern.

Specifically, the licensees failure to implement corrective actions to resolve a known design deficiency of the intercooler inlet plenums could have resulted in either the division 1 or 2 standby diesel generator failing to perform its safety function. Using Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, the finding was determined to be of very low safety significance (Green), because the finding was a design deficiency affecting a mitigating systems structure, system, or component that did not lose operability or functionality. The finding did not have a cross-cutting aspect because the most significant contributor to the performance deficiency did not reflect current licensee performance (Section 1R17.1.b.2).

Green.

The inspectors identified a non-cited violation of 10 CFR Part 50,

Appendix B, Criterion XVI, Corrective Action, which states, in part, that Measures shall be established to assure that conditions adverse to quality, such as failures, malfunctions, deficiencies, deviations, defective material and equipment, and nonconformances, are promptly identified and corrected.

Specifically, from November 20, 1998, until November 7, 2012, actions to correct a known nonconforming condition involving the low pressure interlock of the train B starting circuit on both the division 1 and 2 standby diesel generators had not been implemented. If the train A starting circuit were to fail and starting air pressure were to fall below 120 psig, the diesel generator would have all automatic shutdown permissives active, which are supposed to be bypassed during a loss-of-coolant-accident signal. This was considered a single point vulnerability for the train B starting circuit. The finding was entered into the licensees corrective action program as Condition Report CR-GGN-2013-02524.

The failure to correct a nonconforming condition in the division 1 and 2 standby diesel generators train B starting circuits is a performance deficiency. The performance deficiency is more than minor and therefore a finding because it affected the Mitigating Systems Cornerstone attribute of equipment performance and affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage), and if left uncorrected, the performance deficiency had the potential to lead to a more significant safety concern.

Specifically, the licensees failure to implement corrective actions to resolve a known nonconforming condition of the low pressure interlock of the train B starting circuit could have resulted in either the division 1 or 2 standby diesel generator failing to perform its safety function. Using Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, the finding was determined to be of very low safety significance (Green), because the finding was a design deficiency affecting a mitigating systems structure, system, or component that did not lose operability or functionality. The finding did not have a cross-cutting aspect because the most significant contributor to the performance deficiency did not reflect current licensee performance (Section 1R17.1.b.3).

Green.

The inspectors identified a non-cited violation of Technical Specification Surveillance Requirement SR 3.5.1.1 for the failure to verify the residual heat removal B system was full of water within its specified frequency. The inspectors reviewed a low pressure core injection subsystem B monthly functional test that was performed on April 10, 2013, per Procedure 06-OP-1E12-M-0002,

LPCI/RHR Subsystem B Monthly Functional Test, Revision 113. The inspectors identified that the licensee failed to perform ultra sonic testing on the pipe prior to and after venting of the pipe directly upstream of the residual heat removal heat exchanger B outboard vent valve (1E12F074B). By not performing the ultra sonic testing, the licensee did not verify the residual heat removal system was full of water as required by Surveillance Requirement 3.5.1.1.

Immediate corrective actions included performing the ultra sonic tests, which verified the system was full of water and satisfied the surveillance requirement.

The licensee entered this issue into their corrective action program as Condition Report CR-GGN-2013-02847.

The failure to verify the residual heat removal B system was full of water as required by Technical Specification Surveillance Requirement SR 3.5.1.1 is a performance deficiency. The performance deficiency is more than minor and therefore a finding because it is associated with the equipment performance attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstones objective of ensuring the availability, reliability and capability of systems that respond to prevent undesirable consequences. Specifically, the failure to perform the required ultra sonic testing resulted in Technical Specification Surveillance Requirement SR 3.5.1.1 not being met. Therefore, the licensee could not ensure the system would perform properly by injecting its full capacity into the reactor coolant system upon demand. Using NRC Inspection Manual Chapter 0609, Attachment 4, Initial Characterization of Findings, the inspectors determined that the issue affected the Mitigating Systems Cornerstone. In accordance with NRC Inspection Manual Chapter 0609,

Appendix A, The Significance Determination Process (SDP) for Findings at Power, the inspectors determined that the issue had a very low safety significance (Green) because it was not a deficiency affecting the design or qualification of a mitigating system, structure, or component, does not represent a loss of system or function, does not represent a loss of function for greater than its technical specification allowed outage time, and does not represent a loss of function as defined by the licensees Maintenance Rule program for greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. Through interviews with operations personnel, the inspectors determined the apparent cause of the finding was that management failed to ensure the ultra sonic test was performed. Therefore, the finding had a cross-cutting aspect in the human performance area associated with the work practices component because the licensee failed to ensure supervisory and management oversight of work activities H.4(c) (Section 1R22.b).

Cornerstone: Barrier Integrity

• SLIV. The inspectors identified a non-cited violation of 10 CFR 50.71(e)(4),

which requires the Final Safety Analysis Report be updated, at intervals not exceeding 24 months, and states in part, the revisions must reflect all changes made in the facility or procedures described in the FSAR. Specifically, the inspectors identified three examples of changes to figures or tables that had not been included in the licensees Updated Final Safety Analysis Report submittal in November, 2012:

(1) Figure 9.2-027, Sheet 2, Revision 16 Plant Service Water Radial Well System Unit 1 (2) Figure 10.4-011, Condensate System (Drawing M-1053B, Revision 28), and (3) Table 9.1-12, Maximum Fuel Pool Heat Load did not include values associated with the extended power uprate.

This finding has been entered into the licensees corrective action program as Condition Reports CR-GGN-2013-00426, CR-GGN-2013-02661, and CR-GGN-2013-02471.

The failure of the licensee to include all changes made to the facility or procedures in their November 2012 update to the original revision of the Final Safety Analysis Report is a performance deficiency. The issue is a performance deficiency because it was a failure to meet a requirement, 10 CFR 50.71(e)(4),

and it was within the licensees ability to correct this problem. Using Inspection Manual Chapter 0612, Appendix B, the performance deficiency was assessed through both the Reactor Oversight Process and traditional enforcement because the finding had the potential for impacting the NRCs ability to perform its regulatory function. By screening through the Reactor Oversight Process, the finding resulted in a minor performance deficiency. Following the traditional enforcement path, the inspectors used the NRC Enforcement Policy, dated January 28, 2013, to evaluate the significance of this violation. Consistent with the NRC Enforcement Policy and in accordance with Section 6.1.d.3, this finding was determined to be a Severity Level IV non-cited violation because the licensee failed to update the Final Safety Analysis Report as required by 10 CFR 50.71(e)(4). However, the lack of up-to-date information had not resulted in any unacceptable change to the facility or procedures. This finding had no cross-cutting aspect (Section 1R17.1.b.1).

Licensee-Identified Violations

None

PLANT STATUS

Grand Gulf Nuclear Station began the inspection period at 100 percent rated thermal power.

On June 24, 2013, the operators reduced reactor power to approximately 62 percent for a planned control rod sequence exchange, investigation of inleakage in the offgas system, and repair of moisture separator reheater heating steam valves.

On June 26, 2013, the operators commenced power ascension activities. The plant continued power ascension activities through the end of the quarter.

REPORT DETAILS

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R01 Adverse Weather Protection

.1 Summer Readiness for Offsite and Alternate-AC Power Systems

a. Inspection Scope

The inspectors performed a review of preparations for summer weather for selected systems, including conditions that could lead to loss-of-offsite power. The inspectors reviewed the procedures affecting these areas and the communications protocols between the transmission system operator and the plant to verify that the appropriate information was being exchanged when issues arose that could affect the offsite power system. Examples of aspects considered in the inspectors review included:

• the coordination between the transmission system operator and the plants operations personnel during off-normal or emergency events,

• the explanations for the events,

• the estimates of when the offsite power system would be returned to a normal state, and

• the notifications from the transmission system operator to the plant when the offsite power system was returned to normal.

During the inspection, the inspectors focused on plant-specific design features and the procedures used by plant personnel to mitigate or respond to adverse weather conditions. Additionally, the inspectors reviewed the Updated Final Safety Analysis Report and performance requirements for systems selected for inspection and verified that operator actions were appropriate as specified by plant-specific procedures.

Specific documents reviewed during this inspection are listed in the attachment. The inspectors also reviewed corrective action program items to verify that the licensee was identifying adverse weather issues at an appropriate threshold and entering them into their corrective action program in accordance with station corrective action procedures.

