Text

IR 05000416-12-005; 09/22/2012 - 12/31/2012; Grand Gulf Nuclear Station, Unit 1, Integrated Resident and Regional Report; Maintenance Effectiveness, Refueling & Other Outage Activities, Occupational ALARA Planning and Controls, and Foll
	ML13042A373
Person / Time
Site:	Grand Gulf
Issue date:	02/11/2013
From:	Proulx D L; NRC/RGN-IV/DRP/RPB-C
To:	Kevin Mulligan; Entergy Operations
	Proulx D
References
	Download: ML13042A373 (97)
	v • d • e

February 11, 2013

Kevin Mulligan Vice President Operations Entergy Operations, Inc. Grand Gulf Nuclear Station P.O. Box 756 Port Gibson, MS 39150

SUBJECT: GRAND GULF NUCLEAR STATION - NRC INTEGRATED INSPECTION REPORT NUMBER 05000416/2012005

Dear Mr. Mulligan:

On December 31, 2012, 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 17, 2013, with you and other members of your staff. The inspections examined activities conducted under your license as they relate to safety and compliance with the Commissions rules and regulations and with the conditions of your license. The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel. Four NRC identified and three self-revealing findings of very low safety significance (Green) were identified during this inspection. Six of these findings were determined to involve violations of NRC requirements. Further, a licensee-identified violation, which was determined to be of very low safety significance is listed in this report. The NRC is treating these violations as non-cited violations (NCVs) consistent with Section 2.3.2 of the Enforcement Policy. If you contest these non-cited violations, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington DC 20555-0001; with copies to the Regional Administrator, Region IV; the Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at Grand Gulf Nuclear Station. If you disagree with a cross-cutting aspect assignment in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your disagreement, to the Regional Administrator, Region IV; and the NRC Resident Inspector at Grand Gulf Nuclear Station. In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter, its enclosure, and your response (if any) will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of NRC's Agencywide Document Access and Management System (ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,/RA/ David Proulx, Acting Branch Chief Project Branch C Division of Reactor Projects Docket No.: 50-416 License No: NPF-29

Enclosure:

Inspection Report 05000416/2012005 w/ Attachments 1: Supplemental Information 2: Request for Information for ALARA Planning & Controls Inspection cc w/ encl: Electronic Distribution for Grand Gulf Nuclear Station

SUMMARY OF FINDINGS

The inspectors reviewed a self-revealing non-cited violation of Technical Specification 5.4.1 for failure to comply with radiological exposure controls specified in Radiation Work Permit 2012- required the licensee to verify that fuel pool cleanup (demineralizers) was in-service, and if dose rates increased by more than 0.2 millirem/hour, change the resins. During reactor cavity operations, both fuel pool demineralizer trains were inoperable at least 25 days. In addition, the dryer separator pool and reactor cavity were isolated from the fuel pool clean up system. Consequently, general area radiation levels on the reactor cavity floor increased from 0.4 millirem/hour to 6.0 millirem/hour. The actual collective dose and hours for the work activity was 8.24 person-rem and 9,000 RWP-hours, respectively. This is compared to the planned initial estimate of 4.60 person-rem and 6,987 RWP-hours. This

Radiation Work Permint and procedure violation was documented in the licensees corrective action program as Condition Reports CR-GGNS-2012-04288 and CR-GGNS-2012-12401. comply with the RWP to prevent unplanned and unintended collective doses was a performance deficiency. This performance deficiency was more than minor because it affected the Occupational Radiation Safety Cornerstone attribute of Program and Process in that the failure to adequately implement ALARA procedures caused the collective radiation dose for the job activity to exceed the planned dose by more than 50 percent. In addition, this type of issue is addressed in Example 6.i of IMC 0612, Appendix E, Using the Occupational Radiation Safety Significance Determination Process, the inspector determined this performance deficiency to be a non-cited violation of very low safety significance because although it involved ALARA planninthree-year average does not exceed 240 person-rem. The violation involved a cross-cutting aspect in the human performance area, work control component, because the licensee did not appropriately coordinate work activities by incorporating actions to address the need for work groups to communicate and coordinate with each other during activities in which interdepartmental coordination was necessary to assure human performance H.3(b)(Section 2RS02).

B. Licensee-Identified Violations

One violation of very low safety significance, which was identified by the licensee has been reviewed by the inspector. Corrective actions taken or planned by the licensee program. This violation and corrective action tracking number is listed in Section 4OA7.

REPORT DETAILS

Summary of Plant Status Grand Gulf Nuclear Station (GGNS) began the inspection period at 100 percent rated thermal power.

On October 21, 2012, the operators reduced power to approximately 87 percent rated thermal power for a planned control rod testing and returned to 100 percent rated thermal power the same day.

On November 8, 2012, the operators reduced power to approximately 93 percent rated thermal power due to a moisture intrusion into the main lube oil and hydrogen seal oil systems that resulted in a clogging of the hydrogen seal oil filters and a procedurally required power reduction due to decrease in seal oil pressure. The licensee changed out the seal oil filters, de-watered the oil systems, and returned to 100 percent rated thermal power on November 9, 2012.

On November 20, 2012, the operators reduced power to approximately 57 percent rated thermal power due to an oil leak on the B reactor feedwater pump. The licensee repaired the leak and returned to 100 percent rated thermal power on November 22, 2012.

On December 8, 2012, the operators began to shutdown and cool down the plant to perform planned outage 19-01 to fix some long standing balance of plant issues, including air in leakage to the condenser and a failed open second stage moisture separator drain valve. The licensee commenced plant startup on December 14, 2012, and achieved 100 percent rated thermal power after final control rod pattern was achieved on December 21, 2012.

On November 20, 2012, the inspectors observed the performance of on-shift licensed in a period of heightened activity due to an unplanned downpower from 100 percent to 57 percent for an emergent repair of an oil leak on the B reactor feedwater pump. The Pre-job brief Reactivity management brief Power reduction via recirculation pump flow reduction Power reduction via control rod manipulations including EN-OP- and other operations department policies. As part of this inspection activity, the inspectors also observed the oof the power-to-flow map and awareness power-to-flow map to ensure that the plant was operated within the analyzed region. The inspector also independently verified that the plant was operated within the analyzed region of the power-to-flow map as the power was being reduced from 100 percent to 57 percent. This inspection activity constitutes the completion of one Operating Experience Smart Sample (OpESS) FY2007-BWR Core Power/ Flow Map - Supplemental These activities constitute completion of one quarterly licensed-operator performance sample as defined in Inspection Procedure 71111.11.

b. Findings

No findings were identified.

1R12 Maintenance Effectiveness

Main article: IP 71111.12

a. Inspection Scope

The inspectors evaluated degraded performance issues involving the following risk significant systems: Auxiliary building (T10) Residual heat removal system (E12) Suppression pool makeup system (E30) 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 three quarterly maintenance effectiveness samples as defined in Inspection Procedure 71111.12-05.

b. Findings

(1) Failure to Make Timely Corrective Actions to Repair the Degraded Auxiliary Building Water Intrusion Barrier

Introduction.

The inspectors identified a Green non-cited violation of 10 CFR 50, promptly correct a condition adverse to quality. Specifically, the auxiliary building water-intrusion barrier has been in a degraded condition since April 2004.

Description.

The seismic category 1 containment structures incorporated into the design of Grand Gulf Nuclear Station are the containment building (primary containment), auxiliary building (secondary containment), and enclosure building. The auxiliary building completely encircles the containment building from base mat to mid height and houses normal and safety related equipment. The auxiliary building, in conjunction with the standby gas treatment system, is designed to limit the thyroid dose and whole body dose to within the guidelines of 10 CFR Part 100 by reaching and maintaining a negative pressure of 1/4 inch water column within 120 seconds. The enclosure building is a limited leakage, steel framed, seismic category 1 structure that completely encloses the portions of the containment building above the auxiliary building roof levels and is designed to limit the leakage of radioactive material into the environment during a loss of coolant accident. To maintain the required leakage limits, a water intrusion barrier, in the form of a flexible seal, is provided around the entire periphery of the enclosure/auxiliary building interface. The occurrence of water intrusion into the auxiliary building is evidence that the water intrusion barrier is degraded. Although the standby gas treatment system has passed its surveillance requirements of achieving and maintaining the designed negative pressure, continued degradation of the flexible seal could challenge the standby gas treatment systems surveillance requirements. On October 1, 2012, the inspectors reviewed Condition Report CR-GGN-2012-10314, which described water leaking into the auxiliary building following a heavy rain storm. The inspectors performed a detailed historical review of water intrusion into the auxiliary building and found 18 condition reports had been written between April 2004 and August 2012 identifying occurrences of water leaking into the auxiliary building. The inspectors also found that the majority of the condition reports written were closed to Work Order The licensee entered this issue in their corrective action program as Condition Report CR-GGN-2012-10314. Corrective actions included generating Work Order 318398 and delegating funds to repair the water intrusion barrier at the next available opportunity.

Analysis.

The failure to promptly correct a condition adverse to quality is a performance deficiency. The inspectors used Inspection Manual Chapter 0612, Appendix B, to determine that the finding is more than minor because if left uncorrected, the condition of a degraded auxiliary building water intrusion barrier could lead to a more significant safety concern. Specifically, continued degradation of the water intrusion barrier could lead to the auxiliary building (secondary containment) being degraded in that the standby gas treatment system would not be able to achieve and maintain the design negative pressure of 1/4 inch water column within 120 seconds.

Using Inspection determined that the finding affected the Barrier Integrity Cornerstone. In accordance ficance Determination very low safety significance (Green) because the finding only represents a degradation of the radiological barrier function provided for the auxiliary building and standby gas treatment system. The inspectors determined that the apparent cause of this finding was the licensee had failed to classify the degraded water intrusion barrier as a condition adverse to quality that warranted prompt correction. Therefore, the finding had a cross-cutting aspect in the problem identification and resolution area, corrective action program component because the licensee failed to properly classify conditions adverse to quality P.1(c).

Enforcement.

10 CFR 50, Apmeasures shall be established to assure that conditions adverse to quality, are promptly identified and corrected. Contrary to the above, measures establish by the licensee did not assure that conditions adverse to quality, were promptly identified and corrected. Specifically, the licensee initiated 18 condition reports from April 2004 through August 2012 identifying auxiliary building water intrusion barrier degradation as evidenced by water in-leakage and failed to implement corrective actions to address the degraded barrier. As an immediate corrective action, the licensee generated Work Order 318398 and delegated funds to repair the water-intrusion barrier at the next available opportunity. This violation is being treated as a non-cited violation (NCV), consistent with Section 2.3.2 of the Enforcement Policy because it was of very low safety significance (Green) and it was entered into the CR-GGN-2012-10314 to address recurrence: NCV 05000416/2012005-01Make Timely Corrective Actions to Repair the Degraded Auxiliary Building Water Intrusion Barrier. (2) Failure to Adequately Monitor the Condition of the Auxiliary Building Water Intrusion Barrier

Introduction.

The inspectors identified a Green non-cited violation of 10 CFR 50.65(a)(1), involving the failure to adequately monitor the performance of the auxiliary building water intrusion barrier.

Description.

On October 1, 2012, the inspectors reviewed Condition Report CR-GGN-2012-10323, which described water leaking into the auxiliary building following a heavy rain storm. During the review, the inspectors determined the auxiliary building roof maintenance rule program with the monitoring criteria of zero occurrences of water intrusion barrier degradation. The inspectors performed a detailed historical review of water intrusion into the auxiliary building and found 18 condition reports had been written between April 2004 and August 2012 identifying the occurrence of auxiliary building water intrusion barrier degradation as evidenced by water leaking into the auxiliary building. The inspectors also found that the licensee had not performed any evaluation of the water-maintenance rule program. When the inspectors brought this conc licensee entered this issue in their corrective action program as Condition Report CR-GGN-2012-11740. Corrective actions included initiating Condition Report CR-GGN-2012-12286, in which the licensee concluded the degraded water-intrusion barrier was a Maintenance Rule Functional Failure and required further evaluation to determine if the barrier should be classified a(1).

