IR 05000416/2010002

NRC Integrated Inspection Report 05000416-10-002

ML101250383
Person / Time
Site:	Grand Gulf
Issue date:	05/04/2010
From:	Vincent Gaddy NRC/RGN-IV/DRP/RPB-C
To:	Douet J Entergy Operations
References
IR-10-002
Download: ML101250383 (59)

Text

UNITED STATES NU C LE AR RE G ULATO RY C O M M I S S I O N R E GI ON I V 612 EAST LAMAR BLVD , SU ITE 400 AR LIN GTON , TEXAS 76011-4125 May 4, 2010 James 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 05000416/2010002

Dear Mr. Douet:

On March 27, 2010, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Grand Gulf Nuclear Station. The enclosed integrated inspection report documents the inspection findings, which were discussed on April 12, 2010 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.

This report documents four self-revealing findings of very low safety significance (Green). Two of these findings were determined to involve violations of NRC requirements. Additionally, three licensee-identified violations, which were determined to be of very low safety significance, are listed in this report. However, because of the very low safety significance and because they are entered into your corrective action program, the NRC is treating these findings as a noncited violations, consistent with Section VI.A.1 of the NRC Enforcement Policy. If you contest the violations or the significance of the noncited violations, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, D.C. 20555-0001, with copies to the Regional Administrator, U.S. Nuclear Regulatory Commission, Region IV, 612 E.

Lamar Blvd, Suite 400, Arlington, Texas, 76011-4125; the Director, Office of Enforcement, U.S.

Nuclear Regulatory Commission, Washington, D.C. 20555-0001; and the NRC Resident Inspector at the Grand Gulf Nuclear Station facility. In addition, if you disagree with the characterization of any finding 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. The information you provide will be considered in accordance with Inspection Manual Chapter 0305.

Entergy Operations, Inc. -2-In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter, and its enclosure, will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records component of NRCs document 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: 50-416 License: NPF-29

Enclosure:

NRC Inspection Report 05000416/2010002 w/Attachment: Supplemental Information

REGION IV==

Docket: 05000416 License: NPF-29 Report: 05000416/2010002 Licensee: Entergy Operations, Inc.

Facility: Grand Gulf Nuclear Station Location: 7003 Baldhill Road Port Gibson, MS 39150 Dates: January 1 through March 27, 2010 Inspectors: R. Smith, Senior Resident Inspector A. Barrett, Resident Inspector Wayne Sifre, Senior Reactor Inspector Blake Rice, Reactor Inspector Matthew Young, Reactor Inspector Gilbert L. Guerra, CHP, Emergency Preparedness Inspector Approved By: Vincent Gaddy, Chief, Project Branch C Division of Reactor Projects-1- Enclosure

SUMMARY OF FINDINGS

IR 05000416/2010002; 01/01/2010 - 03/27/2010; Grand Gulf Nuclear Station, Integrated

Resident and Regional Report; Heat Sink Performance, and Event Follow-up.

The report covered a 3-month period of inspection by resident inspectors and announced baseline inspections by regional based inspectors. Four findings of very low safety 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.

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: Barrier Integrity

Green.

The inspectors reviewed a self-revealing non-cited violation of Technical Specification 5.4.1a when a fuel handling platform operator failed to move a fuel assembly in accordance with station procedures. Specifically, a new fuel assembly and the fuel handling platform mast were damaged when the platform was moved away from the fuel preparation machine prior to ensuring that the fuel assembly was clear of the machine. The licensee entered this issue into the corrective action program as Condition Report CR-GGN-2010-01883.

This finding is more than minor because the finding was associated with the human performance attribute of the barrier integrity cornerstone and adversely affected the cornerstones objective to provide reasonable assurance that physical design barriers (i.e. fuel cladding) protect the public from radionuclide releases caused by accidents or events. The failure to follow the fuel handling procedures affected the cornerstones objective to provide reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents or events.

Inspection Manual Chapter 0609, Significance Determination Process, Attachment 0609.04, Phase 1-Initial Screening and Characterization of Findings, was used to evaluate the significance of the finding. Attachment 0609.04, Table 4a, was used to evaluate the impact of the finding on fuel clad integrity. Since the finding represented a fuel handling error that did not cause damage to fuel clad integrity, the finding was determined to be of very low safety significance (Green). The finding has a cross cutting aspect in the work practices component of the human performance area because the operator performing the fuel movement and the spotter providing oversight of the fuel movement failed to employ effective self and peer checking techniques such that fuel handling activities were performed safely

[H.4.(a)]. (Section 4OA3.5)

Cornerstone: Initiating Events

Green.

The inspectors reviewed a self-revealing finding for a failure to follow work instructions resulting a in loss of 480V power to a bus and a plant transient.

Specifically, contract workers were directed by work instructions to enter into a motor control center via its top cable tray to run cables to a spare breaker. Contrary to this, the contract electrical workers deviated from approved work instructions, causing a phase to ground short that tripped the motor control center and resulted in a plant transient. The licensee entered this issue into the corrective action program as Condition Report CR-GGN-2010-01404.

This finding is more than minor because it was associated with the initiating events cornerstone attribute of human performance, and it affected the associated cornerstone objective to limit the likelihood of those events that upset plant stability and that challenge critical safety functions during shutdown, as well as during power operations. Using the Inspection Manual Chapter 0609, "Significance Determination Process," Phase 1 Worksheet, the inspectors concluded that the transient initiator did not contribute to both the likelihood of a reactor trip and to the likelihood that mitigation equipment or functions would not be available. As a result, the issue was of very low safety significance (Green). The cause of this finding has a crosscutting aspect in the area of human performance associated with work practices because the supervisor of the workers failed to ensure the contract workers followed the approved work instructions as required H.4(c). (Section 4OA3.3)

Green.

The inspectors reviewed a self-revealing finding involving the failure of site management to ensure that adequate corrective actions were implemented to resolve the effects of a large steam leak in the turbine building. Specifically, the reactor experienced an automatic scram on low reactor water level due to the B reactor feed pump minimum flow valve failing open and a subsequent trip of the A reactor feed pump. The scram investigation determined that the minimum flow valve failed open due to condensation in a cable routing box. The condensation was caused by a large steam leak on the second stage moisture separator re-heater drain valve. Cable splices in the box were submerged in water and eventually caused those cables to short to ground. The licensee entered this issue into the corrective action program as Condition Report CR-GGN-2010-01503.

This finding is more than minor because it was associated with the initiating events cornerstone attribute of equipment performance, and it affected the associated cornerstone objective to limit the likelihood of those events that upset plant stability and that challenge critical safety functions during shutdown, as well as during power operations. Using the Inspection Manual Chapter 0609, "Significance Determination Process," Phase 1 Worksheet, the inspectors concluded that the transient initiator did not contribute to both the likelihood of a reactor trip and to the likelihood that mitigation equipment or functions would not be available. This is because the reactor feed pump B was able to restore reactor water level post scram. As a result, the issue was of very low safety significance (Green). The cause of this finding has a crosscutting aspect in the area of problem identification and resolution associated with the corrective action program component because the licensee failed to prioritize and thoroughly evaluate the extent of the cause of the water grounding sensitive electronic equipment in the vicinity of the steam leak P.1(c).

