IR 05000416/2014005
| ML15033A479 | |
| Person / Time | |
|---|---|
| Site: | Grand Gulf  |
| Issue date: | 02/02/2015 |
| From: | Jeremy Groom NRC/RGN-IV/DRP/RPB-C |
| To: | Kevin Mulligan Entergy Operations |
| Groom J | |
| References | |
| EA-13-058 IR 2014005 | |
| Download: ML15033A479 (49) | |
Text
UNITED STATES ary 2, 2015
SUBJECT:
GRAND GULF NUCLEAR STATION - NRC INSPECTION REPORT 05000416/2014005
Dear Mr. Mulligan:
On December 31, 2014, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Grand Gulf Nuclear Station Unit 1. On January 8, 2015, the NRC inspectors discussed the results of this inspection with you and other members of your staff. Inspectors documented the results of this inspection in the enclosed inspection report.
NRC inspectors documented one finding of very low safety significance (Green) in this report.
This finding involved a violation of NRC requirements. Further, inspectors documented a licensee-identified violation, which was determined to be of very low safety significance. The NRC is treating these violations as non-cited violations (NCVs) consistent with Section 2.3.2.a of the NRC Enforcement Policy.
If you contest the violations or significance of the NCV, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001; with copies to the Regional Administrator, Region IV; the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC resident inspector at the Grand Gulf Nuclear Station.
In accordance with Title 10 of the Code of Federal Regulations (10 CFR) 2.390, Public Inspections, Exemptions, Requests for Withholding, a copy of this letter, its enclosure, and your response (if any) will be available electronically for public inspection in the NRCs Public Document Room or from the Publicly Available Records (PARS) component of the NRC's Agencywide Documents Access and Management System (ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).
Sincerely,
/RA/
Jeremy Groom, Acting Chief Project Branch C Division of Reactor Projects Docket No.: 50-416 License No.: NPF-29
Enclosure:
Inspection Report 05000416/2014005 w/ Attachment: Supplemental Information
REGION IV==
Docket: 05000416 License: NPF-29 Report: 05000416/2014005 Licensee: Entergy Operations, Inc.
Facility: Grand Gulf Nuclear Station, Unit 1 Location: 7003 Baldhill Road Port Gibson, MS 39150 Dates: October 1 through December 31, 2014 Inspectors: R. Smith, Acting Senior Resident Inspector M. Williams, Acting Senior Resident Inspector N. Day, Resident Inspector B. Parks, Acting Resident Inspector P. Nizov, Acting Resident Inspector C. Alldredge, Health Physicist L. Carson II, Senior Health Physicist T. Farina, Operations Engineer G. Guerra, CHP, Emergency Preparedness Inspector G. Pick, Senior Reactor Inspector, Division of Reactor Safety Approved By: Jeremy Groom, Acting Chief, Project Branch C Division of Reactor Projects-1- Enclosure
SUMMARY
IR 05000416/2014005; 09/01/2014 - 12/31/2014; Grand Gulf Nuclear Station; Operability
Determinations and Functionality Assessments The inspection activities described in this report were performed between October 1 and December 31, 2014, by the resident inspectors at the Grand Gulf Nuclear Station and inspectors from the NRCs Region IV office. One finding of very low safety significance (Green)is documented in this report. This finding involved a violation of NRC requirements.
Additionally, NRC inspectors documented one licensee-identified violation of very low safety significance in this report. The significance of inspection findings are indicated by their color (Green, White, Yellow, or Red), and are determined using Inspection Manual Chapter 0609,
Significance Determination Process, dated June 02, 2011. Cross-cutting aspects are determined using Inspection Manual Chapter 0310, Aspects Within the Cross Cutting Areas, dated December 04, 2014. Violations of NRC requirements are dispositioned in accordance with the NRC Enforcement Policy dated July 9, 2013. The NRCs program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process, Revision 5.
Cornerstone: Mitigating Systems
- Green.
The inspectors reviewed a self-revealing non-cited violation of 10 CFR Part 50,
Appendix B, Criterion III, Design Control, for failure to assure quality installation of the steam line tubing of the reactor core isolation cooling (RCIC) system. Specifically, the licensee failed to assure that rated performance limits of the ferrule connection, installed at the tee between the steam line and the pressure transmitter tube line, were met during initial installation. This failure resulted in an unplanned inoperability of the RCIC system. The licensee entered this issue into the corrective action program as Condition Report CR-GGN-2014-06792. As an immediate corrective action, the licensee replaced the tubing, the failed transmitter, and recalibrated the instruments. Furthermore, the licensee revised their system operation procedure for the RCIC system. This revision requires all steam isolation valves to be closed during this test, and that system recovery starts by opening Valve 1E51F076 (warming bypass valve around the 1E51F063) to allow adequate warming of the steam lines after isolation.