Analysis.

The failure to monitor the performance of the auxiliary building water intrusion barrier in accordance with the maintenance rule program is a performance deficiency. The inspectors used Inspection Manual Chapter 0612, Appendix B, to determine that the finding is more than minor because if left uncorrected, the failure to monitor the performance of the auxiliary building water intrusion barrier in accordance with the maintenance rule program could lead to a more significant safety concern. Specifically, continued unmonitored degradation of the water intrusion barrier could compromise the integrity of the secondary containment function of the auxiliary building. Using inspectors determined that the finding affected the Barrier Integrity Cornerstone. In finding had a very low safety significance (Green) because the finding only represents a degradation of the radiological barrier function provided for the auxiliary building and standby gas treatment system. The inspectors determined that the apparent cause of this finding was the licensee had failed to recognize that the auxiliary building water intrusion barrier was scoped into their Maintenance Rule program with the monitoring criteria of zero occurrences of water intrusion barrier degradation. Therefore, the finding had a cross-cutting aspect in the human performance area, work practices component because the licensee did not follow maintenance rule program procedures H.4(b).

Enforcement.

Configuration management, including maintenance of defense in depth, is commensurate with the outage safety plan for key safety functions and compliance with the applicable technical specifications when taking equipment out of service.

Status and configuration of electrical systems to ensure that technical specifications and outage safety-plan requirements were met.

Monitoring of decay heat removal processes, systems, and components.

Verification that outage work was not impacting the ability of the operators to operate the spent fuel pool cooling system.

Reactor water inventory controls, including flow paths, configurations, and alternative means for inventory addition, and controls to prevent inventory loss.

Controls over activities that could affect reactivity.

Maintenance of secondary containment as required by the technical specifications.

Startup and ascension to full power operation.

Specific documents reviewed during this inspection are listed in the attachment. These activities constitute completion of one other outage inspection sample as defined in Inspection Procedure 71111.20-05.

b. Findings

Introduction.

The inspectors reviewed a self-revealing non-cited violation of 10 CFR 50, Appendix B, Criterion V, ,failure to complete preventive maintenance tasks on the high pressure core spray division III diesel generator output breaker in accordance with the corresponding preventive maintenance task template. Description On June 5, 2012, the high pressure core spray division III diesel generator output breaker (152-1701) failed to close during a surveillance test. Troubleshooting revealed that the breaker had failed to close because of intermittent high resistance on the current relay contacts. Through the subsequent evaluation documented in Condition Report CR-GGN-2012-07922, the licensee determined that the apparent cause of the relay failure was age-related and/or cycle-related degradation due to a lack of an appropriate preventive-maintenance task for the relay. More specifically, although the licensee had set a recurring preventive-maintenance task to refurbish/replace the breaker (using preventive maintenance task PMRQ 50018212-02) every 12 +/- 25% years, and had last completed that task in 1996 such that it was next due on November 2, 2008 (or November 2, 2011 with a 25% extension), the licensee did not complete that task when it was due. Instead, the licensee deferred that task until September, 2012. To review the bases for the preventive maintenance tasks performed using PMRQ 50018212-02, the inspectors noted that Preventive Maintenance -Switchgear-Medium Voltage , discusses switch and relay contact failures and states, in part, develop over time although a trouble-free period of 10 years should be obtained under mild service conditions. Switch and relay contact failure may be avoided by measuring the contact resistance at the The inspectors therefore considered that the licensee likely would have prevented the June 5, 2012, breaker failure if they had performed preventive maintenance task PMRQ 50018212-02 in 2011, and if they had measured the current relay contact resistance at that time. The licensee entered this issue in their corrective action program as Condition Report CR-GGN-2012-07992. Their immediate corrective actions included replacing the failed control relay and restoring operability to the division III diesel generator. The long-term corrective actions included revising the breaker refurbishment/replacement procedure to replace the current relay and changing the procedure frequency to once every 10 years versus once every 12 years.

Analysis.

maintenance tasks on the high pressure core spray division III diesel generator output breaker in accordance with the corresponding preventive maintenance task template was a performance deficiency. Using the inspectors determined that this performance deficiency was more than minor and is therefore a finding because it is associated with the equipment performance attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, this failed control relay caused the subject breaker to fail to close during the division III diesel generator monthly surveillance on June 5, 2012.

The inspectors used NRC Inspection Manual Chapter 0609, Attachment 4, "Initial Characterization of Findings," to determine that the issue affected the Mitigating System Cornerstone. Because the finding pertained only to a degraded condition while the plant was shutdown, the inspectors used Operations Significance Determination ProcessChecklisRefueling Operation Time to Boil > 2 Hours: RCS to determine that the finding was of very low safety significance because it did not increase the likelihood of a loss of reactor coolant system inventory; did not degrade the not affect the safety/relief valves (Green). The inspectors determined that the cause of this finding was a latent issue that is not reflective of current performance, therefore no cross-cutting aspect was identified.

Enforcement.

10 CFR 50, Appendix B, Criterion V, that activities affecting quality shall be accomplished in accordance with procedures.Contrary to this requirement, an activity affecting quality was not accomplished in accordance with procedures. Specifically, preventive maintenance tasks on the high pressure core spray division III diesel generator output breaker are prescribed by preventive maintenance task PMRQ 50018212-02, on November 2, 2011. The licensee did not accomplish preventive maintenance tasks on the high pressure core spray division III diesel generator output breaker in accordance with PMRQ 50018212-02, in that PMRQ 50018212-02 required the licensee to refurbish/replace the breaker before November 2, 2011, and the licensee did not do so. As a result, on June 5, 2012, that breaker failed to close due current relay contacts. As an immediate corrective action, the licensee replaced the failed relay and restored operability to the division III diesel generator. This violation is being treated as a non-cited violation (NCV), consistent with Section 2.3.2 of the Enforcement Policy because it was of very low safety significance (Green)corrective action program as CR-GGN-2012-07992 to address recurrence.

(NCV 05000416/2012005-03, Failure to Perform Preventive Maintenance on GE Magne-Blast Circuit Breakers in Accordance With the Corresponding Preventive Maintenance Task Template).

1R22 Surveillance Testing

Main article: IP 71111.22

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 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.

November 15, 2012, automatic depressurization system electrical surveillance November 29, 2012, turbine control valve fast closure functional test for channels B and D Specific documents reviewed during this inspection are listed in the attachment. These activities constitute completion of two surveillance testing inspection samples as defined in Inspection Procedure 71111.22-05.

b. Findings

No findings were identified.

Cornerstone:

Emergency Preparedness

1EP4 Emergency Action Level and Emergency Plan Changes

Main article: IP 71114.04

a. Inspection Scope

The NSIR headquarters staff performed an in-office review of the latest revisions of various Emergency Plan Implementing Procedures (EPIPs) and the Emergency Plan located under ADAMS accession number ML12265A082 as listed in the Attachment. The licensee determined that in accordance with 10 CFR 50.54(q), the changes made in the revisions resulted in no reduction in the effectiveness of the Plan, and that the revised Plan continued to meet the requirements of 10 CFR 50.47(b) and Appendix E to 10 CFR 50. The NRC 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.

1EP6 Drill Evaluation

Main article: IP 71114.06

.1 Emergency Preparedness Drill Observation

a. Inspection Scope

The inspectors evaluated the conduct of a routine licensee emergency drill on October 16, 2012, to identify any weaknesses and deficiencies in classification, notification, and protective action recommendation development activities. The inspectors observed emergency response operations in the Emergency Operating Facility (EOF) and the Technical Support Center (TSC), 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 were identified.

RADIATION SAFETY

Cornerstone:

Occupational and Public Radiation Safety

2RS0 2 Occupational ALARA Planning and Controls

Main article: IP 71124.02

a. Inspection Scope

This area was inspected to assess performance with respect to maintaining occupational individual and collective radiation exposures as low as is reasonably achievable (ALARA). The inspector used the requirements in 10 CFR Part 20, the technical es required by technical specifications as criteria for determining compliance. During the inspection, the inspector interviewed licensee personnel and reviewed the following items: Site-specific ALARA procedures and collective exposure history, including the current 3-year rolling average, site-specific trends in collective exposures, and source-term measurements ALARA work activity evaluations/post job reviews, exposure estimates, and exposure mitigation requirements The methodology for estimating work activity exposures, the intended dose outcome, the accuracy of dose rate and man-hour estimates, and intended versus actual work activity doses and the reasons for any inconsistencies Records detailing the historical trends and current status of tracked plant source terms and contingency plans for expected changes in the source term due to changes in plant fuel performance issues or changes in plant primary chemistry Radiation worker and radiation protection technician performance during work activities in radiation areas, airborne radioactivity areas, or high radiation areas Audits, self-assessments, and corrective action documents related to ALARA planning and controls since the last inspection Specific documents reviewed during this inspection are listed in the attachment. These activities constitute completion of the one required sample as defined in Inspection Procedure 71124.02-05.

b. Findings

(1) Failure to Adequately Plan and Control Work Activities to Maintain ALARA

Introduction.

An inspector reviewed a self-revealing Green finding of very low safety significance because during Refueling Outage 18, the licensee did not adequately plan and control work activities for the design and replacement of the new fuel pool cooling heat exchangers under Radiation Work Permit (RWP) 2012-1086.

Description.

While reviewing the post ALARA review package for RWP 2012-1086 from Refueling Outage 18, Extended Power Upgrade, the inspector identified that the anned and unintended collective doses related to the design and replacement of the new fuel pool cooling heat exchangers. Specifically, outage personnel did not perform adequate pre-outage walkdowns which resulted in significant unplanned collective exposure. The actual collective dose and hours for the project was 23.9 person-rem and 12,237 RWP-hours, respectively. This is compared to the initial estimate of 3.74 person-rem and 1,905 RWP-hours. Initially, there were approximately 165 work activities, almost equally split between 2 tasks on RWP 2012-1086, Revision 0. However, RWP 2012-1086 was revised eight times during the fuel pool cooling heat exchanger replacement project due to increased work scope. According to the post-job ALARA review, the project began with only 40 percent of its work activities planned out and developed on the outage schedule. An additional 60 percent of the project work activities were added as increased scope after the outage began. The inspector noted that 63 Engineering Change Notice (ECNs) were added to the fuel pool cooling heat exchanger replacement project as increased scope. The implementation of the 63 ECNs caused the projected work hours to increase from 975 hours0.0113 days 0.271 hours 0.00161 weeks 3.709875e-4 months to 7,295 hours0.00341 days 0.0819 hours 4.877645e-4 weeks 1.122475e-4 months (a 748 percent increase). This increase in work scope was not fully understood nor justified, and resulted in unintended collective dose. Some causes for the dose overages were higher dose rates than expected, longer work durations than expected, and more added work scope than expected. However, there was no documentation in the ALARA package that justified the dose estimate increases resulting from changes in the job scope, duration, and work area dose rates. The inspector determined that the performance deficiency that led to the increased collective dose was not following the written ALARA Program procedure EN-RP-110, Revision 7, for planning and work controls and procedure EN-DC-. EN-RP-110, Section 4.0.8, states, in part, that Planning and Outage Groups Responsibilities include: Providing accurate work site person-hours and accurate work locations for ALARA planning purposes. Provide detailed work plans to allow for ALARA planning to designate adequate radiological controls.