(Section 4OA3.4)

Cornerstone: Mitigating Systems

Green.

The inspectors reviewed a self-revealing non-cited violation of Technical Specification 3.7.4 for failing to restore control room air conditioning subsystem B to operable status within the required time of 30 days. Specifically, between March 28, 2009 and June 25, 2009, the control room air conditioner subsystem B was inoperable due to the compressor capacity controller being set incorrectly. The deficiency initially revealed itself on May 14, 2009, when the air conditioner was unable to keep up with demand. The licensee entered this issue into the corrective action program as Condition Report CR-GGN-2009-3779.

This finding is more than minor since it affects because it was associated with the equipment performance attribute of the mitigating systems cornerstone, and it adversely affected the cornerstone objective of ensuring the availability, reliability and capability of safety related equipment. Using Manual Chapter 0609,

Significance Determination Process, Phase 1 Worksheet, the finding was determined to be of very low safety significance (Green) because it was not a design or qualification deficiency confirmed not to result in loss of operability or functionality, it does not represent an actual loss of a system safety function, it does not represent the actual loss of safety function of a single train for greater than its technical specification allowed outage time, it does not represent an actual loss of safety function of one or more non-technical specification of equipment designated as risk-significant per 10 CFR 50.65 for greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> and it does not screen as potentially risk significant due to a seismic, flooding, or severe weather initiating event. The cause of this finding has a crosscutting aspect in the area of human performance associated with decision making in that the operators did not utilize conservative assumptions to determine system operability H.1(b).

(Section 1R07.2).

Licensee-Identified Violations

Violations of very low safety significance, which were identified by the licensee, have been reviewed by the inspectors. Corrective actions taken or planned by the licensee have been entered into the licensees corrective action program. These violations and corrective action tracking numbers (condition report numbers) are listed in Section 4OA7.

REPORT DETAILS

Summary of Plant Status

Grand Gulf Nuclear Station (GGNS) began the inspection period at full rated thermal power. On January 2, 2010, operators reduced power to 80 percent to perform a control rod pattern adjustment and channel bow surveillance testing. The plant returned to rated power on January 3, 2010. On January 30, 2010, operators reduced power to perform a control rod sequence exchange and a channel bow surveillance testing. The plant returned to rated power on February 1, 2010. On the morning of February 17, 2010, operators reduced reactor power to 88 percent due to a low pressure turbine control valve closure, and returned to rated power in the evening on the same day. On February 23, 2010, operators reduced power to 80 percent to repair steam leaks on balance of plant equipment. On February 26, 2010, operators reduced power to 70 percent to perform a control rod pattern adjustment and perform a heater drain tank leak repair. The plant returned to rated power on February 27, 2010. The reactor experienced an automatic scram on March 8, 2010, on low reactor water level due to a feed pump minimum flow control valve opening. During start up from the forced outage, on March 18, 2010, the operators increased power to 97 percent and identified a steam leak in the turbine building. On the evening of March 18, 2010 plant operators reduced power to 80 percent to repair the steam leak. The plant returned to rated power on March 20, 2010. On March 21, 2010, reactor power began to coast down and trended to 97.2 percent at the end of the inspection period.

REACTOR SAFETY

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

1R01 Adverse Weather Protection

.1 Readiness for Seasonal Extreme Weather Conditions

a. Inspection Scope

The inspectors performed a review of the adverse weather procedures for seasonal extremes (e.g., extreme high temperatures, extreme low temperatures, or hurricane season preparations). The inspectors verified that weather-related equipment deficiencies identified during the previous year were corrected prior to the onset of seasonal extremes, and evaluated the implementation of the adverse weather preparation procedures and compensatory measures for the affected conditions before the onset of, and during, the adverse weather conditions.

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 plant personnel

were 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:

• Standby Service Water

• Auxiliary Cooling Tower These activities constitute completion of one readiness for seasonal adverse weather sample as defined in Inspection Procedure 71111.01-05.

b. Findings

No findings of significance were identified.

.2 Readiness for Impending Adverse Weather Conditions

a. Inspection Scope

On January 5, 2010, a winter-weather advisory was issued for an expected ice storm in the area. The inspectors observed the preparations and planning for the significant winter weather potential. The inspectors reviewed licensee procedures and discussed potential compensatory measures with control room personnel. The inspectors focused on plant managements actions for implementing the stations procedures for ensuring adequate personnel for safe plant operation and emergency response would be available. The inspectors conducted a site inspection, including various plant structures and systems, to check for maintenance or other apparent deficiencies that could affect system operations during the predicted significant weather. The inspectors also reviewed corrective action program items to verify that plant personnel were identifying adverse weather issues at an appropriate threshold and entering them into their corrective action program in accordance with station corrective action procedures.

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

These activities constitute completion of one readiness for impending adverse weather condition sample as defined in Inspection Procedure 71111.01-05.

b. Findings

No findings of significance were identified.

1R04 Equipment Alignments

a. Inspection Scope

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

• Control Room Air Conditioner A while Control Room Air Conditioner B compressor was being replaced

• Division 1 Diesel Generator while the Division 2 Diesel Generator was in an allowed outage time

• Offsite Power alignment while the Division 2 Diesel Generator was in an allowed outage time 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 of significance were identified.

1R05 Fire Protection

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:

• Division 2 Diesel Generator Room (1D303)

• Standby Service Water B Pump and Valve Rooms (2M110 and 2M112)

• Division 1 Diesel Generator Room (1D302)

• Diesel Building Hallway (1D301)

• Standby Service Water A Pump and Valve Rooms (1M110 and 1M112)

• High Pressure Core Spray Diesel Generator Room (1D304)

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

No findings of significance 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. 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.

• January 11, 2010, Emergency Core Cooling System Pump Rooms

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

b. Findings

No findings of significance were identified.

1R07 Heat Sink Performance

.1 Annual Heat Sink Inspection

a. Inspection Scope

The inspectors reviewed licensee programs, verified performance against industry standards, and reviewed critical operating parameters and maintenance records for the safety-related room coolers, Division 3 standby diesel generator jacket water cooler and the Division 2 standby diesel jacket water cooler. 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 of significance were identified.

.2 Triennial Heat Sink Inspection

a. Inspection Scope

The inspectors reviewed design documents, program documents, test and maintenance procedures, and corrective action documents for the inspection samples selected. The inspectors interviewed chemistry and engineering personnel.