The inspectors reviews focused specifically on the following plant systems:

• 500 KV switchyard

• 115 KV switchyard These activities constitute completion of one sample to evaluate the readiness of offsite and alternate-ac power for summer weather, as defined in Inspection Procedure 71111.01-05.

b. Findings

No findings were identified.

.2 Readiness to Cope with External Flooding

a. Inspection Scope

The inspectors evaluated the design, material condition, and procedures for coping with the design basis probable maximum flood. The evaluation included a review to check for deviations from the descriptions provided in the Updated Final Safety Analysis Report for features intended to mitigate the potential for flooding from external factors. As part of this evaluation, the inspectors checked for obstructions that could prevent draining, checked that the roofs did not contain obvious loose items that could clog drains in the event of heavy precipitation, and determined that barriers required to mitigate the flood were in place and operable. Additionally, the inspectors performed an inspection of the protected area to identify any modification to the site that would inhibit site drainage during a probable maximum precipitation event or allow water ingress past a barrier.

The inspectors also reviewed the abnormal operating procedure for mitigating the design basis flood to ensure it could be implemented as written. Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of one external flooding sample, as defined in Inspection Procedure 71111.01-05.

b. Findings

No findings were identified.

1R04 Equipment Alignment

.1 Partial Walkdown

a. Inspection Scope

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

• Division 2 diesel generator during division 1 diesel generator maintenance

• Residual heat removal system B during residual heat removal system A maintenance

• Standby service water B during standby service water A maintenance 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 affect the function of the system, and, therefore, potentially increase risk. The inspectors reviewed applicable operating procedures, system diagrams, Updated Final Safety Analysis Report, technical specification requirements, administrative technical specifications, outstanding work orders, condition reports, 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 inspected accessible portions of the systems to verify system components and support equipment were aligned correctly and 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. Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of three partial system walkdown samples as defined in Inspection Procedure 71111.04-05.

b. Findings

No findings were identified.

1R05 Fire Protection

.1 Quarterly Fire Inspection Tours

a. Inspection Scope

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

• Fire areas 1A121 and 1A123, auxiliary building, 103 foot elevation

• Fire area 1D301, diesel generator building corridor

• Fire area 1D303, division 2 diesel generator room

• Fire area 1A105 and 1A106, residual heat removal pump B room

• Fire area 2M110 and 2M112, standby service water pump B room and valve room

• Observed fire watch patrol for auxiliary building rooms 1A207, 1A208, 1A219, 1A221, 1A308, 1A309, 1A318, 1A320, 1A407, and 1A410 The inspectors reviewed areas to assess if licensee personnel 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 affect equipment that could initiate or mitigate a plant transient, or their impact on the plants ability to respond to a security event. Using the documents listed in the attachment, 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 fire doors, dampers, and penetration seals appeared to be in satisfactory condition. The inspectors also verified that minor issues identified during the inspection were entered into the licensees corrective action program.

Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of six quarterly fire-protection inspection samples, as defined in Inspection Procedure 71111.05-05.

b. Findings

Introduction.

The inspectors identified a Green non-cited violation of Facility Operating License Condition 2.C(41) for the failure to properly implement a compensatory fire watch per the station fire protection program.

Description.

On June 19, 2013, following an inadvertent release of carbon dioxide from the Cardox automatic fire suppression system into a division 2 safety-related switchgear room located in the auxiliary building, the operators isolated the auxiliary building from the Cardox system to prevent any future inadvertent releases. That action rendered the automatic fire suppression system inoperable for 10 switchgear rooms within the auxiliary building. As a compensatory measure, operations established hourly fire watches for these rooms. On June 20, 2013, the inspectors accompanied the fire watch patrol and noted that the person performing the fire watch did not check any of the 10 rooms requiring a fire watch. When the inspectors asked that person about the 10 rooms, the person replied that only the general hallway areas of the auxiliary building required the fire watch and that the rooms were not included. However, when the inspectors questioned the shift manager, the shift manager confirmed that the fire watch was required to check each room per the established fire watch criteria, and asserted that the fire watch patrol had misunderstood the requirement.

The licensee entered this issue into the corrective action program as Condition Report CR-GGN-2013-04058. As an immediate corrective action, the shift manager notified the security supervisor who directed the fire watch to check all the rooms to restore compliance with the fire watch requirements.

Analysis.

The failure to perform a fire watch in accordance with the fire protection program is a performance deficiency. The performance deficiency is more than minor and therefore is a finding because it is associated with the protection against the external factors 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, the failure to correctly perform the fire watch adversely impacted the plants capability to detect and suppress a fire in a timely manner. Using NRC Inspection Manual Chapter 0609, Attachment 4, "Initial Characterization of Findings," the inspectors determined that the issue affected the Mitigating Systems Cornerstone. Using NRC Inspection Manual Chapter 0609, Attachment 4, Table 3, the inspectors were directed to NRC Inspection Manual Chapter 0609, Appendix F, Fire Protection Significance Determination Process. The inspectors determined that the finding had an adverse affect on the fixed fire protection systems element of fire watches posted as a compensatory measure for outages or degradations. The inspectors assigned a high degradation rating due to the fact that the automatic fire suppression system was tagged out of service. Because the system was degraded without compensatory actions for less than three days, the inspectors used a duration factor of 0.01. The inspectors used 2E-2 for a generic fire frequency area, which corresponds to Table 1.4.2, Generic Fire Area Fire Frequencies, for a switchgear room. The resulting change in core damage frequency was 2E-4, which was greater than the high degradation Phase 1 Quantitative Screening Criteria of 1E-6.

Therefore the senior reactor analyst performed a detailed risk evaluation.

The analyst performed a bounding analysis of the performance deficiency (See Table

1R05 -1). For each of the ten affected fire areas, the analyst determined the probability

of a fire occurring by multiplying the fire ignition frequency from the licensees fire hazards analysis by the 9.2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> that the performance deficiency impacted the plant.

Because each fire area had a functional fire detection system throughout the exposure period, the analyst determined the non-detection probability by multiplying the fire probability by the generic failure probability for a detection system. The analyst made the bounding assumption that all fires postulated to initiate that were not detected would proceed to core damage. The sum of all the non-detection probabilities was 9.1 x 10-7, (See Table 1R05-1). Therefore, the bounding analysis indicates that this finding is of very low safety significance (Green).

Table 1R05-1: Results of Bounding Risk Analyses Area FIF Time FIre Fire Nondetection Number Compartment (/year) (years) Probability Detection Probability CA207 1.70E-03 1.05E-03 1.78E-06 0.05 8.89E-08 CA208 1.70E-03 1.05E-03 1.78E-06 0.05 8.89E-08 CA219 1.80E-03 1.05E-03 1.88E-06 0.05 9.42E-08 CA221 1.80E-03 1.05E-03 1.88E-06 0.05 9.42E-08 CA308 7.20E-04 1.05E-03 7.53E-07 0.05 3.77E-08 CA309 1.70E-03 1.05E-03 1.78E-06 0.05 8.89E-08 CA318 2.50E-03 1.05E-03 2.62E-06 0.05 1.31E-07 CA320 2.00E-03 1.05E-03 2.09E-06 0.05 1.05E-07 CA407 1.70E-03 1.05E-03 1.78E-06 0.05 8.89E-08 CA410 1.70E-03 1.05E-03 1.78E-06 0.05 8.89E-08 Total 9.06E-07 The apparent cause of this finding was that the security officers performing the fire watch patrols did not understand the requirement to visually check the affected rooms.

Therefore, the finding has a cross-cutting aspect in the human performance area associated with the work practices component because the licensee did not communicate human error prevention techniques such as pre-job briefings and proper documentation of activities commensurate with the risk of the assigned task H.4(a).

Enforcement.

Grand Gulf Nuclear Station Operating License Condition 2.C(41) states, in part, that the plant shall implement and maintain in effect all provisions of the Fire Protection Program as described in the Updated Final Safety Analysis Report. The fire protection program described in the Updated Final Safety Analysis Report includes Technical Requirements Manual Section 6.2.4, CO2 Systems, which requires an hourly fire watch patrol be performed if the required CO2 system is inoperable. Contrary to the above, on June 20, 2013, the licensee did not perform an hourly fire watch patrol when required CO2 systems were inoperable. The licensee restored compliance by performing the fire watch for the affected rooms on June 20, 2013. This violation is being treated as a non-cited violation, consistent with Section 2.3.2.a of the Enforcement Policy, because it was of very low safety significance (Green) and it was entered into the licensees corrective action program as Condition Report CR-GGN-2013-04058. (NCV 05000416/2013003-01, Failure to Properly Implement a Compensatory Fire Watch per Station Fire Protection Procedures)

1R06 Flood Protection Measures

a. Inspection Scope

The inspectors reviewed the Updated Final Safety Analysis Report, the flooding analysis, and plant procedures to assess susceptibilities involving internal flooding. They also reviewed the corrective action program to determine if licensee personnel identified and corrected flooding problems and verified that operator actions for coping with flooding can reasonably achieve the desired outcomes. The inspectors also inspected the area listed below to verify the adequacy of equipment seals located below the flood line and watertight door seals. Specific documents reviewed during this inspection are listed in the attachment.