EN-DC-115, Section 5.3.4(e), states, in part, that Radiation Protection / ALARA considerations shall be identified early in the engineering change process (by 10 percent design milestone). Radiation Protection / ALARA considerations should be addressed as an integral part of the design configuration, material selection, and implementation plan. Apparent Cause Evaluation (ACE) in CR-GGNS-2012-09011 evaluated why the outage ALARA goal was exceeded by 114 person-rem. The ACE stated, in part, that the milestone walkdowns of outage work packages and execution were not completed in a timely manner and in accordance with procedure EN-FAP-OU-

Analysis.

The failure to appropriately use the ALARA Planning and Controls procedure to prevent unplanned and unintended collective doses was a performance deficiency. This performance deficiency was more than minor because it affected the Occupational Radiation Safety Cornerstone attribute of Program and Process in that the failure to adequately implement ALARA procedures caused the collective radiation dose for the job activity to exceed the planned dose by more than 50 percent. In addition, this type of issue is addressed in Example 6.j of IMC 0612, Appendix Using the Occupational Radiation Safety Significance Determination Process, the inspector determined this performance deficiency to be a finding of very low safety latest rolling three-year average does not exceed 240 person-rem. This finding has a cross-cutting aspect in the human performance area, work control component, because the licensee failed to evaluate the impact of work scope change on human performance and interdepartmental communication and coordination prior to commencing work activities. Specifically, there was inappropriate coordination and communication of work activities between work groups H.3(b).

Enforcement.

No violation of regulatory requirements occurred. However, this performance deficiency is directly rs failure to meet its expectation to fully implement ALARA outage, planning, and control procedures. This finding and the procedural concern were entered into the corrective action program as CR-GGNS-2012-09011 and CR-GGNS-2012-12396: FIN 05000416/2012005-04, Failure to Adequately Plan and Control Work Activities to Maintain ALARA. (2) Failure To Follow Radiation Work Permit Requirements During Reactor Cavity High Water Operations

Introduction.

An inspector reviewed a self-revealing Green non-cited violation of Technical Specification 5.4.1 for failure to comply with radiological exposure controls specified in Radiation Work Permit (RWP) 2012-

Description.

Radiation exposure controls in the RWP required the licensee to verify that fuel pool cleanup (demineralizers) was inservice, and if dose rates increased by more than 0.2 millirem/hour, change the resins. During reactor cavity operations, both fuel pool demineralizer trains were inoperable at least 25 days. In addition, the dryer separator pool and reactor cavity were isolated from the fuel pool clean up system. Consequently, general area radiation levels on the reactor cavity floor increased from 0.4 millirem/hour to 6.0 millirem/hour. However, the resins were not changed as required. The actual collective dose and hours for the work activity was 8.24 person-rem and 9,000 RWP-hours, respectively. This is compared to the initial estimate of 4.60 person-rem and 6,987 RWP-hours.

Analysis.

accordance with the RWP was the performance deficiency that caused unplanned and unintended collective doses. This performance deficiency was more than minor because it affected the Occupational Radiation Safety Cornerstone attribute of Program and Process in that the failure to adequately implement ALARA procedures caused the collective radiation dose for the job activity to exceed the planned dose by more than 50 percent. In addition, this type of issue is addressed in Example 6.i of IMC 0612, Using the Occupational Radiation Safety Significance Determination Process, the inspector determined this performance deficiency to be a non-cited violation of very low safety significance because although it -year average does not exceed 240 person-rem. This violation involved a cross-cutting aspect in the human performance area, work control component, because the licensee did not appropriately coordinate work activities by incorporating actions to address the need for work groups to communicate and coordinate with each other during activities in which interdepartmental coordination was necessary to assure human performance H.3(b).

Enforcement.

Technical Specification 5.4.1 states that written procedures shall be established, implemented, and maintained covering the applicable procedures recommended in Regulatory Guide 1.33, Revision 2, Appendix A, 1978. Section 7.e(1). Contrary to the above, during Refueling Outage 18, written procedures were not established, implemented, and maintained covering the applicable procedures recommended in Regulatory Guide 1.33, Revision 2, Appendix A, 1978. Specifically, Appendix A of Regulatory Guide 1.33 lists procedures for radiation exposure and access controls; licensee procedure EN-RP-is a procedure for radiation exposure and access controls and requires, in part, that individuals comply with all requirements of the procedure and radiation work permit (RWP) instructions when performing radiological work; RWP 2012-d the licensee to verify that fuel pool cleanup system demineralizers were in-service and to change the resins if dose rates increased by more than 0.2 millirem/hour; and from March 13 through April 10, 2012, fuel pool cleanup system demineralizers were not in service. In addition, after dose rates increased by more than 0.2 millirem/hour, the resins were not changed. Consequently, general area radiation levels on the reactor cavity floor increased from 0.4 millirem/hour to 6.0 millirem/hour. This violation was documented in the licensees corrective action program as condition reports CR-GGNS-2012-04288 and CR-GGNS-2012-12401. This issue is being treated as a non-cited violation, consistent with Section 2.3.2 of the NRC Enforcement Policy: NCV 05000416/2012005-05, Failure To Follow the Radiation Work Permit Requirements During Reactor Cavity High Water Operations.

2RS0 4 Occupational Dose Assessment

Main article: IP 71124.04

a. Inspection Scope

This area was inspected to: (1) determine the accuracy and operability of personal methods for determining total effective dose equivalent; and (3) ensure occupational dose is appropriately monitored. The inspector used the requirements in 10 CFR Part technical specifications as criteria for determining compliance. During the inspection, the inspector interviewed licensee personnel, performed walkdowns of various portions of the plant, and reviewed the following items: External dosimetry accreditation, storage, issue, use, and processing of active and passive dosimeters The technical competency and adequacy of the licprogram Adequacy of the dosimetry program for special dosimetry situations such as declared pregnant workers, multiple dosimetry placement, and neutron dose assessment Audits, self-assessments, and corrective action documents related to dose assessment since the last inspection Specific documents reviewed during this inspection are listed in the attachment. These activities constitute completion of the one required sample as defined in Inspection Procedure 71124.04-05.

b. Findings

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 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 issues within the work management process. The specific items documented in the condition reports were reviewed by the inspectors, and it was determined that all were minor in nature. The inspectors determined that the licensee had properly identified deficiencies in tagout reviews, emergent work requests, work order impact statements and entered each issue in the corrective action process. The work management issues have resulted in various plant impacts, most notably an impact on resources due to repreforming work orders and tagout reviews. The inspectors determined that although there was an abnormal increase in work management issues, the licensee did appropriately address the issues in the corrective action program.

.4 Selected Issue Follow-up Inspection:

4160 Vac Preventative Maintenance Procedures

a. Inspection Scope

The inspectors chose to review Condition Reports CR-GGN-2012-08885, CR-GGN-2012-9035, and CR-GGN-2012-09111, which addressed programmatic conditions associated with 4160 Vac breaker testing described as The associated PM, 07-S-12-61, Inspection of GE Magna Blast Circuit Breaker, does not have any specific steps that would clean or inspect auxiliary contacts though section 7.1.4 requires a The inspectors reviewed the associated corrective actions for CR-GGN-2011-08885, CR-GGN-2012-9035, and CR-GGN-2012-09111. The inspectors also reviewed associated procedures and interviewed several members of the involved licensee staff. Documents reviewed are listed in the attachment.

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

b. Findings

No findings were identified.

.5 In-depth Review of Operator Workarounds

a. Inspection Scope

document, track, and resolve operational challenges. Inspection activities included, but were not limited to, a review of the cumulative effects of the operator workarounds, operator burdens, control deficiencies, control room alarms and long standing danger and caution tags on system availability and the potential for improper operation of the system, for potential impacts on multiple systems, and on the ability of operators to respond to plant transients or accidents. The inspectors performed a review of the cumulative effects of operator workarounds, operator burdens, control deficiencies, control room alarms and long standing danger and caution tags. The documents listed in the attachment were reviewed to accomplish the objectives of the inspection procedure. The inspectors reviewed current operational challenge records to determine whether the licensee was identifying operator challenges at an appropriate threshold, had entered them into their corrective action program, and had proposed or implemented appropriate and timely corrective actions, which addressed each issue. Reviews were conducted to determine if any operator challenge could increase the possibility of an initiating event, if the challenge was contrary to training, required a change from long-standing operational practices, or if it created the potential for inappropriate compensatory actions. Additionally, the inspectors review two licensee assessments of their process to determine if they were properly assessing the issues and determining long term corrective actions to reduce the operator challenges. Daily plant and equipment status logs, degraded instrument logs, and operator aids or tools being used to compensate for material deficiencies were also assessed to identify any potential sources of unidentified operator workarounds. These activities constitute completion of one operator workarounds annual inspection sample as defined in Inspection Procedure 71152.

b. Findings

No findings were identified.

4OA3 Followup of Events and Notices of Enforcement Discretion

Main article: IP 71153

.1 (Closed) Licensee Event Report 05000416/2012-001-00: Inadequate to Meet the Requirements o

a. Inspection Scope

On November 19, 2009, the licensee failed to ensure that Technical Specification (TS) Surveillance Requirement (SR) 3.5.3.1 was met. The 2009 NRC Problem Identification and Resolution (PI&R) Inspection identified a concern that the surveillance procedure used to verify the reactor core isolation cooling (RCIC) system piping is filled with water from the pump discharge valve to the injection valve was inadequate, in that it did not have a basis (calculation) for the two-minute venting criterion and that there was no visual means of confirming water flow through the vent line when performing venting of the RCIC system. The 2009 PI&R inspection team documented the concern as a non-cited violation in section 4OA2.5a of report 2009008. During the 2011 PI&R inspection, the team reviewed the non-cited violation identified by the 2009 PI&R inspection and determined that corrective actions were not taken in a timely enough manner to meet the requirements of TS (SR) 3.5.3.1, which resulted in the RCIC system being inoperable for a period of time in excess of TS allowance, which resulted in a condition prohibited by TS. The licensee confirmed full compliance with TS SR 3.5.3.1 by performing ultrasonic testing on February 5, 2010, which verified the piping was full of water.

The cause of the occurrence was an inadequate surveillance procedure acceptance criterion, which resulted in the requirements of SR 3.5.3.1 not being met. The contributing cause was the lack of technical rigor in evaluation of a potential inadequate surveillance procedure. Corrective actions included using ultra sonic testing to verify the RCIC system piping was full of water and revising RCIC surveillance procedures to incorporate ultra sonic testing to verify the piping is full of water. Documents reviewed as part of this inspection are listed in the attachment. The enforcement aspects of this finding were discussed in NRC Inspection Report 05000416/2011006 in Section 4OA2.5a. This LER is closed.

b. Findings

No findings were identified.

.2 (Closed) Licensee Event Report 05000416/2012-002-00: Manual Reactor Scram Due to a Steam Supply Motor Operated Valve Failure that Resulted in the Inability to Maintain Reactor Water Level

a. Inspection Scope

On February 19, 2012, at 7:04 p.m., Grand Gulf Nuclear Station (GGNS) was in Mode 1 operating at approximately 22 percent power during a planned plant shutdown with the reactor feed pump A secured when a manual reactor scram was initiated due to decreasing reactor pressure vessel (RPV) water level. The cause of the event was a combination of the isolating steam valve to the reactor feed pump B being out of position, 90 percent closed, which isolates the main steam header from reactor feed pump B and a planned power reduction. The power reduction resulted in the turbine bypass valves (TBPV) opening as designed, then when the TBPVs reached 16 percent open, reactor feed pump B began to decrease in speed. This resulted in a decreasing level in the RPV. As level decreased, the control room supervisor directed a manual scram be inserted prior to reaching the low level scram set point (+11.4 inches narrow range). After the scram, reactor core isolation cooling (RCIC) was manually started to inject water into the RPV and reactor feed pump A was restarted to restore and maintain reactor water level. The appropriate off-normal event procedures were entered to mitigate the transient with all systems responding as designed. All control rods inserted to shut down the reactor. The cause of the event was that equipment deficiencies preventing the high pressure steam inlet valve to B RFPT from fully opening. Corrective actions included reactor water level was restored and the plant was placed in a stable condition. The licensee conducted troubleshooting of the steam supply valve and repaired it during the refueling outage. Other contributing causes were evaluated and corrective actions were develop to address these process issues. Documents reviewed as part of this inspection are listed in the attachment. The enforcement aspects of this finding were discussed in NRC Inspection Report 05000416/2012002 in Section

4OA3 and documented below.