The inspectors selected heat exchangers that ranked high in the plant specific risk assessment and were directly connected to the safety-related standby service water system. The inspectors selected the following heat exchangers:

• Ultimate Heat Sink (Standby Service Water Cooling Towers)

• Division 1 and 2 Control Room Heating, Ventilation, and Air Conditioning

• Division 2 Diesel Generator Jacket Water

• Residual Heat Removal Pump A Seal Cooler For heat exchangers directly connected to the standby service water system, the inspector verified whether testing, inspection, maintenance, and monitoring of biotic fouling and microfouling programs are singularly or in combination adequate to ensure proper heat transfer. Specifically, the inspectors reviewed:

(1) heat exchanger test methods and test results from performance testing;

(2) chemical treatments for microfouling and controls for macrofouling; and

(3) whether test results appropriately considered differences between testing conditions and design conditions.

For heat exchangers directly connected to the safety-related standby service water system, the inspectors verified that the licensee:

(1) performed condition monitoring and operation consistent with design assumptions in the heat transfer calculations; (2)evaluated the potential for water hammer, as applicable;

(3) instituted appropriate chemistry controls for the heat exchangers,

(4) reviewed periodic flow testing at or near maximum design flow for redundant and infrequently used heat exchanger,

(5) verified that the number of plugged tubes were within pre-established limits based on heat transfer capacity, and

(6) reviewed visual inspection records, to determine the structural integrity of the heat exchanger.

For the ultimate heat sink and its subcomponents, the inspectors verified that the licensee established appropriate controls for macrofouling and biological fouling. A system walk-down was performed to verify the licensee had:

(1) sufficient reservoir capacity;

(2) performed periodic monitoring and trending of sediment build-up; (3)periodic performance monitoring of heat transfer capability,

(4) periodic performance monitoring of the ultimate heat sink structural integrity,

(5) instrumentation that is available and functional,

(6) reviewed licensee controls to prevent clogging due to macrofouling, and

(7) biocide treatments that were conducted as scheduled, controlled, and the results monitored, trended, and evaluated.

Documents reviewed by the inspectors are listed in the attachment.

These activities constitute completion of four samples as defined in Inspection Procedure 71111.07-05.

b. Findings

Introduction.

The inspectors reviewed a self-revealing Green non-cited violation of Technical Specification 3.7.4 for failing to restore control room air conditioning subsystem B to operable status within the required time of 30 days.

Description.

On May 14, 2009, the site identified that the control room air conditioning subsystem B was not cooling properly. The thermostat set point was at 55°F, but the control room temperature was being maintained at 73°F. The subsequent operability determination noted that control room air conditioning subsystem B surveillance testing had been performed on the previous day, and that as part of the test, the standby fresh

air heaters had been turned on to ensure an adequate heat load for the test. The standby fresh air heaters were turned off, and the compressor capacity controller was adjusted. This resulted in a control room temperature decrease to 69°F. Based on the system response to the sites troubleshooting efforts and the raw data from the surveillance test, the control room air conditioning subsystem B was declared operable.

Initial review of the surveillance data taken on May 13, 2009, indicated that the control room air conditioning subsystem B condenser had an unacceptable fouling rate. The test data was declared invalid since the condenser had been rebuilt and cleaned in March 2009 and a retest was scheduled. The site failed to identify that the incorrectly positioned capacity controller was a deficiency that had been introduced to the system during the March 28, 2009, maintenance and rebuild of the compressor causing the control room air conditioning subsystem B to be inoperable.

Technical Specification Surveillance Requirement 3.7.4.1 requires an 18-month verification test confirming that each control room air conditioning subsystem is capable of removing an assumed heat load and maintaining the control room at or below 90°F.

On August 12, 2009, an engineering evaluation of the data taken during the May 13, 2009, surveillance test showed that the control room air conditioning subsystem B would have maintained a control room temperature of 91.5°F under design basis heat loads, which did not meet the acceptance criteria defined by the sites technical specifications.

The conclusion of the engineering evaluation was that the control room air condition subsystem B had been inoperable from March 28, 2009, through June 25, 2009, a period of 89 days. Although the control room air conditioning subsystem B was inoperable, it still would have performed its safety function of maintaining the control room below the design basis temperature of 120°F as defined by the sites Technical Requirements Manual.

Analysis.

The performance deficiency associated with this finding was the failure to meet the technical specification requirement of restoring the control room air conditioning subsystem B to operable status within 30 days. The finding was more than minor because it was associated with the equipment performance attribute of the mitigating systems cornerstone, and it adversely affected the cornerstone objective of ensuring the availability, reliability and capability of safety related equipment. Using Manual Chapter 0609, Significance Determination Process, Phase 1 Worksheet, the finding was determined to be of very low safety significance (Green) because it was not a design or qualification deficiency confirmed not to result in loss of operability or functionality, it does not represent an actual loss of a system safety function, it does not represent the actual loss of safety function of a single train for greater than its technical specification allowed outage time, it does not represent an actual loss of safety function of one or more non-technical specification of equipment designated as risk-significant per 10CFR50.65 for greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> and it does not screen as potentially risk significant due to a seismic, flooding, or severe weather initiating event. The cause of this finding has a crosscutting aspect in the area of human performance associated with decision making in that the operators did not utilize conservative assumptions to determine system operability H.1(b).

Enforcement.

In the event that one control room air conditioning subsystem is inoperable, Technical Specification 3.7.4.A.1 requires that the subsystem be restored to operable status within a period of 30 days. Contrary to the above, the control room air conditioning subsystem B was inoperable for a period of 89 days from March 28, 2009, through June 25, 2009. Because this violation was of very low safety significance and was entered in to the licensees corrective action program as Condition Report CR-GGN-2009-3779, this violation is being treated as a non-cited violation, consistent with Section VI.A.1 of the NRC Enforcement Policy: NCV 05000416/2009002-01, Failure to Restore Control Room Air Conditioning Subsystem B to Operable Status within the Required Time of 30 Days.

1R11 Licensed Operator Requalification Program

a. Inspection Scope

On January 25, 2010, 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 of significance were identified.

1R12 Maintenance Effectiveness

a. Inspection Scope

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

• 125V DC Power Supply System (L11, L21, L51)

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.

The inspectors also performed a review of the (a)(3) Periodic Evaluation. This review is credited as an inspection sample.

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

b. Findings

No findings of significance 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 January 11, 2010, during emergency core cooling system Division 3 testing

• The week of January 25, 2010, during the Division 3 allowed outage time resulting in the plant being in yellow risk the entire week

• The week of March 1, 2010, during the Division 2 allowed outage time resulting in the plant being in yellow risk the entire week

• The week of March 8, 2010, during a force outage and startup following an automatic plant shutdown on March 8, 2010

• The week of March 15, 2010, during completion of startup activities which included control rod frictions testing and increase to full power. This was followed by a transition to normal work schedule, that included performing numerous half scram and half isolation surveillances and a shift from Division 2 work week to Division 1 work day to performing yellow risk activities and then a return to Division 2 work week 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 five maintenance risk assessments and emergent work control inspection samples as defined in Inspection Procedure 71111.13-05.

b. Findings

No findings of significance were identified.