The inspectors determined that the failure to assure quality installation of the ferrule connection on the steam line flow Transmitter 1E31N083B was a performance deficiency.
The performance deficiency is more than minor and therefore a finding because it is associated with the design control attribute of the Mitigating Systems Cornerstone.
Specifically, failure to assure steam lines in the RCIC system meet rated performance limits, may result in the unavailability and unreliability of a system that is relied upon to respond to initiating events to prevent undesirable consequences. Using NRC Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process for Findings at Power, dated June 19, 2012, the inspectors determined that the issue required a detailed risk evaluation by the regional senior reactor analyst. This was because the finding represented an actual loss of a safety function due to the RCIC system being a single train system that was out of service for approximately 40 hours4.62963e-4 days <br />0.0111 hours <br />6.613757e-5 weeks <br />1.522e-5 months <br /> for repairs. The senior reactor analyst determined the change to the core damage frequency was 8.7E-8/year, and since the change to core damage frequency was less than E-7, no evaluation of external events or the large early release frequency was required. The finding was of very low safety significance (Green). The inspectors did not identify a cross-cutting aspect, as the performance deficiency is not reflective of current plant performance (Section 1R15).
Licensee-Identified Violations
A violation of very low safety significance that was identified by the licensee has been reviewed by the inspectors. Corrective actions taken or planned by the licensee have been entered into the licensees corrective action program. This violation and associated corrective action tracking numbers are listed in Section 4OA7 of this report.
PLANT STATUS
The operators began the inspection period at 100 percent rated thermal power.
On October 17, 2014, the operators reduced power to approximately 75 percent rated thermal power to perform repairs to heater drain pump A, swap steam jet air ejectors, and perform control rod exercises. The operators returned the plant to 100 percent rated thermal power on October 19.
On October 21, 2014, the operators reduced power to approximately 78 percent rated thermal power for a control rod pattern adjustment. The operators returned the plant to 100 percent rated thermal power on October 22.
On November 8, 2014, operators reduced power to approximately 85 percent rated thermal power for control rod pattern adjustment and exercise. The operators returned the plant to 100 percent rated thermal power on November 11.
On November 23, 2014, operators reduced power to approximately 74 percent rated thermal power due to an emergent issue on the grid. The operators returned the plant to 100 percent rated thermal power the same day.
On December 12, 2014, operators reduced power to approximately 47 percent rated thermal power for a monthly control rod pattern adjustment, control rod exercise, and turbine valve testing. The operators returned the plant to 100 percent rated thermal power on December 19.
The plant was maintained at 100 percent rated thermal power for the remainder of the quarter.
REPORT DETAILS
REACTOR SAFETY
Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity
1R04 Equipment Alignment
.1 Partial Walkdown
a. Inspection Scope
The inspectors performed a partial system walk-down of the following risk-significant system:
- November 4, 2014, reactor core isolation cooling system alignment check after overspeed testing The inspectors reviewed the licensees procedures and system design information to determine the correct lineup for the system. They visually verified that critical portions of the system were correctly aligned for the existing plant configuration.
These activities constituted one partial system walk-down sample as defined in Inspection Procedure 71111.04.
b. Findings
No findings were identified.
.2 Complete Walkdown
a. Inspection Scope
On November 5, 2014, the inspectors performed a complete system walk-down inspection of the control room air conditioning system. The inspectors reviewed the licensees procedures and system design information to determine the correct system lineup for the existing plant configuration. The inspectors also reviewed outstanding work orders, open condition reports, in-process design changes, temporary modifications, and other open items tracked by the licensees operations and engineering departments. The inspectors then visually verified that the system was correctly aligned for the existing plant configuration.
These activities constituted one complete system walk-down sample, as defined in Inspection Procedure 71111.04.
b. Findings
No findings were identified.
