IR 05000416/2011005

IR 05000416-11-005, on 09/28/2011 - 12/31/2011, Grand Gulf Nuclear Station

ML120330608
Person / Time
Site:	Grand Gulf
Issue date:	02/02/2012
From:	Vincent Gaddy NRC/RGN-IV/DRP/RPB-C
To:	Mike Perito Entergy Operations
References
IR-11-005
Download: ML120330608 (61)

Text

UNITED STATES NUCLEAR REGULATORY COMMISSION REGION I V 1600 EAST LAMAR BLVD ARLINGTON, TEXAS 76011-4511 February 2, 2012 Mike Perito Vice President Operations Entergy Operations, Inc.

Grand Gulf Nuclear Station P.O. Box 756 Port Gibson, MS 39150 Subject: GRAND GULF - NRC INTEGRATED INSPECTION REPORT NUMBER 05000416/2011005

Dear Mr. Perito:

On December 31, 2011, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Grand Gulf Nuclear Station Unit 1. The enclosed inspection report documents the inspection results which were discussed on January 10, 2012, 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.

One NRC identified finding of very low safety significance (Green) was identified during this inspection. This finding was determined to involve a violation of NRC requirements. The NRC is treating this violation as non-cited violation (NCV) consistent with Section 2.3.2 of the Enforcement Policy.

If you contest this non-cited violation, 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

Vice President of Operations - Mike Perito - 2 -

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/

Vincent Gaddy, Chief Project Branch C Division of Reactor Projects Docket No: 050000416 License No: NPF-29

Enclosure:

NRC Inspection Report 05000416/2011005 w/Attachment: Supplemental Information

REGION IV==

Docket: 05000416 License: NPF-29 Report: 05000416/2011005 Licensee: Entergy Operations, Inc.

Facility: Grand Gulf Nuclear Station Unit 1 Location: 7003 Baldhill Road Port Gibson, MS 39150 Dates: September 28, 2011, through December 31, 2011 Inspectors: R. Smith, Senior Resident Inspector B. Rice, Resident Inspector P. Elkmann, Senior Emergency Preparedness Inspector G. Guerra, CHP, Emergency Preparedness Inspector G. Schlapper, High Level Waste Inspector, Nuclear Materials Division W. Sifre, Senior Reactor Inspector Approved By: Vincent Gaddy, Chief Reactor Project Branch C Division of Reactor Projects-1- Enclosure

SUMMARY OF FINDINGS

IR 05000416/2011005; 09/28/2011 - 12/31/2011; Grand Gulf Nuclear Station, Integrated

Resident and Regional Report; Fire Protection.

The report covered a 3-month period of inspection by resident inspectors and announced baseline inspections by region-based inspectors. One Green non-cited violation of significance was 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 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 10 CFR 50 Appendix B,

Criterion V, Instructions, Procedures, and Drawings, for failure to perform an adequate inspection of probable maximum precipitation door seals protecting safety related equipment. Inspectors found that one of the door seals to standby service water pump house A was in a degraded condition. The inspectors identified that the door seal did not make complete contact with the door frame all the way around. The licensee determined that the probable maximum precipitation seal for the identified door was in a degraded condition. Failure of this door seal during a probable maximum precipitation event could potentially cause flooding of the standby service water pump house A. Immediate corrective actions included the site initiating compensatory actions for the degraded seal by staging sand bags in the area and requiring monitoring of the affected door during heavy rainfall. The licensee entered this issue into the corrective action program as Condition Report CR-GGN-2011-07687.

The finding is more than minor because it is associated with the protection against external factors attribute of Mitigating System 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. In Inspection Manual Chapter 0609.04, Phase 1 - Initial Screening and Characterization of Findings, the inspectors used the seismic, flooding, and severe weather Table 4b and determined that it would not affect multiple trains of safety equipment and that the finding had very low safety significance (Green). This finding has a cross-cutting aspect in the area of human performance associated with the resources component in that the licensees procedure used for the inspection of the door seals did not take into account the status of the pump house ventilation system while performing the door seal inspection, and therefore, the licensee failed to make the required adjustments to the door seals resulting in their inspections of the probable maximum precipitation door seals being inadequate H.2(c) (Section 1R05).

Licensee-Identified Violations

None

REPORT DETAILS

Summary of Plant Status

Grand Gulf Nuclear Station Unit 1 began the inspection period at 96 percent rated thermal power. During the inspection period, the plant was limited to 96 percent power due to the isolation of the second-stage steam to both moisture separator reheaters A and B on January 9, 2011.

• On September 30, 2011, operators reduced power to 65 percent for a planned control rod sequence exchange, control rod friction testing, control rod testing, and turbine testing. The plant was returned to 96 percent power on October 5, 2011.

• On October 29, 2011, operators reduced power to 85 percent for a planned control rod testing. The plant was returned to 96 percent power on October 30, 2011.

• On November 10, 2011, the plant reduced power to 49 percent due to a trip of the reactor feedpump turbine B. While the plant was at a reduced power level, the site performed control rod friction testing. The plant was returned to 96 percent power on November 24, 2011, after performing required rod pattern adjustments during power accession.