1R15 Operability Evaluations

a. Inspection Scope

The inspectors reviewed the following issues:

• Reactor water cleanup system primary containment isolation valve body to bonnet leakage, CR-GGN-2010-00981

• Fuel oil leak in high pressure core spray diesel filter fitting, CR-GGN-2009-06909

• Standby liquid control system low oil indication problem, CR-GGN-2010-00283

• Standby gas treatment system operability impacted due to door failure, CR-GGN-2009-04480

• Reactor coolant system pressure interface valve interlock problem due to agastat relay failure, CR-GGN-2010-00804

• Corrosion found in standby diesel generator air start system check valve, CR-GGN-2010-01458 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 six operability evaluations inspection samples as defined in Inspection Procedure 71111.15-04

b. Findings

No findings of significance were identified.

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

Modifications (71111.17)

a. Inspection Scope

The inspectors reviewed the effectiveness of the licensees implementation of evaluations performed in accordance with 10 CFR 50.59, Changes, Tests, and Experiments, and changes, tests, experiments, or methodology changes that the licensee determined did not require 10 CFR 50.59 evaluations.

The inspectors reviewed five evaluations required by 10 CFR 50.59 because these were the only evaluations performed since the last performance of this inspection. The inspectors also reviewed 19 changes, tests, and experiments that were screened out by licensee personnel and eight permanent plant modifications. Document numbers of the evaluations, changes, and modifications reviewed are listed in the attachment.

The inspectors verified that when changes, tests, or experiments were made, that evaluations were performed in accordance with 10 CFR 50.59 and that licensee personnel had appropriately concluded that the change, test or experiment can 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 reviewed changes, tests, and experiments that licensee personnel determined did not require evaluations and verified that these conclusions were correct and consistent with 10 CFR 50.59. The inspectors also verified that procedures, design, and licensing basis documentation used to support the changes were accurate after the changes had been made.

In the inspection of modifications, the inspectors verified that supporting design and license basis documentation had been updated accordingly and was still consistent with the new design. The inspectors verified that procedures, training plans and other design basis features had been adequately accounted for and updated. Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of samples as defined in Inspection Procedure 71111.17-05.

b. Findings

No findings of significance were identified.

1R18 Plant Modifications

Temporary Modifications

a. Inspection Scope

To verify that the safety functions of important safety systems were not degraded, the inspectors reviewed the following temporary modifications:

• Feedwater heating valve, 1N35-505B, steam leak repair that was impacting plant equipment

• Removal of control rod drive mechanism temperature alarm inputs The inspectors reviewed the temporary modifications and the associated safety-evaluation screening against the system design bases documentation, including the Updated Final Safety Analysis Report and the technical specifications, and verified that the modification did not adversely affect the system operability/availability. The inspectors also verified that the installation and restoration were consistent with the modification documents and that configuration control was adequate. Additionally, the inspectors verified that the temporary modification was identified on control room drawings, appropriate tags were placed on the affected equipment, and licensee personnel evaluated the combined effects on mitigating systems and the integrity of radiological barriers.

These activities constitute completion of two samples for temporary plant modifications as defined in Inspection Procedure 71111.18-05.

b. Findings

No findings of significance 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:

• For Intermediate Range H power supply refurbishment

• For Division 3 diesel generator following maintenance

• For control room fresh air train B following replacement of the compressor

• Replacement of a reactor protection system relay

• Division 2 Diesel Generator retest after two year maintenance window

• Residual Heat Removal system motor operated valves retest after periodic maintenance and motor operated valve testing

• Standby Service Water system B retest after periodic 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 (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 seven postmaintenance testing inspection samples as defined in Inspection Procedure 71111.19-05.

b. Findings

No findings of significance 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

• 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 January 12, 2010, containment spray time delay relay functional test

• On January 14-15, 2010, high pressure core spray diesel generator 18 month functional test

• On January 22, 2010, high pressure core spray local leak rate test

• On March 4, 2010, residual heat removal system train B quarterly inservice test

• On March 16, 2010, reactor core isolation cooling quarterly inservice test 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

No findings of significance were identified.

1EP4 Emergency Action Level and Emergency Plan Changes

a. Inspection Scope

The inspector performed an in-office review of Grand Gulf Nuclear Station Emergency Plan, Revision 62 and 63. Revision 62 clarified the position descriptions of the Security Coordinator and the Security Shift Supervisor, assigned habitability monitoring to the Emergency Operations Facility Habitability Specialist, described the Emergency Preparedness Department reporting relationships, and made other minor administrative changes. Revision 63 involved on-shift staffing changes submitted to NRC for prior approval by letters dated April 28, 2008 and April 3, 2009. The NRC issued letter dated September 2, 2009 (ADAMS Accession Number ML091110035), concluding that the proposed change would not decrease the effectiveness of the emergency plan. The change increased the on-shift Auxiliary Operators from two to three, increased the 90 minute response Mechanical Maintenance staff from one to two, combined the on-shift Electrical and I&C Maintenance staff from 1 each to two of either discipline or both, and added one 90 minute I&C maintenance staff responder.

These revisions were compared to previous revisions, 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, 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, these revisions are subject to future inspection.

These activities constitute completion of two samples as defined in Inspection Procedure 71114.04-05.

b. Findings

No findings of significance were identified.

1EP6 Drill Evaluation

Emergency Preparedness Drill Observation

a. Inspection Scope

The inspectors evaluated the conduct of a routine licensee emergency drill on February 24, 2010, to identify any weaknesses and deficiencies in classification, notification, and

protective action recommendation development activities. The inspectors observed emergency response operations in the simulator control room and the emergency operations facility to determine whether the event classification, notifications, and protective action recommendations were performed in accordance with procedures. The inspectors also attended the licensee drill critique to compare any inspector-observed weakness with those identified by the licensee staff in order to evaluate the critique and to verify whether the licensee staff was properly identifying weaknesses and entering them into the corrective action program. As part of the inspection, the inspectors reviewed the drill package and other documents listed in the attachment.

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

b. Findings

No findings of significance 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 fourth quarter 2009 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 of significance were identified.

.2 Unplanned Scrams per 7000 Critical Hours (IE01)

a. Inspection Scope

The inspectors sampled licensee submittals for the unplanned scrams per 7000 critical hours performance indicator for the period from the first quarter 2009 through fourth quarter 2009. 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 5.

The inspectors reviewed the licensees operator narrative logs, issue reports, event reports, and NRC integrated inspection reports for the period of January 1, 2009, through December 31, 2009, 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 unplanned scrams per 7000 critical hours sample as defined in Inspection Procedure 71151-05.

b. Findings

No findings of significance were identified.