1R05 Fire Protection
Quarterly Inspection
a. Inspection Scope
The inspectors evaluated the licensees fire protection program for operational status and material condition. The inspectors focused their inspection on four plant areas important to safety:
- November 5, 2014, North East Passage, BOP MCC 12B51, Elevation 139 0 (1A301) and South East Passage, BOP MCC 11B12, Elevation 139 0 (1A302)
- November 5, 2014, South Passage, PCW Primary & Aux Bldg Secondary Pms, Elevation 1390 (1A314)
- November 5, 2014, Standby Gas Treatment SBGT A Train and Standby Gas Treatment SBGT B Train, Elevation 1390 (1A323 and 1A326)
For each area, the inspectors evaluated the fire plan against defined hazards and defense-in-depth features in the licensees fire protection program. The inspectors evaluated control of transient combustibles and ignition sources, fire detection and suppression systems, manual firefighting equipment and capability, passive fire protection features, and compensatory measures for degraded conditions.
These activities constituted four quarterly inspection samples, as defined in Inspection Procedure 71111.05.
b. Findings
No findings were identified.
1R06 Flood Protection Measures
a. Inspection Scope
On October 8, 2014, the inspectors completed an inspection of underground bunkers susceptible to flooding. The inspectors selected two underground bunkers that contained risk-significant or multiple-train cables whose failure could disable risk-significant equipment:
- Inspected manholes 20 and 21 for water intrusion The inspectors observed the material condition of the cables and splices contained in the bunkers and looked for evidence of cable degradation due to water intrusion. The inspectors verified that the cables and vaults met design requirements.
These activities constitute completion of one bunker/manhole sample, as defined in Inspection Procedure 71111.06.
b. Findings
No findings were identified.
1R11 Licensed Operator Requalification Program and Licensed Operator Performance
.1 Review of Licensed Operator Requalification
a. Inspection Scope
On November 13, 2014, the inspectors observed an evaluated simulator scenario performed by an operating crew. The inspectors assessed the performance of the operators and the evaluators critique of their performance. The inspectors also assessed the modeling and performance of the simulator.
These activities constitute completion of one quarterly licensed operator requalification program sample, as defined in Inspection Procedure 71111.11.
b. Findings
No findings were identified.
.2 Review of Licensed Operator Performance
a. Inspection Scope
On October 17, 2014, the inspectors observed the performance of on-shift licensed operators in the plants main control room. At the time of the observations, the plant was in a period of heightened activity due to downpower/control rod exercise/heater drain tank repair.
In addition, the inspectors assessed the operators adherence to plant procedures, including conduct of operations procedure and other operations department policies.
These activities constitute completion of one quarterly licensed operator performance sample, as defined in Inspection Procedure 71111.11.
b. Findings
No findings were identified.
.3 Annual Review of Requalification Examination Results
a. Inspection Scope
The licensed operator requalification program involves two training cycles that are conducted over a 2-year period. In the first cycle, the annual cycle, the operators are administered an operating test consisting of job performance measures and simulator scenarios. In the second part of the training cycle, the biennial cycle, operators are administered an operating test and a comprehensive written examination. For this annual inspection requirement, the licensee was in the first part of the training cycle.
The inspector reviewed the results of the operating tests for the station to satisfy the annual inspection requirements.
On December 18, 2014, the licensee informed the inspector of the following station results:
- 7 of 7 crews passed the simulator portion of the operating test
- 38 of 40 evaluated licensed operators passed the simulator portion of the operating test
- 40 of 40 evaluated licensed operators passed the job performance measure portion of the operating test The individuals that failed the simulator scenario portions of the operating test were remediated, retested, and passed their retake tests. One SRO licensed operator has not yet been evaluated due to illness; the licensee has administratively suspended this operator from watchstanding until he can make up missed training and successfully complete an annual operating test.
These activities constitute completion of one annual licensed operator requalification sample, as defined in Inspection Procedure 71111.11.
b. Findings
No findings were identified.
1R12 Maintenance Effectiveness
a. Inspection Scope
The inspectors reviewed two instances of degraded performance or condition of safety-related structures, systems, and components (SSCs):
- December 15, 2014, standby service water system (P41) near a(1) status
- December 17, 2014, high pressure core spray (E22) near a(1) status The inspectors reviewed the extent of condition of possible common cause SSC failures and evaluated the adequacy of the licensees corrective actions. The inspectors reviewed the licensees work practices to evaluate whether these may have played a role in the degradation of the SSCs. The inspectors assessed the licensees characterization of the degradation in accordance with 10 CFR 50.65 (the Maintenance Rule), and verified that the licensee was appropriately tracking degraded performance and conditions in accordance with the Maintenance Rule.