• On June 3, 2013, door 1A101 located on the 93 foot elevation of the auxiliary building.

These activities constitute completion of one flood protection measures inspection sample as defined in Inspection Procedure 71111.06-05.

b. Findings

No findings were identified.

1R07 Heat Sink Performance

a. Inspection Scope

The inspectors reviewed licensee programs, verified performance against industry standards, and reviewed critical operating parameters and maintenance records for the division 1 diesel generator jackwater heat exchanger. The inspectors verified that performance tests were satisfactorily conducted for heat exchangers/heat sinks and reviewed for problems or errors; the licensee utilized the periodic maintenance method outlined in EPRI Report NP 7552, Heat Exchanger Performance Monitoring Guidelines; the licensee properly utilized biofouling controls; the licensees heat exchanger inspections adequately assessed the state of cleanliness of their tubes; and the heat exchanger was correctly categorized under 10 CFR 50.65, Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants. Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of one heat sink inspection sample, as defined in Inspection Procedure 71111.07-05.

b. Findings

No findings were identified.

1R11 Licensed Operator Requalification Program and Licensed Operator Performance

.1 Quarterly Review of Licensed Operator Requalification Program

a. Inspection Scope

On April 8, 2013, the inspectors observed a crew of licensed operators in the plants simulator during requalification testing. The inspectors assessed the following areas:

• Licensed operator performance

• The ability of the licensee to administer the evaluations

• The modeling and performance of the control room simulator

• The quality of post-scenario critiques These activities constitute completion of one quarterly licensed operator requalification program sample, as defined in Inspection Procedure 71111.11.

b. Findings

No findings were identified.

.2 Quarterly Observation of Licensed Operator Performance

a. Inspection Scope

On June 24, 2013, the inspectors observed the performance of on-shift licensed operators in the plants main control room. At the time of the observations, the plant was in a period of heightened activity due to a scheduled down power to 65 percent reactor thermal power. The inspectors observed the operators performance of the following activities:

• Pre-job brief

• Power reduction by reducing core flow

• Power reduction by inserting control rods

• Minimization of control room distractions

• Operators response to control room annuciators 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 one quarterly licensed-operator performance sample, as defined in Inspection Procedure 71111.11.

b. Findings

No findings were identified.

1R12 Maintenance Effectiveness

a. Inspection Scope

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

• Nuclear boiler system (B21)

• Standby liquid control system (C41)

The inspectors reviewed events such as where ineffective equipment maintenance has resulted in valid 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)

• Characterizing system reliability issues for performance

• Charging unavailability for performance

• Trending key parameters for condition monitoring

• Ensuring proper classification in accordance with 10 CFR 50.65(a)(1) or -(a)(2)

• Verifying appropriate performance criteria for structures, systems, and components classified as having an adequate demonstration of performance through preventive maintenance, as described in 10 CFR 50.65(a)(2), or as requiring the establishment of appropriate and adequate goals and corrective actions for systems classified as not having adequate performance, as described in 10 CFR 50.65(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 corrective action program with the appropriate significance characterization. Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of two maintenance effectiveness samples, as defined in Inspection Procedure 71111.12-05.

b. Findings

No findings were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

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

• Week of April 15, 2013, during maintenance in the switchyard

• Week of April 29, 2013, during division 1 diesel generator allowed outage time

• On May 21, 2013, with the division 2 diesel generator out of service and emergent severe weather resulting in the site going to orange risk

• Week of June 24, 2013, during scheduled down power to 65 percent reactor thermal power The inspectors selected these activities based on potential risk significance relative to the reactor safety cornerstones. As applicable for each activity, the inspectors verified that licensee personnel performed risk assessments as required by 10 CFR 50.65(a)(4)and that the assessments were accurate and complete. When licensee personnel performed emergent work, the inspectors verified that the licensee personnel promptly assessed and managed plant risk. 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 the technical specification requirements and inspected portions of redundant safety systems, when applicable, to verify risk analysis assumptions were valid and applicable requirements were met. Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of four maintenance risk assessments and emergent work control inspection samples, as defined in Inspection Procedure 71111.13-05.

b. Findings

No findings were identified.

1R15 Operability Evaluations and Functionality Assessments

a. Inspection Scope

The inspectors reviewed the following assessments:

• Standby service water siphon line low flow, Condition Report CR-GGN-2013-02201

• Reactor protection system motor generator set error calulation, Condition Report CR-GGN-2013-02594

• Division 2 diesel generator field circuit diode failure, Condition Report CR-GGN-2013-03423

• Division 2 diesel generator fuel oil tank overfill, Condition Report CR-GGN-2013-03703 The inspectors selected these operability and functionality assessments based on the risk significance of the associated components and systems. The inspectors evaluated the technical adequacy of the evaluations to ensure technical specification operability was properly justified and to verify 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 technical specifications and Updated Final Safety Analysis Report 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. Additionally, the inspectors reviewed a sampling of corrective action documents to verify that the licensee was identifying and correcting any deficiencies associated with operability evaluations.

Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of four operability evaluations inspection samples, as defined in Inspection Procedure 71111.15-05.

b. Findings

No findings were identified.

1R17 Evaluations of Changes, Tests, and Experiments and Permanent Plant

Modifications (71111.17)

.1 Evaluations of Changes, Tests, and Experiments

a. Inspection Scope

The inspectors reviewed eight evaluations to determine whether the changes to the facility or procedures, as described in the Updated Final Safety Analysis Report, had been reviewed and documented in accordance with 10 CFR 50.59 requirements. The inspectors verified that when changes, tests, or experiments were made, evaluations were performed in accordance with 10 CFR 50.59 and licensee personnel had appropriately concluded that the change, test, or experiment could be accomplished without obtaining a license amendment. The inspectors also verified that safety issues related to the changes, tests, or experiments were resolved. The inspectors compared the safety evaluations and supporting documents to the guidance and methods provided in the Nuclear Energy Institute (NEI) 96-07, "Guidelines for 10 CFR 50.59 Implementation," as endorsed by NRC Regulatory Guide 1.187, Guidance for Implementation of 10 CFR 50.59, Changes, Tests, and Experiments," to determine the adequacy of the safety evaluations.

The inspectors reviewed 16 samples of changes, tests, and experiments that licensee personnel determined did not require evaluations and verified that the licensee personnels conclusions were correct and consistent with 10 CFR 50.59.

The inspectors also verified that calculations, analyses, design change documentation, procedures, the Updated Final Safety Analysis Report, the Technical Specifications, and plant drawings used to support the changes were accurate after the changes had been made. Documents reviewed are listed in the attachment.

These activities constitute completion of eight samples of evaluations and 16 samples of changes, tests, and experiments that were screened out by licensee personnel as defined in Inspection Procedure 71111.17-04.

b. Findings

(1) Failure to Revise Figures and Tables in the Updated Final Safety Analysis Report

Introduction.

The inspectors identified a Severity Level IV non-cited violation with three examples for the licensees failure to update the Updated Final Safety Analysis Report in accordance with 10 CFR 50.71(e)(4). Specifically, the licensee failed to update:

(1) Figure 9.2-027, Sheet 2, Revision 16 Plant Service Water Radial Well System Unit 1

(2) Figure 10.4-011, Condensate System (Drawing M-1053B, Revision 28), and

(3) Table 9.1-12, Maximum Fuel Pool Heat Load did not include values associated with the extended power uprate.

Description.

The inspectors reviewed the Updated Final Safety Analysis Report sections for the applicable modifications being inspected, and determined that the Updated Final Safety Analysis Report had not been adequately updated per the requirements of 10 CFR 50.71(e)(4). The inspectors identified three examples where the licensee had failed to update the Updated Final Safety Analysis Report within the 2-year time requirement.