.3 Unplanned Scrams with Complications (IE02)

a. Inspection Scope

The inspectors sampled licensee submittals for the unplanned scrams with complications performance indicator for the period from the first quarter 2009 through fourth quarter 2009. 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 5. The inspectors reviewed the licensees operator narrative logs, issue reports, event reports, and NRC integrated inspection reports for the period of January 1, 2009, through December 31, 2009, 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 unplanned scrams with complications sample as defined in Inspection Procedure 71151-05.

b. Findings

No findings of significance were identified.

.4 Unplanned Power Changes per 7000 Critical Hours (IE03)

a. Inspection Scope

The inspectors sampled licensee submittals for the unplanned power changes per 7000 critical hours performance indicator for the period from the first quarter 2009 through fourth quarter 2009. 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 5. The inspectors reviewed the licensees operator narrative logs, issue reports, maintenance rule records, event reports, and NRC integrated inspection reports for the period of January 1, 2009 through December 31, 2009, 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 unplanned transients per 7000 critical hours sample as defined in Inspection Procedure 71151-05.

b. Findings

No findings of significance 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 of significance 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 of significance were identified.

.3 Identification and Resolution of Problems for Heat Exchangers and 10 CFR 50.59

a. Inspection Scope

The inspectors reviewed the licensees corrective actions related to deficiencies in the operation of the selected heat exchangers and the ultimate heat sink. The inspectors evaluated whether the licensee implemented appropriate corrective actions commensurate with their safety significance.

The inspectors reviewed the licensees corrective actions related to deficiencies in the 10 CFR 50.59, Changes, Tests, and Experiments program and permanent plant modifications. The inspectors evaluated whether the licensee implemented appropriate corrective actions commensurate with their safety significance.

b. Observations The inspector concluded that problems are being identified and corrective actions are being implemented for the selected heat exchangers and the plant modification process.

No findings of significance were identified.

.4 Selected Issue Follow-up Inspection

a. Inspection Scope

During a review of items entered in the licensees corrective action program, specifically in reference to sump pump equipment performance in the emergency core cooling system pump rooms, the inspectors found condition reports that had been closed to work orders associated with failed check valves in the room drains. The work orders had been open for more than five years. The inspectors requested information on the number of condition reports documenting problems in safety-related systems that had been closed to work orders, and found that the licensee had previously identified a

backlog of 856 condition reports closed to open work orders, dating back to 1999. The inspectors reviewed approximately 200 of the work orders, starting with the oldest and found 26 that documented degrading equipment. The inspectors focused on eight of the issues and found that the degrading conditions had not been resolved, however, in each case, operability of the system, structure or component was maintained.

The inspectors reviewed a condition report documenting a pin-hole leak on a service water cooling tower fan D gearbox oil drain line caused by degraded protective wraps on the service water cooling tower fans gearbox oil drain lines. The inspectors interviewed the system engineer and learned that a condition report had been written to document the failure to do a proper extent of condition review from a previous event.

The inspectors found that the licensee had previously identified and replaced wrappings on the gearbox for the A fan in 2007; however, the licensee failed to take action to replace known degraded wrappings on the other fan gearboxes.

The inspectors reviewed the status of a condition report and the resulting corrective actions documenting corrosion in the standby cooling tower basins in October 2008.

The inspectors reviewed corrective actions taken to improve maintenance inspections of safety-related equipment and to restore the structural margins of the degraded basins.

The inspectors also reviewed the apparent cause evaluation and the corrective action taken to date to ensure that actions are appropriate and have been implemented in a timely manner.

These activities constitute completion of three in-depth problem identification and resolution samples as defined in Inspection Procedure 71152-05.

b. Findings

No findings of significance were identified.

4OA3 Event Follow-up

.1 (Closed) Licensee Event Report 05000416/2009-004-00/05000416/2009-004-01,

Condition Prohibited by Technical Specifications due to Control Room Air Conditioning Subsystem B Inoperability Not Recognized On May 13, 2009, a surveillance test had been performed per Technical Specification (TS) Surveillance Requirement 3.7.4.1. The test results indicated an unacceptable fouling rate of the control room air conditioning subsystem B (CRAC B) compressor.

Since the compressor had undergone maintenance and cleaning in March 2009, the test data was considered invalid and a retest was scheduled and completed on June 25, 2009. On August 12, 2009, an engineering evaluation of the invalid data showed that the CRAC B unit would not meet the acceptance criteria of maintaining the control room less than or equal to 90°F under design basis accident heat loads. Based on the evaluation, it was concluded that CRAC B had been inoperable from March 28, 2009, through June 25, 2009. As a result, the Technical Specification 3.7.4.A.1, which requires control room air conditioning subsystem operability, be restored within 30 days, was not met.

The cause of this event was a failure to correctly implement station procedures for maintenance on the CRAC B compressor and determining operability of the CRAC B unit. Maintenance personnel did not follow station procedures when setting the capacity controller on the unit compressor. Consequently, a deficiency was introduced to the system that prevented the CRAC unit from meeting the technical specification surveillance test acceptance criteria. Control room personnel failed to adequately develop a reasonable expectation of operability on May 14, 2009, because they utilized an impromptu functional test and un-evaluated surveillance test data to declare the unit operable. There is no safety consequence associated with this event.

Corrective actions included reviewing the maintenance history of control room air conditioning subsystem A to confirm the thermal performance test had been completed with satisfactory results and revise work instructions for both A & B compressors to include prerequisites for capacity controller setup/adjustment and capacity controller setup/adjustment instructions per the Vendor manual. Documents reviewed as part of this inspection are listed in the attachment. The enforcement aspects of this finding were discussed in NRC Inspection Report 05000416/2010002 in Section 1R07. These LERs are closed.

.2 Low Pressure Turbine Control Valve Inadvertent Closure

a. Inspection Scope

On February 17, 2010, at 1:15 a.m., the operations crew noted a decrease of 13 megawatts electric for unknown reason. The control room also received turbine alarms and entered alarm response procedures and sent personnel into the turbine building to determine if previously identified steam leaks had gotten worse. At 5:40 a.m., the operations crew noted that the 1N11-F030K, low pressure turbine 3 control valve, indicated closed. Operators confirmed that the valve was closed and the crew entered Technical Requirements Manual (TRM) Section 6.3.8 for main turbine overspeed protection which required entry into TRM section 6.0.1. As required by the system operating instruction the crew reduced reactor power to 90 percent when the low pressure turbine control valve closed. The shift manager notified the resident inspectors at approximately 5:30 a.m. of the loss of megawatts electric. The inspectors responded to the site to monitor operator actions. The licensee determined that cause of the control valve closure was due to turbine testing control system giving the valve a close signal.