• On November 25, 2011, operators reduced power to 46 percent due to a partial loss of plant service water. The plant was returned to 96 percent power on November 28, 2011.

• On December 17, 2011, operators reduced power to 64 percent for a planned control rod sequence exchange, control rod friction testing, control rod testing and turbine testing. The plant was returned to 96 percent power on December 18,

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity, and Emergency Preparedness

1R04 Equipment Alignments

.1 Partial Walkdown

a. Inspection Scope

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

• Division 2 combustible gas control system while the division 1 system was in an outage

• Low pressure core spray system following a quarterly functional test 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 two partial system walkdown samples as defined in Inspection Procedure 71111.04-05.

b. Findings

No findings were identified.

.2 Complete Walkdown

a. Inspection Scope

On November 17, 2011, the inspectors performed a complete system alignment inspection of the reactor core isolation cooling system to verify the functional capability of the system. The inspectors selected this system because it was considered both safety significant and risk significant in the licensees probabilistic risk assessment. The inspectors inspected the system to review mechanical and electrical equipment line ups, electrical power availability, system pressure and temperature indications, as appropriate, component labeling, component lubrication, component and equipment cooling, hangers and supports, operability of support systems, and to ensure that ancillary equipment or debris did not interfere with equipment operation. The inspectors reviewed a sample of past and outstanding work orders to determine whether any deficiencies significantly affected the system function. In addition, the inspectors reviewed the corrective action program database to ensure that system equipment-alignment problems were being identified and appropriately resolved. Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of one complete system walkdown sample 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:

• Standby service water A pump house and valve room (rooms 1M110 and 1M112)

• Standby service water B pump house and valve room (rooms 2M110 and 2M112)

• Yard electrical manholes (MH01, MH20 and MH21)

• Auxiliary building elevation 208 (1A431, 1A438, 1A532, 1A602, 1A603, and 1A604)

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 four 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 10 CFR 50 Appendix B, Criterion V, Instructions, Procedures, and Drawings, for failure to perform an adequate inspection of probable maximum precipitation door seals protecting safety related equipment.

Description.

During a quarterly fire inspection on October 24, 2011, inspectors found that one of the door seals to standby service water pump house A was in a degraded condition. The inspectors identified that the door seal did not make complete contact with the door frame all the way around. The inspectors notified plant personnel of their concerns, and the licensee performed an evaluation of the standby service water pump house A door seal. The licensee determined that the probable maximum precipitation seal for the identified door was in a degraded condition. Grand Gulf Nuclear Station previously performed the inspection of these door seals on October 10, 2011, with satisfactory results. When this inspection was conducted, the pump house ventilation was not in operation. The NRCs inspection was conducted while the ventilation was in service, and this changed the conditions in the room. Previous to the October 10th inspection, the licensee stated that one door seal in the room was adjusted while ventilation was in service, but the other doors seal was not adjusted under the same conditions. Failure of this door seal during a probable maximum precipitation event could potentially cause flooding of the standby service water pump house A. The licensee initiated compensatory actions for the degraded seal which included staging sand bags in the area and requiring monitoring of the affected door during heavy rainfall.

The licensee initiated a work order to replace the degraded seal on the door. They also revised operator rounds to perform inspections of all probable maximum precipitation doors protecting safely related equipment on a daily bases.

The licensee documented this issue in their corrective action program as Condition Report CR-GGN-2011-07687. Additionally, the licensee conducted a root cause evaluation to determine the cause of the failure of the seals and to put corrective actions in place to prevent recurrence.

Analysis.

The inspectors determined that the failure to properly inspect and repair door seals that protect safety related equipment from probable maximum precipitation is a performance deficiency. The finding is more than minor because it is associated with the protection against external factors attribute of Mitigating System 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. In Inspection Manual Chapter 0609.04, Phase 1 - Initial Screening and Characterization of Findings, the inspectors used the seismic, flooding, and severe weather Table 4b and determined that it would not affect multiple trains of safety equipment and that the finding had very low safety significance (Green). This finding has a cross-cutting aspect in the area of human performance associated with the resources component in that the licensees procedure used for the inspection of the door seals did not take into account the status of the pump house ventilation system while performing the door seal inspection, and therefore, the licensee failed to make the

required adjustments to the door seals resulting in their inspections of the probable maximum precipitation door seals being inadequate H.2(c).

Enforcement.

Title 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures and Drawings, states, in part, that activities affecting quality shall be accomplished in accordance with prescribed procedures. Contrary to the above, on or before October 24, 2011, activities affecting quality were not performed in accordance with prescribed procedures, in that the licensee failed to implement an adequate inspection of door seals protecting safety-related equipment as prescribed in Procedure 07-S-14-310, Inspection of Mechanical Seals on Doors, Revision 8. This finding has been entered into the licensees corrective action program as Condition Report CR-GGN-2011-07687.

Because the finding was determined to be of very low safety significance and was entered into the licensees corrective action program, this violation is being treated as a non-cited violation consistent with Section 2.3.2a of the NRC Enforcement Policy: NCV 05000416/2011005-01, Failure to Perform an Adequate Inspection of Probable Maximum Precipitation Door Seals Protecting Safety Related Equipment.