These activities constituted completion of two maintenance effectiveness samples, as defined in Inspection Procedure 71111.12.
b. Findings
No findings were identified.
1R13 Maintenance Risk Assessments and Emergent Work Control
a. Inspection Scope
On October 15, 2014, the inspectors reviewed one risk assessment performed by the licensee prior to changes in plant configuration, plus the risk management actions taken by the licensee in response to elevated risk for the licensees entry into Orange Risk during a tornado warning while RCIC was inoperable.
The inspectors verified that this risk assessment was performed timely and in accordance with the requirements of 10 CFR 50.65 (the Maintenance Rule) and plant procedures. The inspectors reviewed the accuracy and completeness of the licensees risk assessment and verified that the licensee implemented appropriate risk management actions based on the result of the assessment.
On November 18-19, 2014, the inspectors also observed two emergent work activities that had the potential to affect the functional capability of mitigating systems:
- Licensee entered Yellow Risk after discovering a failed power supply inverter in the RCIC system. The inverter feeds the RCIC speed control system. As a result, the licensee declared the RCIC system inoperable.
- Licensee then discovered a failed overcurrent relay in the division 2 diesel generator. Loss of this relay caused lockout relays to actuate. As a result, the licensee declared the division 2 diesel generator inoperable, and entered Orange Risk due to both the RCIC system and the division 2 diesel generator being simultaneously inoperable.
The inspectors verified that the licensee appropriately developed and followed a work plan for these activities. The inspectors verified that the licensee took precautions to minimize the impact of the work activities on unaffected structures, systems, and components (SSCs).
These activities constitute completion of two maintenance risk assessments and emergent work control inspection samples, as defined in Inspection Procedure 71111.13.
b. Findings
No findings were identified.
1R15 Operability Determinations and Functionality Assessments
a. Inspection Scope
The inspectors reviewed three operability determinations that the licensee performed for degraded or nonconforming structures, systems, or components (SSCs):
- October 8, 2014, operability determination of reactor core isolation cooling steam leak
- December 1, 2014, operability determination for deformed SSW U bolts
- December 16, 2014, functionality determination of switchgear room cooler 1T46-B001B adequate flow The inspectors reviewed the timeliness and technical adequacy of the licensees evaluations. Where the licensee determined the degraded SSC to be operable or functional, the inspectors verified that the licensees compensatory measures were appropriate to provide reasonable assurance of operability or functionality. The inspectors verified that the licensee had considered the effect of other degraded conditions on the operability or functionality of the degraded SSC.
These activities constitute completion of three operability and functionality review samples, as defined in Inspection Procedure 71111.15.
b. Findings
Introduction.
The inspectors reviewed a Green, self-revealing, non-cited violation of Title 10 CFR Part 50, Appendix B, Criterion III, Design Control, for failure to assure quality installation of the steam line tubing of the reactor core isolation cooling (RCIC)system. Specifically, the licensee failed to assure that rated performance limits of the ferrule connection, installed at the tee between the steam line and the pressure transmitter tube line, were met during initial installation. This failure resulted in an unplanned inoperability of the RCIC system.
Description.
On October 2, 2014, while performing Procedure 06-OP-1C61-R-0002, Remote Shutdown Panel Control Check, two sensing lines for the RCIC steam line flow Transmitter 1E31N083B separated from their ferrule tee connection while the control room operators were performing Step 4.1.2.a.6 of Procedure E51 SOI 04-1-01-E51-1, Reactor Core Isolation Cooling System, to return RCIC to standby condition. This resulted in a steam leak in the auxiliary building from the failed sensing lines and required operators to secure the RCIC system by closing Valve 1E51F064, the RCIC outboard steam supply isolation valve. The repair of the damaged tubing, the investigation of the cause of the event, and the extent of condition review resulted in the RCIC system being inoperable for 40 hours4.62963e-4 days <br />0.0111 hours <br />6.613757e-5 weeks <br />1.522e-5 months <br /> more than previously planned.
The inspectors performed a review of the normal standby conditions of the RCIC system and determined that normal steam pressure in the sensing lines is approximately 1,000 pounds per square inch (psi). Both the flow transmitter and the ferrule connection from the main steam line to the transmitter line are rated at pressures much higher than normal conditions (2,000 psi and 6,000 psi respectively). However, the inspectors review of the plants records and simulated testing of the failed parts indicated that a pressure transient of approximately 2,600 psi was present during the event. This transient was due to the sequence of valve manipulations.