This LER is closed.

b. Findings

Introduction.

The inspectors identified a Green non-cited violation of 10 CFR 50, Procedure EN-LI-Revision 18, in that they failed to evaluate the risk significances and develop action plans to address equipment identified during their extent-of-condition review for a post-scram root-cause analysis.

On June 13, 2012, during startup activities for Unit 1 with the reactor in Mode 1 operating at approximately 12 -15 percent (%) power, the Average Power Range Monitor (APRMs) were indicating a reactor power level lower than expected for the plant condition. The licensee determined that during Refueling Outage 18 (RF18) the APRMs were set to indicate flux lower than the actual power level. This resulted in the system being inoperable during Mode 2 due to the APRM Neutron Flux High - Setdown scram setpoint being outside of Technical Specification (TS) 3.3.1.1 Reactor Protection System (RPS) Instrumentation limits. This condition existed when Mode 2 was initially entered on June 6, 2012 until Mode 1 was entered on June 13, 2012. This condition was limited to the Power Range Neutron Monitoring (PRNM) system. During startup in Mode 2, the intermediate range monitors (IRM) and the high reactor pressure trip functions were operable. Therefore, reactor power transients would have been mitigated by these functions. The APRM Neutron Flux High - Setdown function is not directly credited in any safety analyses, and this event did not adversely affect plant safety or the health and safety of the public. The apparent cause of this condition was a failure to identify differing operating characteristics between the old system and the new system during the engineering change process. The licensee had been entering the minimum gain for the old APRM instruments, and did not evaluate this practice as part of the engineering change process. The old instruments indicated much higher than actual power at low power levels while the new instruments indicated closer to actual levels. As a result, when the licensee continued to use the minimum gain setting, the new instruments indicated lower than actual power. The licensee conducted an apparent cause evaluation and identified other contributing causes and corrective actions. Documents reviewed as part of this inspection are listed in the attachment. The enforcement aspects of this finding are documented below. This LER is closed.

b. Findings

Introduction.

The inspectors identified a Green non-cited violation of 10 CFR 50, gain settings used on the power range neutron monitoring (PRNM) system in accordance with design requirements. Specifically, prior to June 13, 2012, the licensee used non-conservative gain settings on the average power range monitors (APRMs) and local power range monitors (LPRMs) causing them to indicate flux lower than the actual power level, which resulted in violations of Technical Specifications 3.0.4, 3.3.1.1, and 3.3.2.1.

Description.

On June 13, 2012, during a reactor startup, the licensee discovered that reactor power as indicated by the APRM neutron flux was significantly lower than the apparent power as determined by the heat balance and other indications. The licensee determined that actual power was approximately 12-15 percent while the APRMs indicated 6.5 percent. The licensee immediately validated the heat balance inputs and adjusted APRM and LPRM gains to correct the discrepancy. The licensee reported this event in License Event Report (LER) 05000416/2012-005-00 as a violation of Technical Neutron Flux High Setdown scram function being inoperable. The inspectors reviewed the LER and concluded that the licensee also violated Technical Specification 3.0.4 because they entered Mode 2 with the required function inoperable and did not meet any of the allowable exceptions. Furthermore, the inspectors noted that the Neutron Flux The cause of the technical specification violations was that the licensee had entered incorrect, non-conservative gains into the APRM and LPRM instruments. During Refueling Outage 18, the licensee upgraded the PRNM system to a digital General Electric Hitachi designed Nuclear Measurement and Control System (NUMAC) as part of the extended power uprate (EPU). This involved replacing all of the APRM instruments with a new design. The licensee also replaced forty LPRM detectors.

The licensee procedure for initial APRM gain setting directed setting the gain to the minimum possible before instrument calibration, which is performed between 18 percent and 21.8 percent reactor power. The apparent reason for this was that the old instruments did not effectively discriminate gamma flux at low power, and therefore indicated higher than actual values. The licensee used the minimum gain value to prevent a rod withdrawal block prior to calibrating the instruments. The new instruments are more effective at gamma discrimination at low power, and therefore indicate closer to actual flux. The licensee had never established a basis for determining the initial gain settings, did not re-evaluate the continued use of these settings during the design change process, and did not modify the procedures to set a more conservative initial gain setting. The licensee also discovered during their apparent cause evaluation that the initial gain setting they used for the replacement LPRM detectors was incorrect. The licensee had been using 3.000 as the default initial gain setting for uncalibrated LPRMs. However, the vendor recommended default setting was 3.692. Therefore the forty replaced LPRMs were providing a non-conservative signal to the APRMs. As a result of the failure to use conservative gain settings on the LPRMs and APRMs, all APRMs indicated approximately 40-50 percent of actual thermal power when the error was discovered. The APRMs are designed to indicate within tolerances and ensure protective functions specified in the plant design documents. The inspectors determined that the licensee had been using initial gain settings for both the LPRMs and APRMs that had not been evaluated or analyzed to ensure these design requirements were being met. The licensee carried over this practice when implementing their design change for the new system instead of evaluating the settings for the new system. The licensee entered this issue into their corrective action program as Condition Report CR-GGN-2013-00177. The immediate corrective actions included adjusting gain settings for their APRM instruments so they indicated actual core thermal power as determined by the heat balance. The licensee also revised their neutron monitoring procedure to set the initial gains for the APRMs to the maximum value to maintain conservative power indication during future startups and changed their LPRM replacement procedure to use the vendor specified initial gain setting of 3.692 prior to startup.

Analysis.

The failure to ensure that the design basis was correctly translated into specifications, drawings, procedures, and instructions was a performance deficiency. The performance deficiency was more than minor because it affected the design control attribute of the Mitigating Systems Cornerstone and impacted the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the incorrect gain settings led to a violation of technical specification 3.0.4 by rendering the APRM Neutron Flux High Setdown scram function and the Neutron Flux Upscale, Startup control rod block function inoperable prior to entry into Mode 2. In accordance with NRC Inspection Manual Chapter 0609, Attachment 4, "Initial Characterization of Findings," the issue was determined to affect the Mitigating Systems Cornerstone. In accordance with NRC Inspection Manual Chapter 0609, Appendix (SDP) have very low safety significance (Green) because although the finding affected a single reactor protection system (RPS) trip signal to initiate a reactor scram, it did not affect the function of other redundant trips or diverse methods of reactor shutdown, did not involve control manipulations that unintentionally added positive reactivity, and did not result in a mismanagement of reactivity by operators. This finding was not assigned a cross-cutting aspect because the performance deficiency occurred in the past and is not reflective of current licensee performance.

Enforcement.

10 CFR 50, Appendix B, Criterion III, requires, in part, measures shall be established to assure that the design basis is correctly translated into procedures. Contrary to the above, prior to June 13, 2012, measures established by the licensee did not assure that the design basis was correctly translated into procedures. Specifically, those measure did not assure that the bases for the APRM and LPRM gain settings were correctly translated into maintenance and operating procedures. The licensee immediate actions were to set appropriate gain settings for their APRM instruments and submit an LER for the violation of technical specifications. This violation is being treated as an NCV, consistent with Section 2.3.2 of the Enforcement Policy, because it was of very low safety significance (Green) and was entere-GGN-2013-00177 to address recurrence NCV 05000416/2012005-07APRM and LPRM Instruments in Accord

.6 (Closed) Licensee Event Report 05000416/2012-006-00: Inventory Discrepancy

a. Inspection Scope

On July 25, 2012, at 3:34 p.m. the licensee determined that a source range monitor detector was not in its expected storage location. This met the reporting criteria in 10 CFR 72.74 and 10 CFR 74.11 as a loss of special nuclear material. The Source Range Monitor (SRM) detector contained an estimated maximum activity of 0.187 microcuries, which is equivalent to 0.00292 grams of all Special Nuclear Material (SNM) isotopes, including U-235. This also met the reporting criteria in 10 CFR 20.2201 (a) (1) (ii) as a loss of licensed material of a quantity greater than ten times that specified in Appendix C to 10 CFR Part 20. According to special nuclear material (SNM) inventory sheets, the SRM detector was expected to be stored in an SNM Item Control Area (ICA) on the 208 foot elevation of the Auxiliary building. However, during performance of the annual physical inventory of SNM, the SRM detector could not be located. Subsequent investigations concluded that the SRM was removed from the 208 foot elevation of the Auxiliary building SNM ICA during clean up at the end of Refueling Outage 18, along with other material that was stored in the area, and discarded as radioactive waste. The inspector reviewed the licensee event report, NRC Event Notification 48133, and The inspectors verified that the cause of the event was identified, radiological consequences were assessed, and that corrective actions were reasonable. The enforcement aspects of this violation are discussed in Section

4OA7 of this report.

This licensee event report is closed.

.7 (Closed) Licensee Event Report 05000416/2012-007-00: Standby Service Water System Administratively Inoperable For A Period Longer Than Allowed By Technical

a. Inspection Scope

On August 18, 1987, a 10 CFR 50.59 safety evaluation was performed for a change to the Final Safety Analysis Report (FSAR) to relax methodology for single passive failures of standby service water components. On July 19, 2012, with the plant in mode 1 at approximately 100 percent power, during the inspectors reviewed FSAR change NPEFSAR 87/0067 and determined prior NRC approval of the change was required. This resulted in SSW being administratively inoperable for a period longer than allowed by technical specifications due to relaxation of the passive failure methodology without prior NRC approval. The licensee determined that the event posed no threat to public health and safety as there had been no passive failures that had challenged operability. The licensee implemented compensatory measures and they have submitted a request to revise the SSW passive failure methodology to the NRC. Procedures are in place to prevent recurrence.

The apparent cause for this issue is misapplication of industry documents that were used for justification in the 10 CFR 50.59 safety evaluation due to lack of understanding their applicability. The NUREG-0138 document did not specifically address single passive failures for systems such as the standby service water system. These documents were based on single passive failures of emergency core cooling systems. Therefore, the licensee should have responded with a "YES" answer to questions 1 and 2 in the safety evaluation, which would have required prior NRC approval before these changes were made to the GGNS FSAR. As stated above the licensee has submitted a request to the NRC seeking approval of changes to the standby passive failure methodology and has implement compensatory measures as an interim actions. Documents reviewed as part of this inspection are listed in the attachment. The enforcement aspects of this finding were discussed in NRC Inspection Report 05000416/2012008 in Section 1R21.2.3. This LER is closed.

b. Findings

No findings were identified.

.8 Reactor Scram Following a Phase A Unit Differential Relay Trip

a. Inspection Scope

On December 29, 2012 at approximately 12:18 a.m, the plant scrammed from 100 percent power. Upon responding to the site at 2:30 a.m., the inspectors learned that the initial cause of the scram appeared to be the phase A unit differential relay tripping, causing a generator lockout relay to trip, which resulted in a turbine trip and reactor scram due to power being greater than 40 percent. The inspectors verified that all the control rods were i, and that reactor water level lowered to approximately +7 inches narrow range (approximately 174 inches above top of active fuel) and being maintained with reactor feedwater pump turbine A at approximately +36 inches using startup level control. Reactor vessel pressure increased on the trip from its nominal value of approximately 1035 psig to approximately 1116 psig, and this caused the low-low level set to initiate as expected.