.2 Annual Fire Protection Drill Observation

a. Inspection Scope

On December 4, 2011, the inspectors observed fire brigade activation due to a simulated fire in the upper cable spreading room of the control building. The inspectors evaluated the readiness of the plant fire brigade to fight fires. The inspectors verified that the licensee staff identified deficiencies; openly discussed them in a self-critical manner at the drill debrief, and took appropriate corrective actions. Specific attributes evaluated were

(1) proper wearing of turnout gear and self-contained breathing apparatus;

(2) proper use and layout of fire hoses;

(3) employment of appropriate fire fighting techniques;

(4) sufficient firefighting equipment brought to the scene;

(5) effectiveness of fire brigade leader communications, command, and control;

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

(7) smoke removal operations;

(8) utilization of preplanned strategies;

(9) adherence to the preplanned drill scenario; and

(10) drill objectives.

These activities constitute completion of one annual fire-protection inspection sample as defined in Inspection Procedure 71111.05-05.

b. Findings

No findings were identified.

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; reviewed the corrective action program to determine if licensee personnel identified and corrected

flooding problems; inspected underground bunkers/manholes to verify the adequacy of sump pumps, level alarm circuits, cable splices subject to submergence, and drainage for bunkers/manholes; and verified that operator actions for coping with flooding can reasonably achieve the desired outcomes. On November 28, 2011, the inspectors also inspected the areas listed below to verify the adequacy of equipment seals located below the flood line, floor and wall penetration seals, watertight door seals, common drain lines and sumps, sump pumps, level alarms, and control circuits, and temporary or removable flood barriers. Specific documents reviewed during this inspection are listed in the attachment.

• Low pressure core spray room

• Residual heat removal pump A, B, and C rooms

• Reactor core isolation cooling pump room

• High pressure core spray pump room 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.

1R11 Licensed Operator Requalification Program

a. Inspection Scope

On October 3, 2011, the inspectors observed a crew of licensed operators in the plants simulator to verify that operator performance was adequate, evaluators were identifying and documenting crew performance problems and training was being conducted in accordance with licensee procedures. The inspectors evaluated the following areas:

• Licensed operator performance

• Crews clarity and formality of communications

• Crews ability to take timely actions in the conservative direction

• Crews prioritization, interpretation, and verification of annunciator alarms

• Crews correct use and implementation of abnormal and emergency procedures

• Control board manipulations

• Oversight and direction from supervisors

• Crews ability to identify and implement appropriate technical specification actions and emergency plan actions and notifications The inspectors compared the crews performance in these areas to pre-established operator action expectations and successful critical task completion requirements.

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

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.

1R12 Maintenance Effectiveness

a. Inspection Scope

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

• Area radiation monitoring system (D21)

• Plant air system (P51)

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 quarterly 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:

• The week of October 2, 2011, during the station transformer 21 outage and lifting of piping near the sites main transformer, requiring the site to enter yellow risk condition

• The week of October 9, 2011, during the continuation of station transformer 21 outage due to emergent issues with the transformer bushings failing the insulating power factor test (DOBLE testing) and requiring replacement

• The week of November 12, 2011, during the recovery of the reactor feedpump turbine B following a trip on November 10, 2011, and during adverse weather in the area requiring the site to enter a yellow risk condition

• The week of December 12, 2011, during the division 3 allowed outage time requiring the site to enter a yellow risk condition 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

a. Inspection Scope

The inspectors reviewed the following issues:

• Standby liquid control initiation timing assumption, CR-GGN-2011-7620

• Control blade 56-41 operability retest, CR-GGN-2011-9165

• Standby service water C base plate repair, CR-GGN-2011-9033

• Division 1 and 2 diesel generator voltage regulator service life, CR-GGN-2011-2983

• Control room air conditioner A condenser divider plate degradation, CR-GGN-2011-8010 The inspectors selected these potential operability issues based on the risk significance of the associated components and systems. The inspectors evaluated the technical adequacy of the evaluations to ensure that technical specification operability was properly justified and the subject component or system remained available such that no unrecognized increase in risk occurred. The inspectors compared the operability and design criteria in the appropriate sections of the technical specifications and Updated Final Safety Analysis Report to the licensee personnels evaluations to determine whether the components or systems were operable. Where compensatory measures were required to maintain operability, the inspectors determined whether the measures in place would function as intended and were properly controlled. The inspectors determined, where appropriate, compliance with bounding limitations associated with the evaluations. Additionally, the inspectors also reviewed a sampling of corrective action documents to verify that the licensee was identifying and correcting any deficiencies

associated with operability evaluations. Specific documents reviewed during this inspection are listed in the attachment.

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

b. Findings

No findings were identified.

1R19 Postmaintenance Testing

a. Inspection Scope

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

• Engineering safety features transformer 21 following a planned outage

• Station transformer 21 following planned outage

• Standby service water system B fans C and D following scheduled maintenance outage

• Division 2 emergency diesel generator following scheduled maintenance

• Residual heat removal valve 1E12-F024B following scheduled maintenance

• Standby service water pump 1P41C002 following scheduled pump replacement 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 (as applicable):

• 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 postmaintenance 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 six postmaintenance 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.