Although plant procedures allowed for isolation of the RCIC system by closing 1E51F064 and/or closing both 1E51F063 (inboard isolation valve) and 1E51F076 (warming bypass valve around the 1E51F063), historical records indicated that this test was previously performed using the inboard isolation and bypass valve. The October 2, 2014, event, in which operators isolated the RCIC system by only closing 1E51F064, resulted in steam being trapped behind the outboard valve. When the outboard valve was opened to restore the RCIC system to its standby condition, the trapped steam caused a pressure surge through the lines, and over-pressurized the ferrule connection and the transmitter. Since the peak pressure was still within the rated performance limits of the ferrule connection, the licensee concluded that the ferrule connection was inadequately installed during original construction. Additionally, the inspectors review of historical documents did not reveal any testing or modifications to this ferrule tee connection since original construction.
The licensee documented this issue in Condition Report CR-GGN-2014-06792. As an immediate corrective action, the licensee replaced the tubing and the failed transmitter, and they recalibrated the instruments. Furthermore, the licensee revised their system operation procedure for the RCIC system. This revision requires all steam isolation valves to be closed during this test and that system recovery will begin with the opening of Valve 1E51F076 (warming bypass valve around the 1E51F063) to allow adequate warming of the steam lines after isolation.
Analysis.
The inspectors determined that the failure to assure quality installation of the ferrule connection on the steam line flow transmitter 1E31N083B was a performance deficiency. The performance deficiency is more than minor and therefore a finding because it is associated with the design control attribute of the Mitigating Systems Cornerstone. Specifically, failure to assure steam lines in the RCIC system meet rated performance limits, may result in the unavailability and unreliability of a system that is relied upon to respond to initiating events to prevent undesirable consequences. Using NRC Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) for Findings at Power, dated June 19, 2012, the inspectors determined that the issue required a detailed risk evaluation by the regional senior reactor analyst.
This was because the finding represented an actual loss of a safety function due to the RCIC system being a single train system that was out of service for approximately 40 hours4.62963e-4 days <br />0.0111 hours <br />6.613757e-5 weeks <br />1.522e-5 months <br /> for repairs.
The senior reactor analyst performed the detailed risk evaluation using the Grand Gulf Standardized Plant Analysis Risk model, Revision 8.22, with a truncation limit of 1E-11.
The analyst set the basic event for the reactor core isolation cooling pump failure to start to 1.0. This was slightly more conservative than changing the test and maintenance basic event. The conditional core damage probability, assuming a full year of exposure, was 2.2E-5. The nominal baseline conditional core damage probability was 2.8E-6, so the incremental conditional core damage probability was 1.9E-5. Considering the 40 hour4.62963e-4 days <br />0.0111 hours <br />6.613757e-5 weeks <br />1.522e-5 months <br /> exposure period, the change to the core damage frequency (CDF) was:
CDF = (40 hours4.62963e-4 days <br />0.0111 hours <br />6.613757e-5 weeks <br />1.522e-5 months <br />)/ (8760 hours0.101 days <br />2.433 hours <br />0.0145 weeks <br />0.00333 months <br /> per year)
- 1.9E-5 = 8.7E-8/year Since the CDF was less than E-7, no evaluation of external events or the large early release frequency was required. The finding was of very low safety significance (Green). The dominant core damage sequences included transient and loss of condenser heat sink events followed by the failure of operators to depressurize the reactor vessel, the division 3 standby service water system being in maintenance, and failure of feedwater injection. The low probability of the service water and depressurization basic events minimized the risk. The inspectors did not identify a cross-cutting aspect, as the performance deficiency is not reflective of current plant performance.
Enforcement.
Title 10 CFR Part 50, Appendix B, Criterion III, states, in part, that Measures shall be established to assurethat appropriate quality standards are specified and included in design documents and that deviations from such standards are controlled. Contrary to the above, prior to October 2, 2014, the licensee failed to establish measures to assure that deviations from quality standards, during installation of the steam line tubing of the reactor core isolation cooling system, were controlled.
Specifically, the licensee failed to assure that the rated performance limits of the ferrule connection, installed at the tee between the steam line and the pressure transmitter tube line, were not deviated from during initial installation.