• On January 6, 2010, the licensee updated Figure 9.2-027, Sheet 2, Revision 16, Plant Service Water Radial Well System Unit 1. The licensee made a required biennial Updated Final Safety Analysis Report update submittal in November 2012, in which Updated Final Safety Analysis Report, Figure 9.2-027, Sheet 2 maintained Revision 14, but it should have been updated for Revision 16. The licensee entered this issue into their corrective actions program as Condition Report CR-GGN-2013-00426.

• On April 5, 2011, the licensee completed Engineering Change EC-12421, which included an update to Figure 10.4-011, Condensate System, (Drawing M -1053B, Revision 28). The licensee made a required biennial Updated Final Safety Analysis Report update submittal in November 2012, in which Revision 28 of Figure 10.4-011 was not included. The licensee entered this issue into their corrective actions program as Condition Report CR-GGN-2013-02661.

• In 2011, the licensee completed installation of the new fuel pool cooling heat exchangers in preparation for the extended power uprate. TABLE 9.1-12, Maximum Fuel Pool Heat Load, page LDC 06045, was not updated to include values associated with the extended power uprate. The licensee entered this issue into their corrective actions program as Condition Report CR-GGN-2013-02471.

Analysis.

The failure of the licensee to include all changes made to the facility or procedures in their November 2012 update to the original revision of the Final Safety Analysis Report is a performance deficiency. The issue is a performance deficiency because it was a failure to meet requirement, 10 CFR 50.71(e)(4), and it was within the licensees ability to correct this problem. Using Inspection Manual Chapter 0612, Appendix B, the performance deficiency was assessed through both the Reactor Oversight Process and traditional enforcement because the finding had the potential for impacting the NRCs ability to perform its regulatory function. Screening the performance deficiency through the Reactor Oversight Process, the finding resulted in a minor performance deficiency. For traditional enforcement, the inspectors used NRC Enforcement Policy, dated January 28, 2013, to evaluate the significance of this violation. Consistent with the NRC Enforcement Policy, in accordance with Section 6.1.d.3, this finding was determined to be a Severity Level IV non-cited violation, because the licensee failed to update the Updated Final Safety Analysis Report as required by 10 CFR 50.71(e)(4), but the lack of up-to-date information did not result in any unacceptable change to the facility or procedures.

Enforcement.

Title 10 CFR 50.71(e)(4) requires that the Updated Final Safety Analysis Report be updated at intervals not exceeding 24 months, and states in part, the revisions must reflect all changes made in the facility or procedures described in the Updated Final Safety Analysis Report. Contrary to the above, a revision of the Updated Final Safety Analysis submitted by the licensee did not reflect all changes made in the facility or procedures described in the Final Safety Analysis Report. Specifically, the licensees Updated Final Safety Analysis Report submittal in November, 2012, did not include the following three changes to figures or tables:

(1) Figure 9.2-027, Sheet 2, Revision 16 Plant Service Water Radial Well System Unit 1

(2) Figure 10.4-011, Condensate System (Drawing M-1053B, Revision 28), and

(3) Table 9.1-12, Maximum Fuel Pool Heat Load did not include values associated with the extended power uprate.

This finding has been entered into the licensees corrective action program as Condition Reports CR-GGN-2013-00426, CR-GGN-2013-02661, and CR-GGN-2013-02471.

Because this finding is of very low safety significance, it is being treated as a Severity Level IV non-cited violation in accordance with Section 6.1.d.3 of the Enforcement Policy. (NCV 05000416/2013003-02, Failure to Revise Figures and Tables in the Updated Final Safety Analysis Report)

(2) Failure to Correct a Nonconforming Condition with the Standby Diesel Generator Inlet Plenum Turning Vanes

Introduction.

The inspectors identified a Green non-cited violation of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, involving the licensees failure to correct a nonconforming condition with the standby diesel generator inlet plenum turning vanes.

Description.

The division 1 and 2 standby diesel generators at Grand Gulf Nuclear Station automatically start in case of a loss of preferred power source and are used to supply standby power to division 1 and 2 safety-related equipment that is required to shut down the reactor, to maintain the reactor in a safe shutdown condition, and to mitigate the consequences of an accident. The diesel engine turbochargers use diesel exhaust as motive force to compress clean inlet air to the diesel engine for proper combustion. The turbocharger intercoolers cool the compressed air from the turbocharger prior to entering the engine by passing it over tubes that are cooled by jacket water. The intercooler plenum is the inlet to the cooler. The turning vane is a stationary vane that re-directs air as it enters the plenum.

Service Information Memo (SIM) 365, Stiffening the Shells of Intercooler Inlet Plenums, from the vendor, dated November 3, 1988, identified a design deficiency that could result in intercooler tube failure and jacket water leakage. Specifically, distortion of the shell area of the intercooler plenum caused cracking and air leakage around turbocharger air nozzles and a partial separation of the internal turning vane from the shell, which then caused an intercooler tube failure and water leakage. Therefore, the purpose of the SIM was to reinforce the intercooler inlet plenum to prevent shell distortion and intercooler tube failure. The SIM also provided drawings and specifications for the reinforcements.

From November 3, 1988, until March 3, 2010, the licensee partially implemented corrective actions to resolve SIM 365. Initially, the licensee inspected the inlet plenums and did not identify any distortion of the shell area on either the division 1 or 2 standby diesel generators. However, during a system outage in 2002, the licensee identified cracking on the division 2 left bank turning vane. Modifications were implemented in 2003 to repair and reinforce the left bank turning vane. At that time, the licensee discovered the right bank to have a different, more robust, design, and no modifications were performed. The licensee determined, with input from the vendor, that the modifications performed on the left bank turning vane fulfilled the intent of SIM 365. In 2010, Change Package EC 20207, implemented a modification to reinforce the division 1 left bank turning vane in order to match the division 2 left bank turning vane.

NRC Inspection Manual, Part 9900: Technical Guidance, Operability Determinations and Functionality Assessments for Resolution of Degraded or Nonconforming Conditions Adverse to Quality or Safety, defines nonconforming conditions as those in which quality has been reduced because of factors such as improper design, testing, construction, or modification. Operating experience that identifies a design inadequacy is an example of a nonconforming condition. The guidance also states, in part, that the licensee should establish a schedule for completing a corrective action when a structure, system, or component is determined to be nonconforming. Furthermore, if the licensee does not resolve the nonconforming condition at the first available opportunity or does not appropriately justify a longer completion schedule, the NRC staff would conclude that a corrective action had not been timely. The inspectors determined that the licensee had not appropriately justified a longer completion schedule because the licensee could not provide justification for not resolving the condition identified in the 1988 SIM or provide justification for not resolving the condition in all banks of both diesel generators around the same time. Finally, the inspectors determined that since the drawings and specifications were provided in the SIM by the vendor, no particular burden was placed upon the licensee to develop a design change package.

Analysis.

The failure to correct a nonconforming condition in the division 1 and 2 standby diesel generator inlet plenum turning vanes is a performance deficiency. The performance deficiency is more than minor and therefore a finding because it affected the Mitigating Systems Cornerstone attribute of equipment performance and affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage),and if left uncorrected, the performance deficiency had the potential to lead to a more significant safety concern. Specifically, the licensees failure to implement corrective actions to resolve a known design deficiency of the intercooler plenums could have resulted in either the division 1 or 2 standby diesel generator failing to perform its safety functions. Using Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, the finding was determined to be of very low safety significance (Green), because the finding was a design deficiency affecting a mitigating systems structure, system, or component that did not lose operability or functionality. The finding did not have a cross-cutting aspect because the most significant contributor to the performance deficiency did not reflect current licensee performance.

Enforcement.

Title 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, states, in part, that Measures shall be established to assure that conditions adverse to quality, such as failures, malfunctions, deficiencies, deviations, defective material and equipment, and non-conformances, are promptly identified and corrected. Contrary to the above, measures established by the licensee did not ensure that a condition adverse to quality was promptly identified and corrected. Specifically, from November 3, 1988, until March 6, 2010, the licensee did not fully implement actions to correct known design deficiencies on the left and right banks of the intercooler inlet plenums of both the division 1 and 2 standby diesel generators. This finding was entered into the licensees corrective action program as Condition Report CR-GGN-2013-02631. Because this finding is of very low safety significance and has been entered into the licensees corrective action program, this violation is being treated as a Green non-cited violation in accordance with Section 2.3.2 of the Enforcement Policy. (NCV 05000416/2013003-03, Failure to Correct a Nonconforming Condition with the Standby Diesel Generator Inlet Plenum Turning Vanes)

(3) Failure to Correct a Nonconforming Condition in the Train B Starting Circuit

Introduction.