• On October 13, 2011, engineering safety features transformer 21 deluge functional and full flow test

• On October 13 and 14, 2011, turbine building ventilation and standby gas treatment A leakage tests

• On November 2, 2011, division 2 emergency diesel generator functional test

• On November 6 and 7, 2011, residual heat removal system A quarterly inservice testing

• On November 17, 2011, control rod settle and frictions testing

• On November 29 - December 2, 2011 emergency core cooling division 3 testing Specific documents reviewed during this inspection are listed in the attachment.

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

b. Findings

No findings were identified.

1EP1 Exercise Evaluation

a. Inspection Scope

The inspectors reviewed the objectives and scenario for the 2011 biennial emergency plan exercise to determine if the exercise would acceptably test major elements of the emergency plan. The scenario simulated a loss of reactor feedwater, an unisolable leak of radioactive steam in the steam tunnel, a reactor coolant leak in the drywell, core damage following reactor pressure vessel water level below the top of active fuel, and a radiological release to the environment from the steam tunnel to demonstrate the licensee personnels capability to implement their emergency plan.

The inspectors evaluated exercise performance by focusing on the risk-significant activities of event classification, offsite notification, recognition of offsite dose consequences, and development of protective action recommendations, in the Control Room Simulator and the following dedicated emergency response facilities:

• Technical Support Center

• Operations Support Center

• Emergency Operations Facility The inspectors also assessed recognition of, and response to, abnormal and emergency plant conditions, the transfer of decision making authority and emergency function responsibilities between facilities, onsite and offsite communications, protection of emergency workers, emergency repair evaluation and capability, and overall implementation of the emergency plan to protect public health and safety and the environment. The inspectors reviewed the current revision of the facility emergency plan, emergency plan implementing procedures associated with operation of the licensees emergency response facilities, procedures for the performance of associated emergency functions, and other documents as listed in the attachment to this report.

The inspectors compared the observed exercise performance with the requirements in the facility emergency plan, 10 CFR 50.47(b), 10 CFR Part 50, Appendix E, and with the guidance in the emergency plan implementing procedures and other federal guidance.

The inspectors attended the post-exercise critiques in each emergency response facility to evaluate the initial licensee self-assessment of exercise performance. The inspectors also attended a subsequent formal presentation of critique items to plant management.

The specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of one sample as defined in Inspection Procedure 71114.01-05.

b. Findings

No findings were identified.

1EP4 Emergency Action Level and Emergency Plan Changes

a. Inspection Scope

The inspector performed an on-site review of Grand Gulf Nuclear Generating Station Emergency Plan, Revision 66, submitted by letter dated August 11, 2011. This revision, revised the emergency response organization callout method from a stand-alone Computer Notification System operated by the licensee to an offsite paging and telephone notification system operated and maintained by a vendor.

This revision was compared to its previous revision, to the criteria of NUREG-0654, Criteria for Preparation and Evaluation of Radiological Emergency Response Plans and Preparedness in Support of Nuclear Power Plants, Revision 1, to Nuclear Energy

Institute Report 99-01, Emergency Action Level Methodology, Revision 4, 5, and to the standards in 10 CFR 50.47(b) to determine if the revision adequately implemented the requirements of 10 CFR 50.54(q). This review was not documented in a safety evaluation report and did not constitute approval of licensee-generated changes; therefore, this revision is subject to future inspection. The specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of one sample as defined in Inspection Procedure 71114.04-05.

b. Findings

No findings were identified.

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 third quarter 2011 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.

.1 Mitigating Systems Performance Index - Emergency ac Power System (MS06)

a. Inspection Scope

The inspectors sampled licensee submittals for the mitigating systems performance index - emergency ac power system performance indicator for the period from the third quarter 2010 through the third quarter 2011. 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 narrative logs, mitigating systems performance index derivation reports, issue reports, event reports, and NRC integrated inspection reports for the period of July 2010 through September 2011 to validate the accuracy of the submittals. The inspectors reviewed the mitigating systems performance index component risk coefficient to determine if it had

changed by more than 25 percent in value since the previous inspection, and if so, that the change was in accordance with applicable NEI guidance. 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 mitigating systems performance index -

emergency ac power system sample as defined in Inspection Procedure 71151-05.

b. Findings

No findings were identified.

.2 Mitigating Systems Performance Index - High Pressure Injection Systems (MS07)

a. Inspection Scope

The inspectors sampled licensee submittals for the mitigating systems performance index - high pressure injection systems performance indicator for the period from the third quarter 2010 through the third quarter 2011. 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 narrative logs, mitigating systems performance index derivation reports, issue reports, event reports, and NRC integrated inspection reports for the period of July 2010 through September 2011 to validate the accuracy of the submittals. The inspectors reviewed the mitigating systems performance index component risk coefficient to determine if it had changed by more than 25 percent in value since the previous inspection, and if so, that the change was in accordance with applicable NEI guidance. 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 mitigating systems performance index -

high pressure injection system sample as defined in Inspection Procedure 71151-05.

b. Findings

No findings were identified.