Additionally, the valve B21-F047A (automatic depressurization system safety relief valve) lifted (normal mechanical lift pressure is 1113 psig), but the valve did not close when it should have, and lowered reactor pressure vessel pressure to approximately 675 psig. The licensee entered their procedures to shut the valve, and when they took the control switch to close, the valve closed. They also removed the fuses for this valve. The licensee determined that the mechanical relief function for the valve was inoperable but the safety relief function and automatic depressurization function were still operable. The licensees maintained the plant in a hot shutdown condition until restart. The inspectors reviewed the force outage list with plant staff and monitored troubleshooting of plant issues. The licensee could not duplicate the condition with the phase A unit differential relay through testing but elected to replace this relay prior to restart. Additionally the licensee placed recording equipment on the various relays to monitor response during startup. Specific documents reviewed during this event follow-up 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

.1 Power Uprate Related Inspection Activities: Licensee Actions for New or More Likely Initiating Events (IP 71004)

a. Inspection Scope

During the inspection period, the inspectors verified that the licensee has taken all required actions to address the effects of new or more probable initiating events as stated in the license amendment, licensee commitments, or in the safety evaluation report. The inspectors verified that the applicable Off-Normal Event Procedures, Emergency Procedures, and Severe Accident Procedures had been revised to incorporate the operational changes made due to the extended power uprate. These activities constitute the completion of one inspection sample as defined in Inspection Procedure 71004, Section 2.01.

b. Findings

No findings were identified.

.2 Power Uprate Related Inspection Activities: Completion of the Grand Gulf Nuclear Station Extended Power Uprate Inspection Plan (IP 71004)

a. Inspection Scope

for inspection. The samples selected were risk-informed and focused on items concerning new integrated plant response characteristics, new operator procedures, and plant safety during any required tests. The inspection effort is summarized below in which each sample, applicable inspection procedure used and report number in which the results were documented are provided. Report No.: 05000416/2012002 Sample Description Procedure Standby service water siphon line extension modification 71111.18 Standby liquid control system (Boron-10 enrichment change) modification 71111.18 Steam dryer assembly welding processes and examinations 71111.08 Review of Anticipated Transient Without a Scram Safety Evaluation 71111.17 Flow Accelerated Corrosion monitoring and maintenance program 71004 Report No.: 05000416/2012003 Sample Description Procedure Power Range Neutron Monitoring modification 71111.18 Replacement steam dryer 10CFR50.59 Evaluation for current operating power limit (3898 MWth) 71111.18 Post modification test for ultimate heat sink siphon piping replacement and extension 71111.19 Power Range Neutron Monitoring system post maintenance test after installation 71111.19 Operator training and requalification program 71111.11 Power Range Neutron Monitoring system functional test prior to startup 71111.22 Report No.: 05000416/2012004 Sample Description Procedure Power ascension testing as described in Appendix 9 of the EPU license amendment 71004 Power Range Neutron Monitoring system calibration at EPU power (4408 MWth) 71111.22 Operator actions during integrated plant evolutions 71004 Operator training at EPU power (4408 MWth) 71111.11 Report No.: 05000416/2012005 Sample Description Procedure Verify licensee has taken all necessary actions to address the effects of new or more likely initiating events as stated in the license amendment, licensee commitments, or the safety evaluation 71004

.3 Licensee Strike Contingency Plans

Main article: IP 92709

a. Inspection Scope

On October 1, 2012, Grand Gulf Nuclear Station initiated a lockout of bargaining unit security officers due to their vote against the ratification of the contract that expired September 30, 2012. In accordance with Inspection P monitored the need for compensatory measures on a daily basis and reported adverse conditions to regional management and security specialists for assessment. The residents also verified support from the local authorities were adequate to ensure that personnel had unimpeded access to the plant, delivery of support goods and offsite shipment of radioactive materials were unencumbered, unimpeded access to medical care and ambulance services, and unimpeded access to the local fire department to supplement the site fire fighting unit. Security inspectors from the regional office provided oversight for the turn-over of the bargaining security force to the contingency security force. The bargaining unit security force voted to ratify a new contract on November 16, 2012. The resident inspectors interviewed security management and along with regional security inspectors reviewed reintegration plan to ensure adequate security coverage would be maintained during the reintegration process. Documents reviewed are listed in the attachments.

b. Findings

No findings were identified.

.4 (Closed) URI 05000416/2012008-Potential Internal Flooding Caused by Circulation

4OA6 Meetings, Including Exit Exit Meeting Summary On January 17, 2013, the inspectors presented the inspection results to Mr. Kevin Mulligan, Site Vice President of 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. On December 3, 2012, the inspector presented the results of the radiation safety inspection to Ms. C. Perino, Director of Nuclear Safety Assurance, 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 violation of very low security significance (Green) was identified by the licensee and is a violation of NRC requirements which met the criteria of NRC Enforcement Policy for being dispositioned as a non-cited violation.

10 CFR 74.19 requires, in part, that each licensee keep records of inventory including location, transfer, and disposal of all special nuclear material and conduct an annual physical inventory of all special nuclear material in its possession. Contrary to the above, before July 25, 2012, the licensee did not keep records of inventory including location, transfer, and disposal of all special nuclear material, in that on that date and after completing an inventory and records review of SNM pursuant to the material control and accounting program, licensee reactor engineers declared a source range monitor (SRM) detector lost. Specifically, SRM with serial number 1OF007J5 was not in its expected storage location. Using Manual Chapter 0609, Appendix D, this finding had very low safety significance (Green) because it resulted in no dose to a member of the public in the restricted area, controlled area or the unrestricted area.

A1-1 Attachment Attachment 1:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

J. Dorsey, Security Manager

H. Farris, Assistant Operations Manager

J. Gerard, Interim Operations Manager

J. Giles, Manager, Training

M. Krupa, Director, Major Projects

C. Justiss, Licensing

C. Lewis, Manager, Emergency Preparedness

E. Mason, Auditor, Quality Assurance

J. Miller, General Plant Manager

R. Miller, Manager, Radiation Protection

K. Mulligan, Site Vice President Operations

L. Patterson, Manager, Program Engineering

C. Perino, Director, Nuclear Safety Assurance

J. Richardson, Director, Power Upgrade Project

R. Scarbrough, Specialist and Lead Offsite Liaison, Licensing

J. Seiter, Acting Manager, Licensing

J. Shaw, Manager, System Engineering

T. Thurmon, Supervisor, Design Engineering-Mechanical

T. Trichell, Manager, Radiation Protection

D. Wiles, Engineering Director

E. Wright, Supervisor, ALARA

NRC Personnel

None

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened and Closed

05000416/2012005-01 NCV Failure to Make Timely Corrective Actions to Repair the Degraded Auxiliary Building Water Intrusion Barrier (Section 1R12.b.1)

05000416/2012005-02 NCV Failure to Adequately Monitor the Condition of the Auxiliary Building Water Intrusion Barrier (Section (1R12.b.2)

05000416/2012005-03 NCV Failure to Implement Adequate Procedure Instructions to Perform Preventive Maintenance Requiring the Periodic Replacement of the Control Relays in GE Magne Blast Circuit Breakers (Section 1R20.b)

05000416/2012005-04 FIN Failure to Adequately Plan and Control Work Activities to Maintain ALARA (Section 2RS02.b.1)

05000416/2012005-05 NCV Failure To Follow the Radiation Work Permit Requirements During Reactor Cavity High Water Operations (Section 2RS02.b.2)

05000416/2012005-06 NCV Failure to Evaluate the Risk Significances and Develop Action Plans to Address Equipment Identified During Extent of Condition Review for a Post Scram Root Cause Analysis (Section 4A03.2.b)

05000416/2012005-07 NCV Failure to Establish Gain Settings on APRM and LPRM Instruments in Accordance with Design Requirements (Section 4A03.5.b) TI 2515/187 Inspection Near Term Task Force Recommendation 2.3 Flooding Walkdowns (Section 4OA5.5) TI 2515/188 Inspection of Near-Term Task Force Recommendation 2.3 Seismic Walkdowns (Section 4OA5.6)

Closed

05000416/FIN-2012008-07 URI Potential Internal Flooding Caused by Circulation Water System Failure (Section 4OA5.4)

05000416/LER-2012-001-00 LER Surveillance Test Procedure Inadequate to Meet the Requirements of Technical Specifications (Section 4OA3.1)

05000416/LER-2012-002-00 LER Manual Reactor Scram Due to a Steam Supply Motor Operated Valve Failure that Resulted in the Inability to Maintain Reactor Water Level (Section 4OA3.2)

05000416/LER-2012-003-00 LER ESF Actuation Due to Division III Bus Undervoltage following a Lighting Strike (Section 4OA3.3)

05000416/LER-2012-004-00 LER Weld Defect Indication Found in Residual Heat Removal System to Reactor Pressure Vessel Boundary Nozzle (Section 4OA3.4)

Closed

05000416/FIN-2012008-07 URI Potential Internal Flooding Caused by Circulation Water System Failure (Section 4OA5.4)

05000416/LER-2012-001-00 LER Surveillance Test Procedure Inadequate to Meet the Requirements of Technical Specifications (Section 4OA3.1)

05000416/LER-2012-002-00 LER Manual Reactor Scram Due to a Steam Supply Motor Operated Valve Failure that Resulted in the Inability to Maintain Reactor Water Level (Section 4OA3.2)

05000416/LER-2012-003-00 LER ESF Actuation Due to Division III Bus Undervoltage following a Lighting Strike (Section 4OA3.3)

05000416/LER-2012-004-00 LER Weld Defect Indication Found in Residual Heat Removal System to Reactor Pressure Vessel Boundary Nozzle (Section 4OA3.4)

LIST OF DOCUMENTS REVIEWED

Section 1R04: Equipment Alignment

PROCEDURE NUMBER TITLE REVISION 04-1-01-P75-1 Standby Diesel Generator System 96 04-1-01-P41-1 Standby Service Water System 136 04-1-01-E12-1 System Operating Instruction, Residual Heat Removal System 142

DRAWINGS NUMBER TITLE REVISION M-1085D Residual Heat Removal System 4

OTHER DOCUMENTS NUMBER TITLE DATE

System Health Report E12 Residual Heat Removal November 16, 2012

CONDITION REPORTS

CONDITION REPORTS

Section 1R05: Fire Protection

PROCEDURES NUMBER TITLE REVISION Fire Pre Plan C-17 Upper Relay Room

Unit 1 Area 25A

Section 1R05: Fire Protection

PROCEDURES NUMBER TITLE REVISION 04-1-01-P64-3 Fire Protection Cardox System 26 GGNS

MS-55 GGNS Mechanical Standard GGNS TRM Required Fire Rated Floor, Walls & Ceilings 0 Fire Pre-Plan

SSW-01 SSW Pump House and Valve Room, Room 1M110-SSW A Pump House Room 1M112-SSW A Valve Room 1 Fire Pre-Plan

DG-02 DIV I Diesel Generator Room 1D302, Area 12, Elevation 133 5 Fire Pre-Plan A-03 RCIC Pump Room

1A104 1

OTHER DOCUMENTS NUMBER TITLE DATE 2012-08 Transient Combustible Evaluation

9A.5.64 GG UFSAR Fire Area 64

9A.5.60.1 GG UFSAR Fire Area 60

Chemetron Fire Systems Manual

January 8, 1979 9A.5.2.4

DRAWINGS NUMBER TITLE REVISION A-629 Unit I and Common Buildings Fire Protection Misc. Notes and Details 0 E-0965 Raceway Plan Water STDBY Water Pump HS Basin A & B Fire and Smoke Detection System Units I & II 7