The inspectors reviewed the sites recovery plans. The inspectors then observed the operating crew recover from the event by opening the control valve. Inspectors also monitored plant response from the control room. The plant restored reactor power to 100 percent. The licensee determined that the reason the low pressure control valve closed was possibly due to a water intrusion from a steam leak into turbine testing logic control panel. Documents reviewed for this inspection are listed in the attachment.

b. Findings

No findings of significance were identified.

.3 Loss of Motor Control Center 14B12

a. Inspection Scope

On March 3, 2010, at 10:25 a.m., the main control room received alarm 480V LCC 14BE1 INCM FDR/Trip, indicating a loss of alternating current to a bus. Further investigation revealed that power was loss to motor control center 14B12. Due to the loss of this bus, the control room lost indications for several control rod drive meters; lost power to solenoid valves for both control rod drive flow control valves causing them to drift close; plant chiller C tripped and subsequently restarted; lost power to recirculation pump B hydraulic control units for the B flow control valve and other plant equipment.

The cause of the loss of power was due to work being performed in the non-safety motor control center which caused a phase to ground short, tripping the feeder breaker 52-14106 to bus 14B12. The phase to ground short also caused damage to the bus bar. The resident inspectors arrived in the main control room shortly after the event occurred and observed the operating crews response to the event. The crew entered their off normal procedure for loss of alternating current to the bus and system operating procedure for determining bus loads that were de-energized. The inspectors also responded to the bus location and observed the recovery actions. After the cause of the ground fault was removed engineering evaluated the extent of damage to the bus bar and established a recovery plan. The inspectors observed control room operators direct the restoration of the bus and restoration of power to loads o the bus. Documents reviewed for this inspection are listed in the attachment.

b. Findings

Introduction.

The inspectors reviewed a self-revealing Green finding involving a failure to follow work instructions that resulted in a loss of 480V power to a bus and a plant transient.

Description.

On March 3, 2010, at 10:25 a.m., the main control room received alarm 480V LCC 14BE1 INCM FDR/Trip, indicating a loss of alternating current to a bus.

Further investigation revealed that power was lost to motor control center 14B12. The loss of power was due to work being performed in the non-safety motor control center, which resulted in a phase to ground short that tripped the feeder breaker 52-14106 to bus 14B12. The operating crew responded to the event by entering their off normal procedure for loss of alternating current to the bus and system operating procedure for determining bus loads that were de-energized. Power was lost to the recirculation pump B hydraulic control units for the B flow control valve. This resulted in the B flow control valve slowly closing over the duration of event, which caused in a slight power decrease. Power was also lost to the solenoid valves for both control rod drive flow control valves, causing them to drift fully closed, causing an increasing temperature to control rod drive mechanisms. The inspectors observed the operating crews response to the event. Additionally, the inspectors responded to the bus location to observe the recovery actions. After the cause of the ground fault was removed and site engineering evaluated the extent of damage to the bus bar, a recovery plan was established, and the bus was restored along with its loads.

Power to the bus was lost when contract electrical workers, who were running cables in motor control center 14B12, deviated from the approved work instructions for performing the work. During the deviation, a metal access cover contacted the energized bus bar, causing the phase to ground short.

Plant management immediately removed all contract/supplemental workers from the site that were associated with the company employing the workers involved in the event.

Additionally, the licensee required the contractor to develop a recovery plan prior to returning to work. Licensee management also addressed all the contract/supplemental workers from this company about the event and about site expectations for working at Grand Gulf Nuclear Station prior to their return to work. This event was entered into the licensees corrective action program as CR-GGN-2010-01404.

Analysis.

The performance deficiency involved the failure of contract electrical workers to follow approved work instructions which resulted in a plant transient. Specifically, contract workers were directed by work instructions to enter into the motor control center (MCC) via the top cable tray of the motor control center to run cables to a spare breaker.

Contrary to this, on March 3, 2010, contract electrical workers deviated from approved work instructions, resulting in a phase to ground short that tripped the motor control center causing a plant transient. The finding was more than minor because it was associated with the initiating events cornerstone attribute of human performance, and it affected the associated cornerstone objective to limit the likelihood of those events that upset plant stability and that challenge critical safety functions during shutdown, as well as during power operations. Using the Inspection Manual Chapter 0609, "Significance Determination Process," Phase 1 Worksheet, the inspectors concluded that the transient initiator did not contribute to both the likelihood of a reactor trip and to the likelihood that mitigation equipment or functions would not be available. As a result, the issue was of very low safety significance (Green). The cause of this finding has a crosscutting aspect in the area of human performance associated with work practices because the supervisor of the workers failed to ensure the contract workers followed the approved work instructions as required H.4(c).

Enforcement.

No violation of regulatory requirements occurred. This finding was entered into the licensees corrective action program as CR-GGN-2010-01404 and is identified as FIN 05000416/2010002-02, Failure to Follow Work Instructions Results in Loss of Buss and a Plant Transient.

.4 Reactor Scram Due to the Reactor Feedwater Pump Turbine B Minimum Flow Valve

Failing Open

a. Inspection Scope

On March 8, 2010, at 4:35 p.m., the reactor experienced an automatic scram from 100 percent power. The B reactor feed pump minimum flow valve failed open, and both reactor feed pumps increased speed to compensate for feedwater that was being diverted to the condenser. The A reactor feed pump governor failed to mechanically respond to the controllers increase in demand, and a greater than 20 percent mismatch occurred between the control circuit signal and the actual feed pump speed, resulting in

trip of the A feed pump. The reactor recirculation system responded to the A feed pump trip by initiating a flow control valve runback to both control valves to reduce reactor power to maintain the reactor level within the flow capability of one reactor feed pump. The A flow control valve locked up and failed to decrease power, and the reactor scrammed on reactor low water level. The resident inspectors responded to the control room to observed operators post scram response. Inspectors observed the operating crew restore reactor water level using reactor feed pump B via the start up level control valve to maintain reactor water level in normal band. The operators entered the appropriate emergency operating, off-normal event and integrating operating procedures to mitigate the transient with all systems responding as designed with the exception of those previously noted. Site personnel investigating the scram determined that the B reactor feed pump minimum flow valve opened due to a cable splice being submerged in water in its routing box, resulting in the cable grounding. This resulted in a signal to the minimum flow valve to open. The source of the water in the cable routing box was from a steam leak from valve N35-F505B (second stage moisture separator re-heater drain valve to the 6B high pressure heater) that had been repaired on February 23, 2010. Documents reviewed in this inspection are listed in the Attachment.

b. Findings

Introduction.

The inspectors reviewed a self-revealing Green finding involving the failure of site management to ensure that adequate corrective actions were implemented to resolve the effects of a large steam leak in the turbine building.

Description.