The inspectors identified a Green non-cited violation of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, involving the licensees failure to resolve a nonconforming condition in the division 1 and 2 standby diesel generator train B start circuits.

Description.

The division 1 and 2 standby diesel generators at Grand Gulf Nuclear Station automatically start in case of a loss of preferred power source and are used to supply standby power to division 1 and 2 safety-related equipment that is required to shut down the reactor, to maintain the reactor in a safe shutdown condition, and to mitigate the consequences of an accident.

NRC Information Notice (IN) 98-41, Spurious Shutdown of Emergency Diesel Generators from Design Oversight, dated November 20, 1998, identified recent inspection findings related to a design deficiency that leads to an automatic shutdown of the emergency diesel generator when the starting air supply pressure depletes. The licensee determined in 1998 that the design deficiency reported in the information notice was not applicable to Grand Gulf Nuclear Station. In 2005, the licensee determined that the issue needed to be revisited. Essentially, the start logic for the division 1 and 2 standby diesel generators employs two redundant start trains A and B. However, starting air trains A and B do not function identically during a loss-of-coolant accident (LOCA) run. Specifically, the train B start logic is configured such that automatic shutdowns that are required to be bypassed during a LOCA are re-activated if starting air pressure falls below 120 psig. As a result, if starting air pressure falls below 120 psig and the associated train A starting circuit fails, the diesel generator would have all automatic shutdown permissives active. This is considered a single point vulnerability for the train B starting air circuit. At that time, the licensee implemented Standing Order 2005-0004 (i.e., a compensatory measure) to maintain starting air pressure in the normal band. In 2012, Change Package EC 02202 corrected the train B start logic on both division 1 and 2 standby diesel generators.

NRC Inspection Manual Part 9900: Technical Guidance, Operability Determinations and Functionality Assessments for Resolution of Degraded or Nonconforming Conditions Adverse to Quality or Safety, defines nonconforming conditions as those in which quality has been reduced because of factors such as improper design, testing, construction, or modification. Operating experience that identifies a design inadequacy is an example of a nonconforming condition. The guidance also states, in part, that the licensee should establish a schedule for completing a corrective action when a structure, system, or component is determined to be nonconforming. Furthermore, if the licensee does not resolve the nonconforming condition at the first available opportunity or does not appropriately justify a longer completion schedule, the staff would conclude that corrective action has not been timely. The inspectors determined that the licensee did not resolve the nonconforming condition at the first available opportunity since many system outages had taken place since the nonconforming condition was first identified to be applicable to Grand Gulf Nuclear Station. Finally, the NRC expects that conditions calling for compensatory measures to restore structure, system, or component operability will be more quickly resolved than conditions that do not rely on compensatory measures to restore operability; however, the inspectors also determined that the compensatory measures implemented did not affect the timing for resolution of the nonconforming condition.

Analysis.

The failure to correct a nonconforming condition in the division 1 and 2 standby diesel generator train B starting circuit is a performance deficiency. The performance deficiency is more than minor and therefore a finding because it affected the Mitigating Systems Cornerstone attribute of equipment performance and affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage),and if left uncorrected, the performance deficiency had the potential to lead to a more significant safety concern. Specifically, the licensees failure to implement corrective actions to resolve a known nonconforming condition of the low pressure interlock of the train B starting circuit could have resulted in either the division 1 or 2 standby diesel generator failing to perform its safety function. Using Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, the finding was determined to be of very low safety significance (Green), because the finding was a design deficiency affecting a mitigating systems structure, system, or component that did not lose operability or functionality. The finding did not have a cross-cutting aspect because the most significant contributor to the performance deficiency did not reflect current licensee performance.

Enforcement.

Title 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, states, in part, that Measures shall be established to assure that conditions adverse to quality, such as failures, malfunctions, deficiencies, deviations, defective material and equipment, and non-conformances, are promptly identified and corrected. Contrary to the above, measures established by the licensee did not ensure that a condition adverse to quality was promptly identified and corrected. Specifically, from November 20, 1998, until November 7, 2012, the licensee did not fully implement actions to correct a known nonconforming condition involving the low-pressure interlock of the train B starting circuit on both the division 1 and 2 standby diesel generators. The finding was entered into the licensees corrective action program as Condition Report CR-GGN-2013-02524.

Because this finding is of very low safety significance and has been entered into the licensees corrective action program, this violation is being treated as a Green non-cited violation in accordance with Section 2.3.2 of the Enforcement Policy. (NCV 05000416/2013003-04, Failure to Correct a Nonconforming Condition in the Train B Starting Circuit)

.2 Permanent Plant Modifications

a. Inspection Scope

The team verified that calculations, analyses, design change documentation, procedures, the Updated Final Safety Analysis Report, the Technical Specifications, and plant drawings used to support the modifications were accurate after the modifications had been made. The team verified that modifications were consistent with the plants licensing and design bases. The team confirmed that revised calculations and analyses demonstrated that the modifications did not adversely impact plant safety. Additionally, the team interviewed design and system engineers to assess the adequacy of the modifications.

These activities constitute completion of eight samples of permanent plant modifications as defined in Inspection Procedure 71111.17-04, and specific documents reviewed during this inspection are listed in the attachment.

.2.1 Provide guidance for use of spiral wound gaskets

The team reviewed Engineering Change EC 0000018694, which was implemented to analyze the use of spiral wound gaskets (SWG). Spiral wound gaskets are preformed gaskets consisting of a V-shaped spiral wound sealing element, a metal outer ring, and in some styles, a metal inner ring. The spiral wound gaskets function is to provide a seal in mechanical joints subjected to extremes in temperature and pressure cycling, vibration, and joint movement. There are two basic types of spiral wound gaskets used by the industry for ASME/ANSI B16.5 series flanges. Section 3.2.5 of ASME/ANSI B16.20 provides guidance for spiral wound gaskets with the metal inner ring. ASME/ANSI B16.20 provides guidance for applications where spiral wound gaskets with the metal inner ring is Required, Recommended, and Not Recommended.

Style CGI gaskets are manufactured to meet design requirements for spiral wound gaskets with outer and inner ring design. Style CGI gaskets are manufactured to meet the requirements of ASME Specification B16.20. The spiral wound sealing material used in Style CGI gaskets should be nuclear-grade flexible graphite. Graphite is a nonpolymer material that meets chemical restrictions for Boiling Water Reactor (BWR)systems containing primary reactor coolant and Pressuized Water Reactor (PWR)systems containing secondary reactor coolant. The standard material for the metal rings used in most BWR and PWR applications is stainless steel (304 or 316L). However, Inconnel X-750 is recommended in applications above 750°F where gaskets are subject to vibration and flange movement.

.2.2 Evaluate whip restraint PBR-RHR-1A for Condition Report CR-2010-02271

The team reviewed Engineering Change EC 0000021436, which was implemented to evaluate the whip restraint for hanger PBR-RHR-1A. Condition Report CR-GGN-2010-02271 noted that Calculation C-G-561.6, used a thrust coefficient of 1 instead of 1.26 and brings into question the adequacy of whip restraint PBR-RHR-1A. The change package required that an evaluation be performed to provide reasonable assurance that whip restraint PBR-RHR-1A would be capable of performing its intended design function.

residual heat removal (RHR) whip restraint PBR-RHR-1A is a six loop 1.25-inch diameter whip restraint. The design of the whip restraint was evaluated by Bechtel Calculation C-G-561.6.

During power uprate a perceived error was discovered in this calculation in that a thrust coefficient of 1.26 was not applied in the calculation. This resulted in the evaluation using what appeared to be an inadequate load when evaluating the whip restraint. The RHR restraint is on a 20-inch pipe with a pressure of 1060 psia. The application of a thrust factor is required by Design for Pipe Break Effects (BN-TOP-2). A thrust factor of 1.26 is used for saturated steam, water, and steam-water mixtures. A thrust factor of 2.00 is used for sub-cooled non flashing water unless justified otherwise. Upon further review, it was discovered that Calculation C-G-561.6, was correct as originally prepared. The factor of 1.26 was applied to account for loads imposed upon the jet on the opposite side of the break. In this case, the line downstream of the break is isolated, and there is no accumulator to blow down. Therefore, there would be no jet to impose additional loads on the whip restraint. As a result, there is no requirement to use a thrust factor of 1.26 and there was no nonconformance with Calculation C-G-561.6.