CALCULATION NUMBER TITLE DATE

MC-QSP64-86058 Fire Zone Yard/Fire Area 59 June 13, 2001

CONDITION REPORTS

CR-GGN-2012-11435 CR-GGN-2009-05026

Section 1R06: Flood Protection Measures

PROCEDURES NUMBER TITLE REVISION 05-1-02-VI-1 Off-Normal Event Procedure Flooding 109 04-1-02-1H13-P680-8A1-C1 Alarm Response Instruction, Turbine Building E Floor Drain Sump Level Hi-Hi 100 04-1-02-1H13-P680-8A1-B1 Alarm Response Instruction, Turbine Building W Equipment Drain Sump Level Hi-Hi 100 04-1-02-1H13-P680-8A1-A1 Alarm Response Instruction, Turbine Building E Equipment Drain Sump Level Hi-Hi 100 04-1-02-1H13-P680-8A1-D1 Alarm Response Instruction, Turbine Building W Floor Drain Sump Level Hi-Hi 100 04-1-02-1H13-P870-6A-G1 Alarm Response Instruction, Circulating Water Expansion Joint Seal Level Hi 113

CALCULATIONS NUMBER TITLE REVISION M6.3.051 Circulating Water System

Calculate Revised Plant Flooding Elevations Due to the Aux Cooling Tower B M6.3.043 Circulating Water System

Calculate Water Volume of Circulating Water System C

CALCULATIONS NUMBER TITLE REVISION M6.3.051-001 Circulating Water Systems

Calculate Revised Unit 1 Turbine Building and Unit 1 Control Building Flooding Elevations 0

DRAWINGS NUMBER TITLE REVISION

C-1706C Unit 1 & 2 Circulating Water System Circulating Water Piping Sections and Details 11 M154.0-N1N71G521A-1.2-006 Garlock Style 204 & 204HP Expansion Joints 1 M-1059A P&I Diagram, Circulation Water System 41 M-1059B P&I Diagram, Circulating Water System, Unit 1 18

SFD-1059 System Flow Diagram, Circulating Water System, Unit 1 2 A-0010 -- 10 A-0011 Units 1 & 2 Gen. Fl. Plan. ---- 8 E-1152-033 Schematic Diagram, Circulating Water System, Main Control Room Annunciation, Unit 1 14

ENGINEERING CHANGES NUMBER TITLE REVISION

EC 38959 Calculate Revised Unit 1 Turbine Building and Unit 1 Control Building Flooding Elevations 0

VENDOR DOCUMENTS NUMBER TITLE REVISION 9645-A-021.0 Bechtel Material Requisition

Watertight Doors 8

WORK ORDERS

WO 52306120 01

WO 52323476 01

WO 52323703 01

CONDITION REPORTS

CR-GGN-2012-09424

CR-GGN-2012-12448 CR-GGN-2012-12449

Section 1R11: Licensed Operator Requalification Program

PROCEDURES NUMBER TITLE REVISION 03-1-01-2 Integrated Operating Instruction Power Operations 152

EN-RE-215 Reactivity Maneuver Plan (BWR) 1

EN-RE-215 Reactivity Maneuver Plan 1

OTHER DOCUMENTS NUMBER TITLE REVISION / DATE

2012 Cycle 6 Licensed Operator Requal Simulator Training Plan Simulator Differences

GSMS-LOR-WEX17 LOR Training APRM Downscale/Loss of Condenser Vacuum/LOCA/Degraded ECCS (EP-2,

EP-3) 18

OTHER DOCUMENTS NUMBER TITLE REVISION / DATE Grand Gulf Cycle 19 Periodic Log November 20, 2012

Section 1R12: Maintenance Effectiveness

PROCEDURES NUMBER TITLE REVISION / DATE

GGNS-C-399.0 Maintenance Rule Inspection of Structures, Tanks, and Transformers Inspections 9

EN-DC-204 Maintenance Rule Scope and Basis 2

EN-DC-150 Condition Monitoring of Maintenance Rule Structures 2

EN-DC-203 Maintenance Rule Program 1

EN-DC-205 Maintenance Rule Monitoring 4

EN-DC-206 Maintenance Rule (a)(1) Process 1

OTHER DOCUMENTS NUMBER TITLE REVISION / DATE EQ04.10 9kV Power Cable 1

ER-GG-2005-0144-000 Evaluate Water Inleakage into the Enclosure Bldg. 0

GGNS-96-0075 Assessment of Grand Gulf Compliance with the Guidelines of

NEI 96-03, Rev. D and the Maintenance Rule for Monitoring the Condition of Structures 2

EN-DC-205, Attachment 9.1 Maintenance Rule Functional Failure Evaluation,

CR-GGN-2012-08921

CA 00051 October 5, 2012

CONDITION REPORTS

CONDITION REPORTS

CONDITION REPORTS

CONDITION REPORTS

WORK ORDERS

Section 1R13: Maintenance Risk Assessment and Emergent Work Controls

PROCEDURES NUMBER TITLE REVISION / DATE 02-S-01-17 Control of Limiting Conditions for Operation 123

EN-WM-101 Online Emergent Work Add/Delete Approval Form November 1, 2012 07-S-02-300 Fuel and Core Component Movement Control 125 07-S-05-300 Control and Use of Cranes and Hoists 113

EN-MA-119 Material Handling Program 13 05-1-02-V-12 Off-Normal Event Procedure, Condensate/Reactor Water High Conductivity 25

EN-WM-101 Attachment 9.1 Online Emergent Work Add/Delete Approval Form,

WO 52313215 9 01-S-18-6, Attachment VI Risk Assessment of Maintenance Activities 119 02-S-01-41 On Line Risk Assessment 7

OTHER DOCUMENTS NUMBER TITLE DATE

LCOTR No.:1-TS-12-0290

LCOTR No.:1-TS-12-0228

LCOTR No.:1-TS-12-0261

Shutdown Condition 1, Mode: 4, State: Cold S/D, Fuel Status: Fueled December 9, 2012 9:34 pm

Shutdown Condition 1, Mode: 4, State: Cold S/D, Fuel Status: Fueled December 10, 2012 7 am

Shutdown Condition 1, Mode: 4, State: Cold S/D, Fuel Status: Fueled December 10, 2012 10:56 am

Shutdown Condition 1, Mode: 4, State: Cold S/D, Fuel Status: Fueled December 10, 2012 3:45 pm

Shutdown Condition 1, Mode: 4, State: Cold S/D, Fuel Status: Fueled December 10, 2012 7:50 pm

Shutdown Condition 1, Mode: 4, State: Cold S/D, Fuel Status: Fueled December 11, 2012 7:20 pm

Shutdown Condition 1, Mode: 4, State: Cold S/D, Fuel Status: Fueled December 12, 2012 8:07 pm

Shutdown Condition 1, Mode: 4, State: Cold S/D, Fuel Status: Fueled December 12, 2012 10 pm

Shutdown Condition 1, Mode: 4, State: Cold S/D, Fuel Status: Fueled December 13, 2012 1:02 am

Shutdown Condition 1, Mode: 4, State: Cold S/D, Fuel Status: Fueled December 13, 2012 1:35 am

CONDITION REPORTS

WORK ORDERS

ENGINEERING CHANGES EC No. 39577 EC No. 41383

Section 1R15: Operability Evaluations

PROCEDURE NUMBER TITLE REVISION

EN-OP-104 Operability Determination Process:

CR-GGN-2012-12133 6

OTHER DOCUMENTS NUMBER TITLE DATE

460000286 Limitorque Valve Controls July 16, 2007

ASM Handbook, Volume 13A

Corrosion: Fundamentals, Testing, and Protection 2003

Structural

Analysis and design of Process Equipment, 2nd Edition 1989

Eddie Current Test Data for Div II Emergency Diesel Generator Jacket Water Heat Exchanger November 1, 2012

NRC Regulatory Guide 1.9 March 2007

NRC Regulatory Guide 1.32 February 1977

DRAWINGS NUMBER TITLE REVISION E-1111-013 P75 Stand-by Diesel Generator SYS DIV II Train B Start Circuit 16 E-1111-012 P75 Stand-by Diesel Generator SYS DIV II Train A Start and Stop Circuit 13

DRAWINGS NUMBER TITLE REVISION Figure 1 Boundary and Support Systems of Emergency Diesel Generator Systems 4

CALCULATIONS NUMBER TITLE REVISION / DATE

MC-Q1P75-98030 Standby Diesel Jacket Water Operating Parameters 1

CONDITION REPORTS

CR-GGN-2012-12060

CR-GGN-2012-12133

CR-GGN-2012-11755

ENGINEERING CHANGES EC No. 40834 EC No. 40821 EC No. 40897

Section 1R19: Post-Maintenance Testing

PROCEDURES NUMBER TITLE REVISION 07-S-23-P75-2 Diesel Generator DIV I and DIV II Functional Check Overspeed Trip Switch and Emergency Stop Switch 2 06-OP-1P41-Q-005 Standby Service Water Loop B Valve and Pump Operability Test 122 06-OP-1E12-Q-0006 LPCI/RHR Subsystem B MOV Functional Test 111 06-OP-1E12-M-0002 LPCI/RHR Subsystem B Monthly Functional Test 113 06-OP-1E12-Q-0024 LPCI/RHR Subsystem B Quarterly Functional Test 118 06-0P-1P41-M-0005 SSW Loop B Operability Check 112 06-OP-1P75-M-0002, Attachment Standby Diesel Generator 12 Functional Test

131

Section 1R19: Post-Maintenance Testing

PROCEDURES NUMBER TITLE REVISION

II 06-OP-1P75-M-0002, Attachment I Standby Diesel Generator 12 Functional Test

131 04-1-03-P75-1 Div 2 Diesel Generator Unexcited Run 7

OTHER DOCUMENTS NUMBER TITLE DATE

November 5, 2012

Analysis for Static Test of Gate and Globe Valves, Valve 1P41F016B

MOV Torque Switch Setpoint Methodology Set Point Calculations, Valve No. 1P41F016B

MOV Torque Switch Setpoint Methodology Set Point Calculations, Valve No. 1E12F006B

Preliminary Vibration Data on SSW B

41329 Stator Winding Test Report, Grand Gulf SSW Pump

GNRO-2012-00007 Reply to Notice of Violation

EA-2012-015 February 13, 2012

TR-110392 Eddy Current Testing of Service Water Heat Exchangers for Engineers Guideline February 1999

ASM Handbook, Vol. 13A-Corrosion: Fundamentals, Testing, Protection 2003

WORK ORDERS

WO 00121405 01

WO 00282241 01

WO 00314300 01

WO 00319437 01

WO 00318398 01

WO 00320182 02

WO 52421359 01

WO 00272998 01

WO 00272998 04

WO 00082560 04

WO 00082560 01

WO 00082560 03

WO 00082560 08

WO 00332736 01

CONDITION REPORTS

CR-GGN-2012-11949 CR-GGN-2012-

Section 1R20: Refueling and Other Outage Activities

PROCEDURES NUMBER TITLE REVISION

PO 19-01 Shutdown Operations Protection Plan: December 17, 2012 13 07-S-12-150 General Electric AM 4.16 KV Breaker Overhaul Instruction 0 07-S-12-61 Inspection of GE Magne Blast Circuit Breakers

3 07-S-12-61 Inspection of GE Magne Blast Circuit Breakers 4 07-S-12-150 General Electric AM 4.16 KV Breaker Overhaul Instruction 1