.3 Mitigating Systems Performance Index - Heat Removal System (MS08)

a. Inspection Scope

The inspectors sampled licensee submittals for the mitigating systems performance index - heat removal system performance indicator for the period from the third quarter

2010 through the third quarter 2011. 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 narrative logs, mitigating systems performance index derivation reports, issue reports, event reports, and NRC integrated inspection reports for the period of July 2010 through September 2011 to validate the accuracy of the submittals. The inspectors reviewed the mitigating systems performance index component risk coefficient to determine if it had changed by more than 25 percent in value since the previous inspection, and if so, that the change was in accordance with applicable NEI guidance. 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 mitigating systems performance index -

heat removal system sample as defined in Inspection Procedure 71151-05.

b. Findings

No findings were identified.

.4 Mitigating Systems Performance Index - Residual Heat Removal System (MS09)

a. Inspection Scope

The inspectors sampled licensee submittals for the mitigating systems performance index - residual heat removal system performance indicator for the period from the third quarter 2010 through the third quarter 2011. 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 narrative logs, mitigating systems performance index derivation reports, issue reports, event reports, and NRC integrated inspection reports for the period of July 2010 through September 2011 to validate the accuracy of the submittals. The inspectors reviewed the mitigating systems performance index component risk coefficient to determine if it had changed by more than 25 percent in value since the previous inspection, and if so, that the change was in accordance with applicable NEI guidance. 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 mitigating systems performance index -

residual heat removal system sample as defined in Inspection Procedure 71151-05.

b. Findings

No findings were identified.

.5 Mitigating Systems Performance Index - Cooling Water Systems (MS10)

a. Inspection Scope

The inspectors sampled licensee submittals for the mitigating systems performance index - cooling water systems performance indicator for the period from the third quarter 2010 through the third quarter 2011. 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 narrative logs, mitigating systems performance index derivation reports, issue reports, event reports, and NRC integrated inspection reports for the period of July 2010 through September 2011 to validate the accuracy of the submittals. The inspectors reviewed the mitigating systems performance index component risk coefficient to determine if it had changed by more than 25 percent in value since the previous inspection, and if so, that the change was in accordance with applicable NEI guidance. 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 mitigating systems performance index -

cooling water system sample as defined in Inspection Procedure 71151-05.

b. Findings

No findings were identified.

.6 Drill/Exercise Performance (EP01)

a. Inspection Scope

The inspectors sampled licensee submittals for the Drill and Exercise Performance, performance indicator for the period October 2010 through September 2011. To determine the accuracy of the performance indicator data reported during those periods, performance indicator definitions and guidance contained in Nuclear Energy Institute Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revisions 5 and 6, were used. The inspectors reviewed the licensees records associated with the performance indicator to verify that the licensee accurately reported the indicator in accordance with relevant procedures and the Nuclear Energy Institute guidance.

Specifically, the inspectors reviewed licensee records and processes including procedural guidance on assessing opportunities for the performance indicator; assessments of performance indicator opportunities during predesignated control room simulator training sessions, performance during the 2011 biennial exercise, and

performance during other drills. The specific documents reviewed are described in the attachment to this report.

These activities constitute completion of the drill/exercise performance sample as defined in Inspection Procedure 71151-05.

b. Findings

No findings were identified.

.7 Emergency Response Organization Drill Participation (EP02)

a. Inspection Scope

The inspectors sampled licensee submittals for the Emergency Response Organization Drill Participation performance indicator for the period October 2010 through September 2011. To determine the accuracy of the performance indicator data reported during those periods, performance indicator definitions and guidance contained in Nuclear Energy Institute Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 5, was used. The inspectors reviewed the licensees records associated with the performance indicator to verify that the licensee accurately reported the indicator in accordance with relevant procedures and the Nuclear Energy Institute guidance. Specifically, the inspectors reviewed licensee records and processes including procedural guidance on assessing opportunities for the performance indicator, rosters of personnel assigned to key emergency response organization positions, and exercise participation records. The specific documents reviewed are described in the attachment to this report.

These activities constitute completion of the emergency response organization drill participation sample as defined in Inspection Procedure 71151-05.

b. Findings

No findings were identified.

.8 Alert and Notification System (EP03)

a. Inspection Scope

The inspectors sampled licensee submittals for the Alert and Notification System performance indicator for the period October 2010 through September 2011. To determine the accuracy of the performance indicator data reported during those periods, performance indicator definitions and guidance contained in Nuclear Energy Institute Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 5, was used. The inspectors reviewed the licensees records associated with the performance indicator to verify that the licensee accurately reported the indicator in accordance with relevant procedures and the Nuclear Energy Institute guidance.

Specifically, the inspectors reviewed licensee records and processes including

procedural guidance on assessing opportunities for the performance indicator and the results of periodic alert notification system operability tests. The specific documents reviewed are described in the attachment to this report.

These activities constitute completion of the alert and notification system sample as defined in Inspection Procedure 71151-05.

b. Findings

No findings were identified.

4OA2 Identification and Resolution of Problems

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

.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 Semi-Annual Trend Review

a. Inspection Scope

The inspectors performed a review of the licensees corrective action program and associated documents to identify trends that could indicate the existence of a more significant safety issue. The inspectors focused their review on repetitive equipment issues, but also considered the results of daily corrective action item screening discussed in Section 4OA2.2, above, licensee trending efforts, and licensee human performance results. The inspectors nominally considered the 6-month period of June 2011 through December 2011, although some examples expanded beyond those dates where the scope of the trend warranted.