.2.3 Reduction of inspection requirements on recirculation inlet and outlet (N1 and N2)

nozzles The team reviewed Engineering Change EC 0000025204 LO-OLG-2010-0157 CA 2, which was implemented to evaluate the reduction of nozzle inservice inspections. The Boiling Water Reactor Vessel and Internals Project (BWRVIP) Report BWRVIP-108, is the technical-basis document for ASME Code Case N-702, regarding reduction of the inspection of reactor pressure vessel (RPV) nozzle-to-vessel shell welds and nozzle inner radius areas from 100 percent to 25 percent of the nozzles for each nozzle type every 10 years. In order to reference the BWRVIP-108 report as the technical basis for the use of ASME Code Case N-702, as an alternative to ASME Code Section XI requirements, the plant specific applicability of BWRVIP-108 must be shown. The components identified are the reactor vessel nozzles N1 and N2. These are the recirculation system inlet and outlet nozzles from the reactor vessel. These components are part of the reactor vessel pressure boundary. The nozzles perform a pressure boundary function in order for the reactor vessel to perform a power generation function.

The reactor vessel performs a safety function of providing a barrier to the fuel during a Design Basis Accident (DBA).

.2.4 Revise the minimum required stem thrust Calculation MC-Q1111-91132 and MS-25

based on the results of Engineering Change EC 26284 The team reviewed Engineering Change EC 00000028897 per Engineering Report GGNS-EP-10-00001, Rev. 0 (reference EC 26284), that was implemented to evaluate the valve factor for several GL89-10 Program motor operated valves. The increase in valve factor allows the motor operated valves to be considered Category A or B valves in the Joint Owners Group Periodic Verification (PV) Program, thus allowing the licensee to continue to perform static diagnostic testing in lieu of dynamic testing. The change to the valve factor for those affected motor operated valves requires that the minimum required stem thrust be re-calculated in Calculation MC-Q1111-91132. Since the minimum required stem thrust was being re-calculated, Standard MS-25 needed to be revised to reflect the new values and the setup of each affected motor operated valve.

The motor operated valves needed to be evaluated against the new minimum required stem thrust to ensure that each motor operated valve would perform its safety function as setup per Engineering Report GGNS-EP-10-00001, Rev. 0 (reference EC 26284).

.2.5 Evaluation of division 2 diesel

The team reviewed Engineering Change EC 0000020409, which was implemented to evaluate the structural integrity of the rocker arm sub-cover for the 1P75E001B standby diesel generator. Condition Report CR-GGN-2010-01397, identified abnormalities in the right bank 2, left bank 2, and left bank 8 rocker arm sub-covers during a liquid penetrant examination. The design basis of the standby diesel generator system is to provide a backup source of electrical power to emergency core cooling system equipment in case of a loss-of-coolant-accident (LOCA) and/or a loss of offsite power. The team also reviewed Condition Report CR-GGN-2010-01397, Service Information Memo 372, Removal of Spring Pins from R4 Subcover Assemblies, and Engineering Report Number GGNS-01-0001, Attachment A, Subcover/Rocker Arm Machines Surface Inspection (Division 1 Only), and Subcover/Rocker Liquid Penetrant Inspection (Divisions 1 and 2).

.2.6 Emergency core cooling systems vent timing for HPCS, LPCS, RHR A, RHR B, and

RHR C The team reviewed Engineering Change EC 00000020644, which was implemented to determine the basis for the minimum time that venting can occur in emergency core cooling systems (ECCSs) and to update these criteria in venting surveillance procedures. The emergency core cooling systems are required to be full of water; however, the original venting criteria for each of the emergency core cooling systems subsystems had no basis. The design basis of the emergency core cooling systems is to provide protection against postulated loss-of-coolant-accidents (LOCA) caused by ruptures in primary system piping. Functionally, the system consists of four subsystems or operating modes, which are the low pressure core injection (LPCI), the high pressure core spray (HPCS), the automatic depressurization system (ADS), and the low pressure core spray (LPCS) subsystems. The inspectors reviewed Condition Report CR-GGN-2009-06249 and Condition Report CR-GGN-2010-01107, Work Order 52197987, Calculations MC-Q1111-10001, ECCS Vent Line Timing for ECCS Vent Valves, and MC-Q1111-12001, ECCS and RCIC Suction Line Dynamic Venting, and Procedure 06-OP-1E12-M-00001, LPCI/RHR Subsystem A Monthly Functional Test.

.2.7 Lonergan LCT-11 relief valve replacements

The team reviewed Engineering Change EC 0000000069, which was implemented to replace 26 existing Lonergan LCT-11 relief valves with new Crosby 900 OMNI-TRIM valves. The valves are ASME Section III Class 2 and 3 valves that provide thermal over pressure protection for various plant components and penetrations. The replacement valves setpoint pressures and design relieving capacities were not altered by this engineering change. The team reviewed seismic calculations as well as the vendor manual for the replacement valves to verify that the modification would not affect the safety design function of the relief valves. The individual valves were replaced by separate implementing engineering changes. The team selected valve 1E12F017C, a relief valve on the suction line for RHR jockey pump C, and reviewed Engineering Change EC 0000002109, which evaluated replacing this specific valve. The team reviewed design drawings and the work order package that replaced valve 1E12F017C to ensure installation of the new valve was in accordance with design.

.2.8 Evaluate the installation of replacement standby service water B pump motor

The team reviewed Engineering Change EC 0000039065, which was implemented to evaluate the installation of the refurbished standby service water (SSW) system B pump motor. The design basis function of the standby service water system is to remove heat from plant auxiliaries that are required for a safe reactor shutdown. The engineering change evaluated three discrepancies between the existing motor configuration and the replacement motor, including differences in space heater ratings, ground lug connections, and motor wiring. The team reviewed the work order that installed the new motor as well as the vendor manual for the motor to verify that the modification would not affect the safety design function of the standby service water system pump motor.

The team also reviewed Engineering Change EC 0000039577, which evaluated the use of a mobile crane to perform the required heavy lifts of the old and new motor. The team walked down the standby service water system B pump motor, including the ground lead connection and electrical terminal box to ensure installation of the modification was in accordance with design.

b. Findings

No findings were identified.

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:

• For division 1 standby service water inlet to diesel generator jacket water heat exchanger, P41F018A after maintenance

• For division 1 standby service water pump discharge valve, P41-F001A after maintenance

• For division 1 residual heat removal motor, E12C002A after maintenance

• For division 1 residual heat removal heat exchanger bypass valve, E12F048A after maintenance

• For division 1 residual heat removal heat minimum flow valve, E12F064A after maintenance

• For division 1 diesel generator after maintenance

• For division 1 standby service water pump after maintenance

• For division 2 safety switchgear ventilation dampers, Z77 after repair and maintenance The inspectors selected these activities based upon the structure, system, or component's ability to affect 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 The inspectors evaluated the activities against the technical specifications, the Updated Final Safety Analysis Report, 10 CFR Part 50 requirements, licensee procedures, and various NRC generic communications 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 being corrected commensurate with their importance to safety. Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of eight post-maintenance testing inspection samples, as defined in Inspection Procedure 71111.19-05.

b. Findings

No findings were identified.

1R22 Surveillance Testing

a. Inspection Scope

The inspectors reviewed the Updated Final Safety Analysis Report, procedure requirements, and technical specifications to ensure that the surveillance activities listed below demonstrated that the systems, structures, and/or components tested were capable of performing their intended safety functions. The inspectors either witnessed or reviewed test data to verify that the significant surveillance test attributes were adequate to address the following:

• Preconditioning

• Evaluation of testing impact on the plant

• Acceptance criteria

• Test equipment

• Procedures

• Jumper/lifted lead controls

• Test data

• Testing frequency and method demonstrated technical specification operability

• Test equipment removal

• Restoration of plant systems

• Fulfillment of ASME Code requirements

• Updating of performance indicator data

• Engineering evaluations, root causes, and bases for returning tested systems, structures, and components not meeting the test acceptance criteria were correct

• Reference setting data

• Annunciators and alarms setpoints The inspectors also verified that licensee personnel identified and implemented any needed corrective actions associated with the surveillance testing.

• April 7, 2013, turbine valve testing

• April 8, 2013, reactor coolant system unidentified leakage

• April 10, 2013, division 2 residual heat removal system monthly fill and vent

• April 23, 2013, turbine bypass valve testing

• April 24, 2013, division 2 diesel generator 24-hour run and quick restart Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of five surveillance testing inspection samples, as defined in Inspection Procedure 71111.22-05.

b. Findings

Introduction.

The inspectors identified a Green non-cited violation of Technical Specification Surveillance Requirement SR 3.5.1.1 for the failure to verify the residual heat removal B system was full of water within its specified frequency.