DRAWINGS NUMBER TITLE REVISION E-1188-018 Schematic Diagram, HPCS Power supply System Breaker No.1 11 E-1009 One Line Meter & Relay Diagram 4.16KV E.S.F. System Bus 17AC 9

OTHER DOCUMENTS NUMBER TITLE REVISION / DATE GG19-013 December Startup Power Profile

GG19-014 December Startup Power Profile

PO-19-01 Critical Path December 9, 2012

PO-19-01 Critical Path December 10, 2012

OTHER DOCUMENTS NUMBER TITLE REVISION / DATE

PO-19-01 Critical Path December 11, 2012

PO-19-01 Critical Path December 12, 2012

GGNS

PO-19-01 Planned Outage Daily Update December 10, 2012

GGNS

PO-19-01 Planned Outage Daily Update December 11, 2012

GGNS

PO-19-01 Planned Outage Daily Update December 12, 2012

GGNS

PO-19-01 Planned Outage Daily Update December 13, 2012

LT-Apparent Cause Evaluation Report: Failure of the Division

June 27, 2012

GEK-7320F Instruction, Magne Blast Circuit Breaker Types

AM-4.16-350-2C,

AM-4.16-350-2H F PM Basis Template

EN-Switchgear-Medium Voltage-1KV to 7KV 3

ACE Report

CR-GGN-2012-07922 dated 06-27-2012

1000011 Guidance on Overhaul of Magne-Blast Circuit Breakers December 2000

CONDITION REPORTS

CR-GGN-2012-07922 CR-GGN-2012-07935

Section 1R22: Surveillance Testing

PROCEDURE NUMBER TITLE REVISION 06-EL-1B21-Q-0001 ADS Timers Functional Test and Calibration 102

Section 1R22: Surveillance Testing

PROCEDURE NUMBER TITLE REVISION 06-IC-1C71-Q-2003 Turbine Control Valve Fast Closure (RPS/EOC RPT) Functional Test 104

WORK ORDERS

WO 52439342 01

WO 52439341 01

WO 52439340 01

Section 1EP6: Drill Evaluation

PROCEDURES NUMBER TITLE REVISION 10-S-01-1 Activation of the Emergency Plan 121

OTHER DOCUMENTS NUMBER TITLE DATE

Emergency Notification Form, Message Number 1 October 16, 2012

GGNS-EP Group Drill, Emergency Facility Log October 16, 2012 Attachment 2 Objectives/Evaluation Criteria, Performance Indicators

Attachment 3 PCRS Items, Lessons Learned

Repair and Corrective Actions-Admin Status Board October 16, 2012

GGNS 2012 EP Drill (Blue Team) October 16, 2012

CONDITION REPORTS

Section 2RS02:

Occupational ALARA Planning and Controls

PROCEDURES

NUMBER TITLE REVISION

EN-CY-112 BWR Shutdown and Startup Chemistry 0

EN-FAP-OU-100 Refueling Outage Preparation & Milestones 2

EN-MA-101 Conduct of Maintenance 3

EN-DC-115 Engineering Change Process 13

EN-RP-100 Radiation Worker Expectations 7

EN-RP-101 Access Control for Radiologically Controlled Areas 6

EN-RP-102 Radiological Control 3

EN-RP-108 Radiological Posting 11

EN-RP-110 ALARA Program 7

EN-RP-143 Source Control 9

EN-RP-151 Radiological Diving 2

EN-RP-201 Dosimetry Administration 3

EN-RP-202 Personnel Monitoring 8

EN-RP-204 Special Monitoring Requirements 6

EN-RP-503 Selection, Issue and Use of Respiratory Protection 5

AUDITS,

SELF-ASSESSMENTS, AND SURVEILLANCES

NUMBER TITLE DATE

QA 14/15-2011 GGNS 2011

RP-RW Audit Report Final November 30, 2011

CONDITION REPORTS

RADIATION EXPOSURE PERMITS-ALARA

POST-JOB REVIEWS

NUMBER TITLE REVISION

RWP-1086 Fuel Pool Cooling & Cleanup Modification

8

RWP-1402 Refuel Floor High Water 2

RWP-1403 Reactor Assembly/Disassembly 5

RWP-1406 Dryer/Separator Replacement 16

RWP-1505 Scaffold 2

RWP-1508 Under Vessel Activities 4

RWP-1511 General Drywell Maintenance 3

RWP-1516 In-Service Inspection 4

Section 4OA1: Performance Indicator Verification

PROCEDURE NUMBER TITLE REVISION

EN-LI-114 Performance Indicator Process 6

OTHER DOCUMENTS NUMBER TITLE DATE

NRC Performance Indicator Technique/Data Sheet, Heat Removal (RCIC/EFW/AFW) 4th Quarter 2011

NRC Performance Indicator Technique/Data Sheet 1st Quarter 2012

NRC Performance Indicator Technique/Data Sheet 2nd Quarter 2012

NRC Performance Indicator Technique/Data Sheet 3rd Quarter 2012

NRC Resident Questions about E51-RCIC MSPI Data 4th Quarter 2011-3rd Quarter 2012

Surveillance Tests for RCIC/E51 System

NRC Performance Indicator Technique/Data Sheet, Residual Heat Removal (RHR) 4th Quarter 2011

NRC Performance Indicator Technique/Data Sheet 1st Quarter 2012

NRC Performance Indicator Technique/Data Sheet 2nd Quarter 2012

NRC Performance Indicator Technique/Data Sheet 3rd Quarter 2012

NRC Resident Questions about E12- Residual Heat Removal 4th Quarter 2011-3rd Quarter 2012

Residual Heat Removal 4th Quarter 2011

OTHER DOCUMENTS NUMBER TITLE DATE

NRC Performance Indicator Technique/Data Sheet, High Pressure Injection (HPCS/HPCI/HPI/HPSI/FCI/HPI) 4th Quarter 2011

NRC Performance Indicator Technique/Data Sheet, High Pressure Injection (HPCS/HPCI/HPI/HPSI/FCI/HPI) 1st Quarter 2012

NRC Performance Indicator Technique/Data Sheet, High Pressure Injection (HPCS/HPCI/HPI/HPSI/FCI/HPI) 2nd Quarter 2012

NRC Performance Indicator Technique/Data Sheet, High Pressure Injection (HPCS/HPCI/HPI/HPSI/FCI/HPI) 3rd Quarter 2012

NRC Performance Indicator Technique/Data Sheet, Emergency AC Power (EDG) 4th Quarter 2011

NRC Performance Indicator Technique/Data Sheet, Emergency AC Power (EDG) 1st Quarter 2012

NRC Performance Indicator Technique/Data Sheet, Emergency AC Power (EDG) 2nd Quarter 2012

NRC Performance Indicator Technique/Data Sheet, Emergency AC Power (EDG) 3rd Quarter 2012

NRC Resident Questions about Division I and II Standby Diesel Generators 4th Quarter 2011-3rd Quarter 2012

NRC Resident Questions about E22 High Pressure Core Spray 4th Quarter 2011-3rd Quarter 2012

NRC Performance Indicator Technique/Data Sheet, Cooling Water Support 4th Quarter 2011

NRC Performance Indicator Technique/Data Sheet, Cooling Water Support 1st Quarter 2012

NRC Performance Indicator Technique/Data Sheet, Cooling Water Support 2nd Quarter 2012

NRC Performance Indicator Technique/Data Sheet, Cooling Water Support 3rd Quarter 2012

Operations Surveillances for Stand-by Service Water P41 System

Section 4OA2: Identification and Resolution of Problems

PROCEDURES NUMBER TITLE REVISION/ DATE 04-1-01-P44-1 Plant Service Water/Radial Well System 99 05-1-02-III-12 Off-Normal Event Procedure 0

EN-WM-100 Work Request Generation, Screening, and Classification 8

EN-FAP-OP-009 Tagging Performance Indicator Program 2

EN-LI-121 Entergy Trending Process 12

EN-WM-101 On-Line Work Management Process 9

EN-OP-117, Attachment 9.5 Operator Aggregate Assessment of Plant Deficiencies April 2012

EN-OP-117 Operations Assessments 4

EN-FAP-OP-006 Operator Aggregate Impact Index Performance Indicator 0

EN-OP-117, Attachment 9.5 Operator Aggregate Assessment of Plant Deficiencies November 2012 07-S-12-61 Inspection of GE MagnaBlast Circuit Breakers 110

OTHER DOCUMENTS NUMBER TITLE DATE

Standing Orders October 14, 2012

Operator Compensatory Actions October 2012

ODMIs In Effect November 14, 2012

List of Inputs to Operation Aggregate Index October 2012

Tagouts Older than 90 days Report August 19, 2012

Caution Tagouts Older than 90 days Report August 19, 2012

Items Affecting Operations Aggregate Index March 1, 2012

Remaining Open Actions For Open GGN Crs with Operability Code: OPERABLE DNC April 17, 2012

OTHER DOCUMENTS NUMBER TITLE DATE

GGNS Quarterly Trend Report 1st and 2nd Quarter 2012 October 3, 2012

Open ODMI Actions March 2012

Remaining Open Actions For Open GGN Crs with Operability Code: OPERABLE-COMP MEAS April 17, 2012