The inspectors also included issues documented outside the normal corrective action program in major equipment problem lists, repetitive and/or rework maintenance lists, departmental problem/challenges lists, system health reports, quality assurance audit/surveillance reports, self-assessment reports, and Maintenance Rule assessments.

The inspectors compared and contrasted their results with the results contained in the licensees corrective action program trending reports. Corrective actions associated with a sample of the issues identified in the licensees trending reports were reviewed for adequacy.

These activities constitute completion of one single semi-annual trend inspection sample as defined in Inspection Procedure 71152-05.

b. Findings and Observations

No findings were identified.

The inspectors identified an increasing trend in condition reports identifying equipment failures affecting safety and non-safety related systems. The specific items documented in the condition reports were reviewed by the inspectors, and it was determined that 17

plant systems had been affected by failed equipment. These systems include plant air system, process radiation monitoring system, plant service water system, and reactor protection system. The equipment failures have resulted in various impacts on the plant including down powers and unplanned entries into limiting conditions of operation. The inspectors have already evaluated the down powers and limiting conditions of operations entries under other inspection samples for potential findings.

The licensee was aware of the decline in equipment reliability and has initiated corrective actions to improve equipment reliability by implementing preventative maintenance practices, performing system health evaluations, and employing a life cycle management program.

4OA3 Event Follow-up

.1 Hydrogen Leak at the Bulk Hydrogen Storage Facility

a. Inspection Scope

On October 19, 2011, the inspectors responded to the control room to observe operator response to a hydrogen leak at the bulk hydrogen storage facility. The main control room received the following alarm, H2 Storage Area Pump/Common Trouble/Power Loss, and dispatched operators to investigate. The control room supervisor contacted the Air Products vendor for assistance with the event. The responding operators found the A hydrogen compressor had tripped with the B compressor running. They also found a hydrogen leak on or near the outlet of the regulator for the main hydrogen tank.

Site safety was contacted, and upon their recommendations, access was restricted to the area. The licensees shift manger evaluated the emergency actions levels and determined that entry into an action level was not appropriate at the time due to location of the leak being outside the protected area, the size of the leak being from the valve packing, and the prevailing winds blowing the hydrogen gas away from the protected area. The inspectors observed control room actions and monitored the leak from site cameras. The hydrogen leak and the compressor A were repaired without incident by the vendor that day. Documents reviewed for this inspection are listed in the attachment.

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

b. Findings

No findings were identified.

.2 Trip of Reactor Water Cleanup Pump A due to Maintenance Technicians Working on the

Wrong Component

a. Inspection Scope

On October 25, 2011, the inspectors were briefed on a trip of the reactor water cleanup pump A due to instrument and control technicians performing maintenance on the wrong component. At 11:00 a.m. on October 25, 2011, the main control room received RWCU PUMP SUCT FLOW LOW and RWCU FILTER DMIN CONT TROUBLE alarms and a trip of reactor water cleanup pump A. Additionally, reactor water cleanup filter demineralizer A was lost. The operating crew responded to the alarms by entering their alarm response procedures and investigating the cause of the pump trip. The crew determined that instrument and control technicians assigned to perform scheduled maintenance on a train B solenoid valve instead performed scheduled maintenance on a train A solenoid valve, resulting in the trip of the pump A. The plant experienced a decrease in reactor power of approximately three megawatts thermal (0.05 percent) due to the trip of the reactor water cleanup pump A. The operating crew recovered the reactor water cleanup pump A after maintenance restored the solenoid valve on the train A. Inspectors reviewed logs, interviewed operators, and received additional briefings from the maintenance manager to determine what occurred and if proper recovery actions were taken. The maintenance manager also briefed the inspectors on future actions that would be taken to improve performance in the maintenance department.

Documents reviewed for this inspection are listed in the attachment.

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

b. Findings

No findings were identified.

.3 Trip of Drywell Chillers Following Offsite Grid Disturbance

a. Inspection Scope

b. On November 5, 2011, Grand Gulf Nuclear Station experienced a voltage spike from the electrical grid. The spike occurred due to the tripping and reclosing of two offsite 500 KV breakers. The voltage spike resulted in various control room annunciators and loss of the train A drywell chillers. In response to the loss of the train A drywell chillers, the train B drywell chillers auto started, but eventually tripped on high discharge pressure, which resulted in no trains of drywell chillers operating. The operators monitored the drywell temperature and containment steam tunnel temperatures in accordance with Technical Specification 3.6.5.5. The licensee determined the undervoltage relay for the train A drywell chillers had tripped due to the voltage spike but would not reset, thus preventing the chillers from operating. A priority one work order was authorized by the shift manager, which allowed the installation of a jumper to bypass the undervoltage relay.

Once the jumper was installed, the operators were able to restart the train A drywell chillers. At the end of the inspection the licensee was still troubleshooting the train B drywell chiller. The inspectors reviewed the licensees activities and determined that no technical specification limits had be exceeded and concluded that the licensees actions were appropriate for the safety significance of the drywell chiller system. Documents reviewed for this inspection are listed in the attachment.