On March 8, 2010, the reactor experienced an automatic scram on low reactor water level due to the B reactor feed pump minimum flow valve failing open and a subsequent trip of the A reactor feed pump. The scram investigation determined that the minimum flow valve failed open due to condensation in a cable routing box. The condensation was caused by a large steam leak on the second stage moisture separator re-heater drain valve. Cable splices in the box were submerged in water and eventually caused those cables to short to ground.

The following timeline details the steam leak and the associated plant effects:

• On February 14, 2010, a major steam leak developed in the second stage moisture separator re-heater drain valve to the 6B high pressure feed water heater.

• On February 17, 2010, a low pressure turbine control valve failed closed resulting in a plant down power.

• On February 18-19, 2010, control room operators identified the following deficiencies for the B reactor feed pump:

o The pump suction flow indicator failed down scale.

o The low pressure and high pressure stop valves showed dual position indication.

o Various computer points on the parameter display system went to a faulted status.

• On February 20, 2010, control room operators observed fluctuations in generator electric power output.

• On February 21, 2010, various indications were lost on steam supply valves and alarms were received for the B reactor feed pump. Water was found leaking into a panel in the vicinity of the steam leak.

• On February 23, 2010, plant power was reduced to 80 percent to repair the steam leak.

Site personnel investigating the scram determined that the plant failed to take timely and appropriate actions to resolve the problems caused by the steam leak. Following the steam leak repair on February 23, 2010, the licensee implemented a corrective action plan to identify deficiencies listed in the above timeline and the plan was to be implemented March 12, 2010. The failure to take these actions sooner directly resulted in the automatic reactor scram that occurred on March 8, 2010.

Prior to plant startup, the site conducted a review of electrical boxes in the turbine building and drained several boxes where water had accumulated. In addition, boxes found with cable splices that had been submerged were identified and the splices repaired.

Analysis.

The performance deficiency involved the failure of site management to ensure that adequate corrective actions were implemented to resove the effects of the steam leak on second stage moisture separator re-heater drain valve. Specifically, EN-LI-102, Section 4.0[2](c), states, EN Management is responsible for ensuring that required actions for Condition Reports are determined, implemented, and adequate to resolve the condition. Contrary to this, site management did not take adequate corrective actions to thoroughly evaluate and resolve the effects of the February 14, 2010, steam leak. Had this evaluation been performed, it could have potentially prevented an automatic reactor scram on March 8, 2010. The finding was more than minor because it was associated with the initiating events cornerstone attribute of equipment performance, and it affected the associated cornerstone objective to limit the likelihood of those events that upset plant stability and that challenge critical safety functions during shutdown, as well as during power operations. Using the Inspection Manual Chapter 0609, "Significance Determination Process," Phase 1 Worksheet, the inspectors concluded that the transient initiator did not contribute to both the likelihood of a reactor trip and to the likelihood that mitigation equipment or functions would not be available. This is because the reactor feed pump B was able to restore reactor water level post scram. As a result, the issue was of very low safety significance (Green). The cause of this finding has a crosscutting aspect in the area problem identification and resolution associated with the corrective action program component because the licensee failed to prioritize and thoroughly evaluate the extent of the cause of the water grounding sensitive electronic equipment in the vicinity of the steam leak P.1(c).

Enforcement.

No violation of regulatory requirements occurred. This finding was entered into the licensees corrective action program as CR-GGN-2010-01503 and is identified as FIN 05000416/2010002-03, Inadequate Actions in Response to a Steam Leak Result in an Automatic Reactor Scram.

.5 Fuel Handling Platform Mast and Fuel Assembly Damaged during Fuel Receipt

a. Inspection Scope

On March 22, 2010, a new fuel assembly and the fuel handling platform mast were damaged when the platform was moved away from the fuel preparation machine prior to ensuring that the fuel assembly was clear of the machine. During the movement of the bridge, a popping noise was heard by the refuel supervisor, fuel preparation machine operator, bridge operator, and spotter. Fuel handling platform movement was terminated. The noise was caused by the mast impacting the Plexiglas shield attached to the top of the fuel handling platform cab. The inspectors responded to the spent fuel pool area to ensure that the fuel was in a safe condition. The inspectors monitored the recovery and observed repairs of the refueling mast. Documents reviewed in this inspection are listed in the Attachment.

b. Findings

Introduction.

A Green self-revealing non-cited violation of Technical Specification 5.4.1a was identified when a fuel handling platform operator failed to move a fuel assembly in accordance with station procedures.

Description.

On March 22, 2010, a fuel assembly was damaged during receipt of new fuel in the spent fuel pool. The assembly had been placed in the fuel preparation machine and lowered so that the fuel handling platform could grapple the bail handle and move the assembly to a designated storage location in the spent fuel pool. The platform operator manoeuvred the platform and mast to the fuel assembly and grappled the fuel.

As the operator was lifting the fuel bundle with the mast hoist, the spotter informed the operator of an unusual noise that sounded like a hissing. After a few minutes of investigation, the operator and spotter determined the sound to be from a relief valve that lifts under normal conditions and was expected. The operator returned to the mast controls and instead of bringing the bundle to the full up position, began to move the platform away from the fuel preparation machine. At the same time, the spotter had left the cab area to complete documentation associated with the fuel movement. A popping noise was heard by the refuel supervisor, fuel preparation machine operator, bridge operator, and spotter. Fuel handling platform movement was terminated. The popping noise was caused by the mast impacting the Plexiglas shield attached to the top of the fuel handling platform cab.

The licensee inspected the bundle and mast and found that the bundle had lifted a few inches off the seat of the fuel preparation machine. The upper carriage guide on the fuel preparation machine prevented the horizontal movement of the bundle, resulting in the mast and the fuel assembly bail handle bending under the horizontal force applied by the platform movement.

Analysis.

The performance deficiency was the failure of the fuel handling platform operator to move a fuel assembly in accordance with station procedures. The inspectors determined that the finding was more than minor because the finding was associated with the human performance attribute of the barrier integrity cornerstone and adversely affected the cornerstones objective to provide reasonable assurance that physical design barriers (i.e. fuel cladding) protect the public from radionuclide releases caused by accidents or events. Inspection Manual Chapter 0609, Significance Determination Process, Attachment 0609.04, Phase 1-Initial Screening and Characterization of Findings, was used to evaluate the significance of the finding. Attachment 0609.04, Table 4a, was used to evaluate the impact of the finding on fuel clad integrity. Since the finding represented a fuel handling error that did not cause damage to fuel clad integrity, the finding was determined to be of very low safety significance (Green). The finding has a cross cutting aspect in the work practices component of the human performance area because the operator performing the fuel movement did not employ effective self and peer checking techniques such that fuel handling activities were performed safely

H.4(a).

Enforcement.