Description.

On April 23, 2013, the inspectors reviewed a low pressure core injection subsystem B monthly functional test that was performed on April 10, 2013, per Procedure 06-OP-1E12-M-0002, LPCI/RHR Subsystem B Monthly Functional Test, Revision 113. The inspectors identified that the licensee failed to perform ultra sonic testing on the pipe prior to and after venting of the pipe directly upstream of the residual heat removal heat exchanger B outboard vent valve (1E12F074B). When the inspectors asked why the ultra sonic testing was not performed, the licensee stated that no engineering support to perform the ultra sonic testing portion of the procedure was scheduled, and therefore operations believed it was not necessary to meet the intent of the procedure. Upon further review, the inspectors determined the ultra sonic testing requirements were incorporated in Revision 109 of the procedure per Engineering Change EC 31291, Calculate the vent timing for ECCS valves 1E12F073A(B) AND 1E12F074A(B). The engineering change specifies that ultra sonic testing would be necessary to meet the surveillance requirement of verifying the residual heat removal system is full of water because flow cannot be observed through the valves while being vented. By not performing the ultra sonic testing, the licensee did not verify the residual heat removal system was full of water as required by Surveillance Requirement 3.5.1.1.

On April 25, 2013, the inspectors informed the licensee of their concern. The licensee determined the last successful performance of SR 3.5.1.1 occurred on March 13, 2013, thus licensee missed the 39 day frequency requirement (31 days + 25 percent allowed by Technical Specifications). The licensee immediately entered Surveillance Requirement SR 3.0.3, for the failure to perform a surveillance within its specified frequency.

The licensee entered this issue into their corrective action program as Condition Report CR-GGN-2013-02847. Immediate corrective actions included performing the ultra sonic tests, which verified the system was full of water and satisfied the surveillance requirement.

Analysis.

The failure to verify the residual heat removal B system was full of water as required by Technical Specification Surveillance Requirement SR 3.5.1.1 is a performance deficiency. The performance deficiency is more than minor and therefore a finding because it is associated with the equipment performance attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstones objective of ensuring the availability, reliability and capability of systems that respond to prevent undesirable consequences. Specifically, the failure to perform the required ultra sonic testing resulted in Technical Specification Surveillance Requirement SR 3.5.1.1 not being met. Therefore, the licensee could not ensure the system would perform properly by injecting its full capacity into the reactor coolant system upon demand. Using NRC Inspection Manual Chapter 0609, Attachment 4, Initial Characterization of Findings, the inspectors determined that the issue affected the Mitigating Systems Cornerstone. In accordance with NRC Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) for Findings at Power, the inspectors determined that the issue had a very low safety significance (Green) because it was not a deficiency affecting the design or qualification of a mitigating system, structure, or component, does not represent a loss of system or function, does not represent a loss of function for greater than its technical specification allowed outage time, and does not represent a loss of function as defined by the licensees Maintenance Rule program for greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. Through interviews with operations personnel, the inspectors determined the apparent cause of the finding was that management failed to ensure the ultra sonic test was performed. Therefore the finding had a cross-cutting aspect in the human performance area associated with the work practices component because the licensee failed to ensure supervisory and management oversight of work activities H.4(c).

Enforcement.

Technical Specification 3.5.1.1 requires verification that each emergency core cooling subsystem piping is filled with water from the pump discharge valve to the injection valve within a frequency of 31 days plus 25 percent. Contrary to the above, verification that each emergency core cooling subsystem piping is filled with water from the pump discharge valve to the injection valve within a frequency of 31 days plus 25 percent was not accomplished. Specifically, Surveillance Procedure 06-OP-1E12-M-0002, LPCI/RHR Subsystem B Monthly Functional Test, Revision 113, requires an ultra sonic test be performed prior to and after venting of the pipe directly upstream of the residual heat removal heat exchanger B outboard vent valve (1E12F074B). On April 10, 2013, the licensee failed to perform the procedurally required ultra sonic testing. On April 25, 2013, the licensee restored compliance with the technical specification surveillance requirement by performing the ultra sonic tests. This violation is being treated as a non-cited violation, consistent with Section 2.3.2.a of the Enforcement Policy, because it was of very low safety significance (Green) and it was entered into the licensees corrective action program as Condition Report CR-GGN-2013-02847. (NCV 05000416/2013003-05, Failure to Verify the Residual Heat Removal B System was Full of Water Within its Specified Frequency)

1EP6 Drill Evaluation

.1 Training Observations

a. Inspection Scope

The inspectors observed a simulator training evolution for licensed operators on June 24, 2013, which required emergency plan implementation by a licensee operations crew. This evolution was planned to be evaluated and included in performance indicator data regarding drill and exercise performance. The inspectors observed event classification and notification activities performed by the crew. The inspectors also attended the postevolution critique for the scenario. The focus of the inspectors activities was to note any weaknesses and deficiencies in the crews performance and ensure that the licensee evaluators noted the same issues and entered them into the corrective action program. As part of the inspection, the inspectors reviewed the scenario package and other documents listed in the attachment.

These activities constitute completion of one training observation sample, as defined in Inspection Procedure 71114.06-05.

b. Findings

No findings were identified.

OTHER ACTIVITIES

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

4OA1 Performance Indicator Verification

.1 Data Submission Issue

a. Inspection Scope

The inspectors performed a review of the performance indicator data submitted by the licensee for the first Quarter 2013 performance indicators for any obvious inconsistencies prior to its public release in accordance with Inspection Manual Chapter 0608, Performance Indicator Program.

This review was performed as part of the inspectors normal plant status activities and, as such, did not constitute a separate inspection sample.

b. Findings

No findings were identified.

.2 Safety System Functional Failures (MS05)

a. Inspection Scope

The inspectors sampled licensee submittals for the safety system functional failures performance indicator for the period from the second quarter 2012 through the first quarter 2013. To determine the accuracy of the performance indicator data reported during those periods, the inspectors used definitions and guidance contained in NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6, and NUREG-1022, Event Reporting Guidelines 10 CFR 50.72 and 50.73."

The inspectors reviewed the licensees operator narrative logs, operability assessments, maintenance rule records, maintenance work orders, issue reports, event reports, and NRC integrated inspection reports for the period of April 2012 through March 2013 to validate the accuracy of the submittals. The inspectors also reviewed the licensees condition report database to determine if any problems had been identified with the performance indicator data collected or transmitted for this indicator and none were identified. Specific documents reviewed are described in the attachment to this report.

These activities constitute completion of one safety system functional failures sample, as defined in Inspection Procedure 71151-05.

b. Findings

No findings were identified.

.3 Reactor Coolant System Specific Activity (BI01)

a. Inspection Scope

The inspectors sampled licensee submittals for the reactor coolant system specific activity performance indicator from the second quarter 2012 through the first quarter 2013. To determine the accuracy of the performance indicator data reported during those periods, the inspectors used definitions and guidance contained in NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6. The inspectors reviewed the licensees reactor coolant system chemistry samples, technical specification requirements, issue reports, event reports, and NRC integrated inspection reports for the period of April 2012 through March 2013 to validate the accuracy of the submittals. The inspectors also reviewed the licensees condition report database to determine if any problems had been identified with the performance indicator data collected or transmitted for this indicator and none were identified. In addition to record reviews, the inspectors observed a chemistry technician obtain and analyze a reactor coolant system sample. Specific documents reviewed are described in the attachment to this report.

These activities constitute completion of one reactor coolant system specific activity sample, as defined in Inspection Procedure 71151-05.

b. Findings

No findings were identified.

.4 Reactor Coolant System Leakage (BI02)

a. Inspection Scope

The inspectors sampled licensee submittals for the reactor coolant system leakage performance indicator from the second quarter 2012 through the first quarter 2013. To determine the accuracy of the performance indicator data reported during those periods, the inspectors used definitions and guidance contained in NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6. The inspectors reviewed the licensees operator logs, reactor coolant system leakage tracking data, issue reports, event reports, and NRC integrated inspection reports for the period of April 2012 through March 2013 to validate the accuracy of the submittals. The inspectors also reviewed the licensees condition report database to determine if any problems had been identified with the performance indicator data collected or transmitted for this indicator and none were identified. Specific documents reviewed are described in the attachment to this report.

These activities constitute completion of one reactor coolant system leakage sample, as defined in Inspection Procedure 71151-05.

b. Findings

No findings were identified.