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

c. Findings

No findings were identified.

.4 Trip of Reactor Feedpump Turbine B and Subsequent Downpower

a. Inspection Scope

On November 10, 2011, at 10:41 p.m. the Grand Gulf Nuclear Station experienced a trip of the reactor feedpump turbine B. This resulted in a flow control valve runback on the recirculation valve B. The recirculation flow control valve A failed to automatically runback and had to be manually runback by a reactor operator. Reactor water level decreased to 16 inches above instrument zero (183 inches above the top of active fuel)and was restored to normal level by the decrease in power to approximately 50 percent.

The inspectors responded to the plant and interfaced with licensee management to determine their plan of action to recover from the event. The licensee briefed the inspectors on their plans and the findings from their investigation. The licensee determined that the feedpump turbine had tripped due to a servo card fault, which was replaced. The failure of the recirculation flow control valve A to runback was attributed to a bad tachometer in the logic circuit. The tachometer was also replaced. The inspectors reviewed the results of the licensees failure mode analysis teams and determined the corrective actions were appropriate. On November 14, 2011, the licensee commenced a power increase and restored the reactor feedpump turbine B to operation during power increase. The inspectors monitored activities in the main control room during power ascension. Documents reviewed for this inspection are listed in the attachment.

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

b. Findings

No findings were identified.

.5 Partial Loss of Plant Service Water due to a Trip of the 18AG Bus

a. Inspection Scope

On November 25, 2011, at approximately 4:50 p.m. the Grand Gulf Nuclear Station experienced a partial loss of plant service water that cools non-safety related equipment at Grand Gulf Nuclear Station. The operations shift manager notified the inspectors that a power pole, which supplied power to the bus 28AG, had been damaged by a security truck striking the pole. As a result, the plant decided to split out non-safety related buses 28AG and 18AG, which were previously tied together to allow maintenance to perform inspections of the power supply cable to the bus 18AG. The site experienced a partial

loss of plant service water when the supply breaker to the bus 18AG closed, which resulted in the cross tie breaker between the 18AG and 28AG opening as expected.

Subsequently, the supply breaker to the bus 18AG unexpectedly reopened. This in turn resulted in a loss of power to three of the seven operating plant service water pumps.

The site subsequently reduced power to approximately 50 percent to align with the capacity of the remaining four plant service water pumps. The inspectors conducted numerous calls with the site through the night to understand plant conditions and responded to the site the next day to independently monitor activities. The inspectors reviewed the results of the licensees failure mode analysis team and determined the corrective actions were appropriate. The licensee concluded that the loss of the bus 18AG was due to either a failed relay in the supply breaker to the bus or a damaged cable that allowed operation of the supply breaker remotely from the main control room.

The site replaced the suspected relay and used an alternate method in their procedure to re-energize the bus 18AG locally and restart the tripped plant service water pumps.

Then the licensee crossed tied the bus 18AG with the bus 28AG and de-energized the bus 28AG to conduct replacement of the damaged power pole. The site increased power to 96 percent rated power. After the power pole was replaced on November 28, 2011, the site restored plant service water system to its normal electrical alignment of four pumps powered from 18AG and four pumps powered from 28AG. Documents reviewed for this inspection are listed in the attachment.

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

b. Findings

No findings were identified.

4OA5 Other Activities

(Closed) NRC Temporary Instruction (TI) 2515/177, Managing Gas Accumulation in Emergency Core Cooling, Decay Heat Removal, and Containment Spray Systems (NRC Generic Letter 2008-01)

a. Inspection Scope

The inspectors evaluated whether the licensee maintained documents, installed system hardware, and implemented actions that were consistent with the information provided in their response to NRC Generic Letter 2008-01, Managing Gas Accumulation in Emergency Core Cooling, Decay Heat Removal, and Containment Spray Systems.

Specifically, the inspectors verified that the licensee had implemented, or was in the process of implementing, the commitments, modifications, and programmatically controlled actions described in their response to Generic Letter 2008-01. The inspectors conducted their review in accordance with Temporary Instruction 2515/177 and considered the site-specific supplemental information provided by the Office of Nuclear Reactor Regulation (NRR) to the inspectors.

b. Inspection Documentation

The inspectors reviewed the licensing basis, design, testing, and corrective actions as specified in the temporary instruction. The specific items reviewed and any resulting observations are documented below.

Licensing Basis: The inspectors reviewed selected portions of licensing basis documents to verify that they were consistent with the NRR assessment report, and that the licensee properly processed any required changes. The inspectors reviewed selected portions of technical specifications, technical specification bases, and the Updated Final Safety Analysis Report. The inspectors also verified that applicable documents that described the plant and plant operation, such as calculations, piping and instrumentation diagrams, procedures, and corrective action program documents addressed the areas of concern and were updated, if needed, following plant changes.

The inspectors confirmed that the licensee performed surveillance tests at the frequency required by the technical specifications. The inspectors verified that the licensee tracked their commitment to evaluate and implement any changes that would be contained in the technical specification task force traveler.