Technical Specification 5.4.1a, requires that written procedures be established, implemented and maintained as recommended in NRC Regulatory Guide 1.33, Quality Assurance Program Requirements, Revision 2, Appendix A, February 1978. Regulatory Guide 1.33, Appendix A, Section 2 includes procedures for refueling equipment operation. System Operating Procedure 04-1-01-F11-3, Fuel Handling Platform, Revision 036 requires that the operator continuously observe the grapple position as the bridge and trolley is moved. System Operating Procedure 04-1-01-F11-4, Fuel Prep Machine Operation, Revision 016 requires that the operator slowly raise the fuel bundle until it is clear of the fuel preparation machine upper carriage guide. Contrary to these procedural requirements, on March 22, 2010, the operator failed to continuously observe the grapple position to ensure that a new fuel assembly cleared the upper carriage guide of the fuel preparation machine. This resulted in damage to the fuel assembly and the fuel handling platform mast. Because this violation was of very low safety significance and the licensee has entered it into their corrective action program as condition report CR-GGN-2010-01883, this violation is being treated as an NCV, consistent with Section VI.A.1 of the NRC Enforcement Policy. NCV 05000416/2010002-04, Failure to Follow Procedures Results in Damage to Fuel Assembly and Fuel Handling Platform Mast.

4OA6 Meetings

Exit Meeting Summary

On February 11, 2010, the region-based inspectors presented the triennial heat exchanger and 50.59 inspection results to Mr. R. Douet, Site Vice President, and other members of his staff.

The inspectors reviewed some proprietary information and verified that none would be included in this report.

On March 22, 2010, the inspector conducted a telephonic exit meeting to present the results of the in-office inspection of changes to the licensees emergency plan to Mr. R. Vandenakker, Acting Manager, Emergency Preparedness and Mr. M. Larson, Licensing Engineer. 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 April 12, 2010, the inspectors presented the inspection results to Mr. R. Douet, 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

The following violations of very low safety significance (Green) were identified by the licensee and are violations of NRC requirements which meet the criteria of Section VI of the NRC Enforcement Policy, NUREG-1600, for being dispositioned as NCVs.

• Title 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, states 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 this, conditions adverse to quality which had been documented in condition reports and then subsequently closed to improperly prioritized or delayed work orders, failed to be corrected in a timely manner. The licensee identified a large backlog of work orders for safety related equipment that dated back to 1999. The work orders included several conditions adverse to quality such as an increasing trend in cyclic loading on a containment isolation valve motor, degraded standby service water basin slab coatings, and a degraded control building fire door. This issue was documented in the licensees corrective action program in condition report CR GGN-2009-05478. This finding is of very low safety significance because it did not represent a loss of system safety function, did not represent the actual loss of safety function of a single train for greater than its technical specification allowed outage time, and did not screen as potentially risk significant due to a seismic, flooding, or severe weather initiating event.

• Technical Requirements Manual (TRM) section 6.2.8 requires that if a fire barrier assembly is inoperable and the fire detection system on one side of the inoperable assembly is inoperable a continuous fire watch must be established immediately.

Contrary to this, on February 26, 2010 the licensee identified the fire detection system for fire zone 2-14 had failed its surveillance and was declared inoperable. The control room supervisor established an hourly fire watch based on TRM section 6.2.1. During shift turnover it was discovered that previously the auxiliary building elevator door for 103 foot elevation of the auxiliary building was declared inoperable. This was a barrier assembly that was in the same area as fire zone 2-14 and a continuous fire watch should have been established rather then a hourly fire watch. The control room supervisor immediacy established a continuous fire watch to comply with the TRM. This issue was documented in the licensees corrective action program in condition report CR GGN-2010-01291. The senior reactor analyst from region IV performed a bounding evaluation of the change in risk caused by substituting a one-hour roving fire watch for a continuous fire watch. Based on the short exposure period and the 45-minute fire wrap in use in the fire compartments of concern, the analyst determined that the change in risk was significantly less than 1E-6. Therefore, this finding was of very low safety significance (Green).

• Title 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, states 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 this, on June 27, 2007 the licensee identified degrading protective wrappings on the service water cooling tower A fan gearbox oil drain lines resulting in metal loss on the piping due to corrosion. The wrappings were replaced on the gearbox for the A fan; however the licensee failed to take action to replace known degraded wrappings on the other fan gearboxes. This resulted in a pinhole leak on the D fan gearbox on December 3, 2009.

This issue was documented in the licensees corrective action program in condition report CR GGN-2009-06597. This finding is of very low safety significance because it did not represent a loss of system safety function, did not represent the actual loss of safety function of a single train for greater than its technical specification allowed outage time, and did not screen as potentially risk significant due to a seismic, flooding, or severe weather initiating event.

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

D. Barfield, Director, Engineering

R. Benson, Supervisor, Radioactive Waste

J. Browning, General Manager, Plant Operations

J. Buford, Acting Manager, Licensing

J. Caery, Training Manager

M. Causey, Maintenance Rule Engineer

R. Douet, Vice President, Operations

B. Edwards, Minority Owner Specialist

H. Farris, Assistant Operations Manager

G. Giles, Manager, Corrective Actions and Assessments

E. Harris, Manager, Quality Assurance

K. Higginbotham, Manager, Operations

J. Houston, Manger, Maintenance

D. Jones, Manager, Design Engineering

M. Larson, Senior Licensing Specialist

S. Osborn, Senior Licensing Specialist

C. Perino, Licensing Manager

M. Rohrer, Manager, Component Engineering

F. Rosser, Supervisor, Radiation Protection

J. Shew, Manager, System Engineering

P. Stokes, Radiation Protection Specialist

W. Trichell, Radiation Protection Manager

J. Watts, Radiation Protection Specialist

R. Wilson, Manager, Planning, Scheduling and Outages

E. Wright, ALARA Specialist, Radiation Protection

R. Vandenakker, Acting Manager, Emergency Preparedness

M. Larson, Licensing Engineer

NRC Personnel

R. Kumana, Project Engineer

B. Hagar, Senior Project Engineer

Attachment

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened and Closed

Failure to Restore Control Room Air Conditioning Subsystem

05000416/2010002-01 NCV B to Operable Status Within the Required Time of 30 days (Section 1R07)

Failure to Follow Work Instructions Results in Loss of Buss

05000416/2010002-02 FIN and a Plant Transient (Section 4OA3)

Inadequate Actions in Response to a Steam Leak Result in

05000416/2010002-03 FIN an Automatic Reactor Scram (Section 4OA3)

Failure to Follow Procedures Results in Damage to Fuel

05000416/2010002-04 NCV Assembly and Fuel Handling Platform Mast (Section 4OA3)

Closed

Condition Prohibited by Technical Specifications due to

05000416/2009-004-00 LER Control Room Air Conditioning Subsystem B Inoperability Not Recognized Condition Prohibited by Technical Specifications due to

05000416/2009-004-01 LER Control Room Air Conditioning Subsystem B Inoperability Not Recognized