4OA2 Problem Identification and Resolution

.1 Routine Review of Identification and Resolution of Problems

a. Inspection Scope

As part of the various baseline inspection procedures discussed in previous sections of this report, the inspectors routinely reviewed issues during baseline inspection activities and plant status reviews to verify that they were being entered into the licensees corrective action program at an appropriate threshold, that adequate attention was being given to timely corrective actions, and that adverse trends were identified and addressed. The inspectors reviewed attributes that included the complete and accurate identification of the problem; the timely correction, commensurate with the safety significance; the evaluation and disposition of performance issues, generic implications, common causes, contributing factors, root causes, extent of condition reviews, and previous occurrences reviews; and the classification, prioritization, focus, and timeliness of corrective actions. Minor issues entered into the licensees corrective action program because of the inspectors observations are included in the attached list of documents reviewed.

These routine reviews for the identification and resolution of problems did not constitute any additional inspection samples. Instead, by procedure, they were considered an integral part of the inspections performed during the quarter and documented in Section 1 of this report.

b. Findings

No findings were identified.

.2 Daily Corrective Action Program Reviews

a. Inspection Scope

In order to assist with the identification of repetitive equipment failures and specific human performance issues for follow-up, the inspectors performed a daily screening of items entered into the licensees corrective action program. The inspectors accomplished this through review of the stations daily corrective action documents.

The inspectors performed these daily reviews as part of their daily plant status monitoring activities and, as such, did not constitute any separate inspection samples.

b. Findings

No findings were identified.

.3 Selected Issue Follow-up Inspection: Test Program for 125 Vdc Safety-Related Molded

Case Circuit Breakers and 4160 Vac Circuit Breakers

a. Inspection Scope

The inspectors chose to review Condition Reports CR-GGN-2012-08885, CR-GGN-2012-09035, CR-GGN-2012-09111, CR-GGN-2012-09030, and CR-GGN-2012-09175. These condition reports addressed programmatic conditions associated with 125 Vdc safety related molded case circuit breakers and 4160 Vac circuit breakers. These conditions were due to the licensees failure to establish a test program for 125 Vdc safety-related molded case circuit breakers that incorporated the requirements of IEEE 308, to ensure the breakers would not degrade and would perform satisfactorily in service and for the licensees failure to incorporate into their 4160 Vac maintenance program inspections and test requirements for minimum voltage tests, reduced voltage tests, and inspection of auxiliary switch relay contacts.

The inspectors reviewed the associated corrective actions for CR-GGN-2011-08885, CR-GGN-2012-09035, CR-GGN-2012-09111, CR-GGN-2012-09030, and CR-GGN-2012-09175. The inspectors also reviewed associated procedures and interviewed members of the involved licensee staff. Documents reviewed are listed in the attachment.

These activities constitute completion of one in-depth problem identification and resolution sample, as defined in Inspection Procedure 71152-05.

b. Findings

No findings were identified.

.4 Selected Issue Follow-up Inspection: Seismic Monitoring Equipment

a. Inspection Scope

The inspectors chose to review Condition Report CR-GGN-2013-00980, which addressed NRC information Notice IN 2012-25, Performance Issues with Seismic Instrumentation and Associated Systems for Operating Reactors. The inspectors reviewed the licensees evaluation of the items discussed in Information Notice 2012-25, and their applicability to the station. The inspectors also review several related condition reports, design documents, the Updated Final Safety Analysis Report, applicable regulatory guides, and interviewed members of the involved staff. Documents reviewed are listed in the attachment.

These activities constitute completion of one in-depth problem identification and resolution sample, as defined in Inspection Procedure 71152-05.

b. Findings

No findings were identified.

4OA3 Followup of Events and Notices of Enforcement Discretion

.1 Fire in Temporary Transformer Resulting in a Declaration of a Notice of Unusual Event

a. Inspection Scope

On May 12, 2013, the inspectors responded to the Grand Gulf Nuclear Station to observe recovery actions for a fire in a temporary transformer located inside the protected area. At 5:30 p.m. the control room was informed of smoke emanating from a temporary transformer located on the southeast side of the turbine building. The fire brigade was dispatched to the scene. The shift manager evaluated the emergency actions levels for a fire inside the protected area lasting longer than 15 minutes, and at 5:43 p.m., a notice of unusual event was declared. Plant personnel determined the transformer was receiving energy from the 115 KV switchyard and notified the Jackson transmission operations center to open breaker 5X02 to de-energize the transformer.

Once breaker 5X02 was opened, the fire brigade leader reported that smoke was no longer coming from the transformer. The fire was declared extinguished at 5:55 p.m.,

and the site exited the notice of unusual event at 7:21 p.m.

These activities constitute completion of one event follow-up as defined in Inspection Procedure 71153-05.

b. Findings

No findings were identified.

.2 Carbon Dioxide Release in a Division 2 Safety Related Switchgear Room Resulting in a

Declaration of a Notice of Unusual Event

a. Inspection Scope

On June 19, 2013, the inspectors responded to the Grand Gulf Nuclear Station control room to observe recovery actions for a release of carbon dioxide in room 1A207, which contains division 2 safety related switchgear. At 1:30 p.m. the control room received reports that carbon dioxide had been released in the switchgear room. Operators immediately dispatched, and using self-contained breathing apparatus, they entered the room to check for injured personnel and to determine if the release of carbon dioxide was due to a fire. The operators confirmed the carbon dioxide release and found no injured personnel and saw no evidence of a fire in the room. Upon receiving confirmation of the carbon dioxide release, the shift manager declared an unusual event due to the release of carbon dioxide into a room affecting normal plant operations.

Immediate actions taken by the licensee included isolating the auxiliary building from the carbon dioxide storage tank and utilizing smoke exhausters to disperse the carbon dioxide. At 4:28 p.m. the operators verified oxygen levels in the auxiliary building had returned to normal, and the plant exited the unusual event.

These activities constitute completion of one event follow-up as defined in Inspection Procedure 71153-05.

b. Findings

No findings identified.

4OA6 Meetings, Including Exit

Exit Meeting Summary

On April 18, 2013, the inspectors presented inspection results in section 1R17 to Mr.

K. Mulligan, Site Vice President, and other members of the licensees staff. The licensee acknowledged the results as presented. While some proprietary information was reviewed during this inspection, no proprietary information was included in this report.

On July 18, 2013, the inspectors presented the inspection results to Mr. K. Mulligan, Site Vice President, and other members of the licensee staff. The licensee acknowledged the issues presented. The inspector asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identified.

4OA7 Licensee-Identified Violations

None

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

A. Evans, Design Engineering, Tech Spec IV

C. Beschett, Manager, Nuclear Analyst

C. Perino, Director, NSA

C. Robinson, Manager, Licensing

C. Williams, Supervisor, Design Engineering

D. Wiles, Director, Engineering

G. Phillips, Supervisor, Design Engineering - Electrical/I&C

J. Gerard, Manager, Operations

J. Giles, Manager, Training

J. Hixson, Design Engineering, Tech Spec IV

J. Miller, General Manager, Plant Operations

K. Mulligan, Site Vice President

K. Robertson, Design Engineering, Engineer I

L. Justiniano, Supervisor, Design Engineering - Configuration Management

M. Runion, Manager, Maintenance

O. Chess, Design Engineering, Tech Spec IV

P. Mullins, Design Engineering, Sr. Engineer

R. Fuller, Design Engineering, Sr. Engineer

R. Miller, Manager, Radiation Protection

R. Scarbrough, Specialist and Lead Offsite Liaison, Licensing

R. Sumners, Systems Engineering, Engineer I

T. Thornton, Manager, Design Engineering

T. Thurmon, Supervisor, Design Engineering - Mechanical/Civil

NRC Personnel

R. Kopriva, Senior Reactor Inspector

Attachment

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened and Closed

05000416/2013003-01 NCV Failure to Properly Implement a Compensatory Fire Watch per Station Fire Protection Procedures (1R05.1.b)

05000416/2013003-02 NCV Failure to Revise Figures and Tables in the Updated Final Safety Analysis Report (1R17.1.b.1)

05000416/2013003-03 NCV Failure to Correct a Nonconforming Condition with the Standby Diesel Generator Inlet Plenum Turning Vanes (1R17.1.b.2)

05000416/2013003-04 NCV Failure to Correct a Nonconforming Condition in the Train B Starting Circuit (1R17.1.b.3)

05000416/2013003-05 NCV Failure to Verify the Residual Heat Removal B System was Full of Water Within its Specified Frequency (1R22.b)