Grand Gulf Operator Aggregate Impact Index November 2011

Grand Gulf Operator Aggregate Impact Index December 2011

Grand Gulf Operator Aggregate Impact Index January 2012

Grand Gulf Operator Aggregate Impact Index February 2012

Grand Gulf Operator Aggregate Impact Index March 2012

Grand Gulf Operator Aggregate Impact Index April 2012

Grand Gulf Operator Aggregate Impact Index May 2012

Grand Gulf Operator Aggregate Impact Index June 2012

Grand Gulf Operator Aggregate Impact Index July 2012

Grand Gulf Operator Aggregate Impact Index August 2012

Grand Gulf Operator Aggregate Impact Index September 2012

Grand Gulf Operator Aggregate Impact Index October 2012

Grand Gulf Operator Aggregate Impact Index November 2012

Grand Gulf Operator Burdens (OB) November 2011

Grand Gulf Operator Burdens (OB) December 2011

Grand Gulf Operator Burdens (OB) January 2012

Grand Gulf Operator Burdens (OB) February 2012

OTHER DOCUMENTS NUMBER TITLE DATE

Grand Gulf Operator Burdens (OB) March 2012

Grand Gulf Operator Burdens (OB) April 2012

Grand Gulf Operator Burdens (OB) May 2012

Grand Gulf Operator Burdens (OB) June 2012

Grand Gulf Operator Burdens (OB) July 2012

Grand Gulf Operator Burdens (OB) August 2012

Grand Gulf Operator Burdens (OB) September 2012

Grand Gulf Operator Burdens (OB) October 2012

Grand Gulf Operator Burdens (OB) November 2012

Grand Gulf Operator Workarounds (OWA) November 2011

Grand Gulf Operator Workarounds (OWA) December 2011

Grand Gulf Operator Workarounds (OWA) January 2012

Grand Gulf Operator Workarounds (OWA) February 2012

Grand Gulf Operator Workarounds (OWA) March 2012

Grand Gulf Operator Workarounds (OWA) April 2012

Grand Gulf Operator Workarounds (OWA) May 2012

Grand Gulf Operator Workarounds (OWA) June 2012

Grand Gulf Operator Workarounds (OWA) July 2012

OTHER DOCUMENTS NUMBER TITLE DATE

Grand Gulf Operator Workarounds (OWA) August 2012

Grand Gulf Operator Workarounds (OWA) September 2012

Grand Gulf Operator Workarounds (OWA) October 2012

Grand Gulf Operator Workarounds (OWA) November 2012

Grand Gulf Control Room Deficiencies November 2011

Grand Gulf Control Room Deficiencies December 2011

Grand Gulf Control Room Deficiencies January 2012

Grand Gulf Control Room Deficiencies February 2012

Grand Gulf Control Room Deficiencies March 2012

Grand Gulf Control Room Deficiencies April 2012

Grand Gulf Control Room Deficiencies May 2012

Grand Gulf Control Room Deficiencies June 2012

Grand Gulf Control Room Deficiencies July 2012

Grand Gulf Control Room Deficiencies August 2012

Grand Gulf Control Room Deficiencies September 2012

Grand Gulf Control Room Deficiencies October 2012

Grand Gulf Control Room Deficiencies November 2012

OTHER DOCUMENTS NUMBER TITLE DATE

Grand Gulf Control Room Alarm (CRA) November 2011

Grand Gulf Control Room Alarm (CRA) December 2011

Grand Gulf Control Room Alarm (CRA) January 2012

Grand Gulf Control Room Alarm (CRA) February 2012

Grand Gulf Control Room Alarm (CRA) March 2012

Grand Gulf Control Room Alarm (CRA) April 2012

Grand Gulf Control Room Alarm (CRA) May 2012

Grand Gulf Control Room Alarm (CRA) June 2012

Grand Gulf Control Room Alarm (CRA) July 2012

Grand Gulf Control Room Alarm (CRA) August 2012

Grand Gulf Control Room Alarm (CRA) September 2012

Grand Gulf Control Room Alarm (CRA) October 2012

Grand Gulf Control Room Alarm (CRA) November 2012

Grand Gulf Caution Tags > 90 days November 2011- November 2012

Grand Gulf Tagouts > 90 days November 2011- November 2012

CONDITION REPORTS

CONDITION REPORTS

CR-GGN-2012-09035 CR-GGN-2012-09111

Section 4OA3: Event Follow-Up

PROCEDURES NUMBER TITLE REVISION

EN-LI-118 Root Cause Evaluation Process 18 05-S-01-EP-1 Emergency/Severe Accident Procedure Support Documents 27 06-RE-1C51-O-0001 Local Power Range Monitor Calibration 112 17-S-02-40 Bypassing and Unbypassing LRPMs 116 04-1-01-C51-1 Neutron Monitoring 28 04-1-02-1H13-P680-5A-C9 LPRM DNSC 206

Section 4OA3: Event Follow-Up

PROCEDURES NUMBER TITLE REVISION 07-S-33-C51-2 LPRM Detector Removal/Installation 112 07-S-33-C51-2 LPRM Detector Removal/Installation 113 03-1-01-1 Cold Shutdown to Generator Carrying Minimum Load 154 06-RE-1C51-O-0001 Local Power Range Monitor Calibration 112 06-RE-1C51-W-0001 APRM Gain Adjustment 106 01-S-06-26 Post-Trip Analysis, Scram # 126, December 31, 2012 20 02-S-01-27

49 01-S-06-5 Event Notification Worksheet EN #48637 110

OTHER DOCUMENTS NUMBER TITLE REVISION / DATE

00160640 Action Request Identification October 22, 2012

CA 34 for

CR-GGN-2012-1842

CA 35 for

CR-GGN-2012-1842

CA 43 for

CR-GGN-2012-1842

GNRO-2012-00013 GGNS

LER 2012-001-00 Surveillance Test Procedure Inadequate to meet the Requirements of Technical Specifications March 13, 2012

GNRO-2012-00028 GGNS

LER 2012-002-00 Manual Reactor Scram Due to a Steam Supply Motor Operated Valve Failure that Resulted in the Inability to Maintain Reactor Water Level April 19, 2012

OTHER DOCUMENTS NUMBER TITLE REVISION / DATE

GNRO-2012-00048 GGNS

LER 2012-003-00 Actuation Due to Division III Bus Undervoltage following a Lightening Strike May 29, 2012

GNRO-2012-00069 GGNS

LER 2012-004-00 Weld Defect Indication Found in Residual Heat Removal System to Reactor Pressure Vessel Boundary Nozzle June 27, 2012

GNRO-2012-00084 GGNS

LER 2012-005-00 Average Power Range Monitors Inoperable in Excess of Technical Specifications Allowances in Mode 2 August 13, 2012

GNRO-2012-00090 Special Report 2012-006-00 Special Nuclear Inventory Discrepancy August 23, 2012

Root Cause Evaluation Report, Inability to Maintain Reactor Water Lever,

CR-GGN-2012-1842 July 11, 2012

Apparent Cause Evaluation Report PRNM Issues During RF18 Power Ascension,

CR-GGN-2012-8224 1

GNRO-2012/00108 GGNS

LER 2012-007-00 Standby Service Water System Administratively Inoperable For A Period Longer Than Allowed By Technical Specifications September 14, 2012

Core Operating Limits Report LBDCR 12034 22A3739AE Neutron Monitoring System 6

SDC-C71 Reactor Protection System 0

SDC-C51 Neutron Monitoring System 0 Chapter 7 GG UFSAR Chapter 7

GG Technical Specifications and Bases

SCN No: 96/0001 Standard/Specific Change Notice December 30, 2003 DRN No: 04-1210

SDC-C51 Neutron Monitoring System 0

OTHER DOCUMENTS NUMBER TITLE REVISION / DATE DRN No: 05-1185

SDC-C71 0

Forced Outage Worklist December 18, 2012

CONDITION REPORTS

ENGINEERING CHANGES EC No. 19461 EC No. 21999

Section 4OA7: Licensee-Identified Violations

CONDITION REPORTS

CR-GGNS-2012-09405

TI 187/188 PROCEDURES NUMBER TITLE REVISION / DATE 07-S-14-310 Inspection of Mechanical Seals on Doors 10

EN-DC-170 Fukushima Near Term Task Force Recommendation 2.3 Flooding Walkdown Procedure 0

GGNS-CS-12-0002 Flooding Walkdown Submittal Report for Resolution of Fukushima Near-Term Task Force Recommendation 2.3: Flooding

0

EN-DC-168 Fukushima Near-Term Task Force Recommendation 2.3 Seismic Walk-down Procedure 0 05-1-02-VI-2 Hurricanes, Tornados, and Severe Weather 119 05-1-02-VI-1 Off-Normal Event Procedure Flooding 109

EN-EP-302 Severe Weather Response 0

DRAWINGS NUMBER TITLE REVISION / DATE 07-S-14-310 Inspection of Mechanical Seals on Doors 10 J-0133G Installation detail-Seismic and Non Seismic Tubing Run-STDBY. Diesel Generator 3 J-0157T Area Temp. Element 6 J-135B-002 Standby Service Water Pump House A and B Temperature 5 J-1512 Standby Service Water Pump House Basin A 8 J-1512- U2-C Standby Service Water Pump House Basin A A J-KA1512 Standby Service Water Pump House Basin A A M-1026 Diesel Generator Building, Unit 1 15 M-1106A D. Gen., ECCS., ESF. ELEC. SWGR., SSW. & CIRC. WTR. PP. HSE. VENT. SYS.

Unit 1 12 9645-J-561.0-Q1C61N403A-1.1-0010 Thermo Electric Drawing 27620

OTHER NUMBER TITLE REVISION / DATE

Endorsement of Nuclear Energy Institute 12-for Performing Verification Walkdowns of Plant Flood

May 31, 2012 WP1 Yard Inside PA (North) 0 WP2 Yard Inside PA (South) 0 WP 3 Yard Outside PA (North) 0 WP4 Yard Outside PA (South) 0

OTHER NUMBER TITLE REVISION / DATE

AWC-041

AWC-050

SWEL1-084 H22P401, STBY DG Engine Control Panel

SWEL1-068 Y47N005B, Temperature Element (SSW Pump House B Space)

SWEL SWEL Excel Sheet September 17, 2012

US Army Corp of Engineers: Sandbagging Techniques 2004

ER-GG-2004-0272-000 Acceptance of corrosion of conduit and electric boxes (CR-GGN-2004-02612) July 1, 2004

PMP Site Drainage Modifications 1

GGNS-CS-12-00003 GGNS Flooding Walkdown Submittal Report for Resolution of Fukushima Near-Term Task Force Recommendation 2.3: Flooding 0

GGNS-CS-12-00002 GGNS Flooding Walkdown Submittal Report for Resolution of Fukushima Near-Term Task Force Recommendation 2.3: Seismic 0

GGNS-CS-12-00004 GGNS Flooding Walkdown Submittal Report for Resolution of Fukushima Near-Term Task Force Recommendation 2.3: Flooding 0

CONDITION REPORTS

CR-GGN02004-02612

Attachment Attachment 2: Request for Information for ALARA Planning & Controls Inspection

1. Items needed to support the ALARA Planning & Controls (71124.02) inspection to be conducted by Louis C. Carson II are as follows:

Date of Last Inspection:

February 18, 2011 A. List of contacts and telephone numbers for ALARA program personnel B. Applicable organization charts C. Copies of audits, self-assessments, and LERs, written since date of last inspection, focusing on ALARA D. Procedure index for ALARA Program E. Please provide specific procedures related to the following areas noted below.

Additional Specific Procedures may be requested by number after the inspector reviews the procedure indexes.

1. ALARA Program 2. ALARA Committee 3. Radiation Work Permit Preparation F. A summary list of corrective action documents (including corporate and subtiered systems) written since date of last inspection, related to the ALARA program.

In addition to ALARA, the summary should also address Radiation Work Permit violations, Electronic Dosimeter Alarms, and RWP Dose Estimates NOTE: The lists should indicate the significance level of each issue and the search criteria

G.

List of work activities greater than 1 rem, since date of last inspection.

Include original dose estimate and actual dose.

H. Site dose totals and 3-year rolling averages for the past 3 years (based on dose of record) I. Outline of source term reduction strategy J. A major focus of this inspection will be the results of the power upgrade outage, please provide the following:

Annual GGNS ALARA Report for 2011

Last post Refueling-Power- Outage Report

List of ALARA Package that Exceeded the Original Dose Projections Provide Written Justifications if Dose were Exceeded by 50% & 5 Person-Rem 2. Occupational Dose Assessment (Inspection Procedure 71124.04) to be reviewed: Date of Last Inspection:

August 18, 2010 A List of contacts and telephone numbers for the following areas: 1 Radiological effluent control 2 Engineered safety feature air cleaning systems B Applicable organization charts C Audits, self assessments, surveillances, vendor or NUPIC audits of contractor support, and LERs written since September 2010 related to Occupational Dose Assessment D Procedure indexes for Occupational Dose Assessment E Please provide specific procedures related to the following areas.

Additional Specific Procedures may be requested after the inspector reviews the procedure indexes.

1. Radiation Protection Program 2. Radiation Protection Conduct of Operations 3. Personnel Dosimetry Program 4. Radiological Posting and Warning Devices 5. Air Sample Analysis 6. Performance of High Exposure Work 7. Declared Pregnant Worker 8. Bioassay Program

F List of corrective action documents (including corporate and subtiered systems) written since September 2010 associated with: 1. NVLAP accreditation 2. Dosimetry (TLD/OSL, etc.) problems 3. Electronic alarming dosimeters 4. Bioassays or internally deposited radionuclides or internal dose

5. Neutron dose

NOTE; The lists should indicate the significance level of each issue and the search criteria used. G List of positive whole body counts since, September 2010 names redacted if desired H Part 61 analyses/scaling factors I The most recent National Voluntary Laboratory Accreditation Program (NVLAP) accreditation report on the licensee or dosimetry vendor, as appropriate Please provide this information to me by November 1, 2012; thank you in advance.

If you have any questions pertaining to the requested information or the upcoming inspection, my office number is (817) 200-1221, or you can reach me by email at Louis.Carson@nrc.gov.