Design: The inspectors reviewed selected design documents, performed system walkdowns, and interviewed plant personnel to verify that the licensee addressed design and operating characteristics. Specifically:

• The inspectors verified that the licensee had identified the applicable gas intrusion mechanisms for their plant.

• The inspectors verified that the licensee had established void acceptance criteria consistent with the void acceptance criteria identified by NRR. The inspectors also confirmed that the range of flow conditions evaluated by the licensee was consistent with the full range of design basis and expected flow rates for various break sizes and locations.

• The inspectors selectively reviewed applicable documents, including calculations, and engineering evaluations with respect to gas accumulation in the emergency core cooling systems and decay heat removal systems. Specifically, the inspectors verified that these documents addressed venting requirements, aspects where pipes were normally voided, void control during maintenance activities, and the potential for vortex effects that could ingest gas into the systems during design basis events.

• The inspectors verified that piping and instrumentation diagrams and isometric drawings describe up-to-date configurations of the emergency core cooling systems and decay heat removal systems. The review of the selected portions of isometric drawings considered the following:

High point vents were identified.

High points without vents were recognizable.

Other areas where gas could accumulate and potentially impact operability, such as at orifices in horizontal pipes, isolated branch lines, heat exchangers, improperly sloped piping, and under closed valves, were described in the drawings or in referenced documentation.

Horizontal pipe centerline elevation deviations and pipe slopes in nominally horizontal lines that exceeded specified criteria were identified.

All pipes and fittings were clearly shown.

The drawings were up-to-date with respect to recent hardware changes, and that any discrepancies between as-built configurations and the drawings were documented and entered into the corrective action program for resolution.

• The inspectors verified that the licensee had completed their walkdowns and selectively verified that the licensee identified discrepant conditions in their corrective action program and appropriately modified affected procedures and training documents.

Testing: The inspectors reviewed selected surveillances, post-modification tests, and post-maintenance test procedures and results, conducted during power and shutdown operations, to verify that the licensee was using procedures that appropriately addressed gas accumulation and/or intrusion into the subject systems. This review included the verification of procedures used for conducting surveillances and for the determination of void volumes to ensure that void criteria were satisfied and would continue to be satisfied until the next scheduled void surveillances. Also, the inspectors reviewed procedures used for filling and venting following conditions that could introduce voids into the subject systems to verify that the procedures adequately tested for such voids and provided adequate instructions for their reduction or elimination.

Corrective Actions: The inspectors reviewed selected corrective action program documents to assess how effectively the licensee addressed the issues associated with Generic Letter 2008-01 in their corrective action program. In addition, the inspectors verified that the licensee implemented appropriate corrective actions for issues identified in the nine-month and supplemental responses. The inspectors determined that the licensee had effectively implemented the actions required by Generic Letter 2008-01.

Based on this review, the inspectors concluded that there is reasonable assurance that the licensee will complete all outstanding items and incorporate this information into the design basis and operational practices. This temporary instruction is closed for Grand Gulf Nuclear Station.

c. Findings

No findings were identified.

4OA6 Meetings

Exit Meeting Summary

On November 3, 2011, the inspector presented the results of the onsite inspection of the licensees biennial emergency preparedness exercise to Mr. M. Richey, Director, Nuclear Safety Assurance, and other members of the licensees 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.

On December 9, 2011, the inspector presented the inspection results to Mr. D. Wiles, Engineering Director and other members of the licensee staff. The licensee acknowledged the issues presented. The inspector confirmed that none of the potential report input discussed was considered proprietary.

On January 10, 2012, the inspectors presented the inspection results to Mike Perito, Site Vice President Operations, 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.

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

J. Browning, General Plant Manager

J. Caery, Manager, Training

H. Farris, Assistant Operations Manager

P. Griffith, Supervisor, System Engineering

K. Higgenbotham, Manager, Planning and Scheduling

J. Houston, Manager, Maintenance

D. Jones, Manager, Design Engineering

C. Lewis, Manager, Emergency Preparedness

C. Loyd, Supervisor, Engineering

J. Miller, Manager, Operations

L. Patterson, Manager, Program Engineering

C. Perino, Manager, Licensing

M. Perito, Site Vice President of Operations

T. Reno, System Engineer

W. Renz, Corporate Director, Emergency Preparedness

M. Richey, Director, Nuclear Safety Assurance

R. Scarbrough, Specialist and Lead Offsite Liaison, Licensing

J. Seiter, Senior Licensing Specialist

J. Shaw, Manager, System Engineering

D. Wiles, Director, Engineering

R. Wilson, Manager, Quality Assurance

T. Trichell, Manager, Radiation Protection

R. Fuller, Design Engineer

NRC Personnel

R. Smith, Senior Resident Inspector

B. Rice, Resident Inspector

Attachment

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened and Closed

Failure to Perform an Adequate Inspection of Probable

05000416/2011005-01 NCV Maximum Precipitation Door Seals Protecting Safety Related Equipment (Section 1R05)

Closed

Managing Gas Accumulation in Emergency Core Cooling, TI 2515/177 TI Decay Heat Removal, and Containment Spray Systems (Section 4OA5)

Attachment