For immediate corrective actions to restore compliance, the licensee replaced the tubing and failed transmitter, and recalibrated the instruments. In addition, the licensee revised its system operation procedure for the RCIC system. This violation is being treated as a non-cited violation (NCV), consistent with Section 2.3.2.a of the Enforcement Policy, because it was of very low safety significance (Green) and it was entered into the licensees corrective action program as Condition Report CR-GGN-2014-06792.
(NCV 05000416/2014005-01, Failure to Assure Quality Installation on RCIC Steam Line)
1R19 Post-Maintenance Testing
a. Inspection Scope
The inspectors reviewed two post-maintenance testing activities that affected risk-significant structures, systems, or components (SSCs):
- November 19, 2014, retesting of the division 2 diesel generator overcurrent relay after the cleaning and recalibrating the relay
- November 19, 2014, the bench calibration of the reactor core isolation cooling system power supply inverter prior to replacement and the post maintenance testing after reinstallation of the power inverter The inspectors reviewed licensing and design-basis documents for the SSCs and the maintenance and post-maintenance test procedures. The inspectors reviewed the work orders with post-maintenance test data to verify that the licensee performed the tests in accordance with approved procedures, satisfied the established acceptance criteria, and restored the operability of the affected SSCs.
These activities constitute completion of two post-maintenance testing inspection samples, as defined in Inspection Procedure 71111.19.
b. Findings
No findings were identified.
1R22 Surveillance Testing
a. Inspection Scope
The inspectors observed two risk-significant surveillance tests and reviewed test results to verify that these tests adequately demonstrated that the structures, systems, and components (SSCs) were capable of performing their safety functions:
- October 28, 2014, reactor core isolation cooling overspeed
- November 20, 2014, average power range monitor calibrations channels 1 through 4 The inspectors verified that these tests met technical specification requirements, that the licensee performed the tests in accordance with their procedures, and that the results of the test satisfied appropriate acceptance criteria. The inspectors verified that the licensee restored the operability of the affected SSCs following testing.
These activities constitute completion of two surveillance testing inspection sample, as defined in Inspection Procedure 71111.22.
b. Findings
No findings were identified.
Cornerstone: Emergency Preparedness
1EP2 Alert and Notification System Evaluation
a. Inspection Scope
The inspector verified the adequacy of the licensees methods for testing the primary and backup alert and notification system (ANS). The inspector interviewed licensee personnel responsible for the maintenance of the primary and backup ANS and reviewed a sample of corrective action system reports written for ANS problems. The inspector compared the licensees alert and notification system maintenance and testing programs with criteria in NUREG-0654, Criteria for Preparation and Evaluation of Radiological Emergency Response Plans and Preparedness in Support of Nuclear Power Plants, Revision 1; FEMA Report REP-10, Guide for the Evaluation of Alert and Notification Systems for Nuclear Power Plants; and the licensees current FEMA-approved alert and notification system design report, Grand Gulf Nuclear Station REP-10 Design Review Report, Dated January 2010 and update letter dated November 27, 2012.
These activities constituted completion of one alert and notification system evaluation sample, as defined in Inspection Procedure 71114.02.
b. Findings
No findings were identified.
1EP3 Emergency Response Organization Staffing and Augmentation System
a. Inspection Scope
The inspector verified that the licensees emergency response organization on-shift and augmentation staffing levels were in accordance with the licensees emergency plan commitments. The inspector reviewed documentation and discussed with licensee staff the operability of primary and backup systems for augmenting the on-shift emergency response staff to verify the adequacy of the licensees methods for staffing emergency response facilities, including the licensees ability to staff pre-planned alternate facilities.
The inspector also reviewed records of emergency response organization augmentation tests and events to determine whether the licensee had maintained a capability to staff emergency response facilities within emergency plan timeliness commitments.
These activities constitute completion of one emergency response organization staffing and augmentation testing sample, as defined in Inspection Procedure 71114.03.
b. Findings
No findings were identified.
1EP5 Maintenance of Emergency Preparedness
a. Inspection Scope
The inspector reviewed the licensees program for maintaining site emergency preparedness capabilities for the period of September 2012 to October 2014, and reviewed the following:
- After-Action reports for emergency classifications and events;
- After-Action evaluation reports for licensee drills and exercises;
- Independent audits and surveillances of the licensees emergency preparedness program;
- Self-Assessments of the emergency preparedness program conducted by the licensee;
- Drill and Exercise performance issues entered into the licensees corrective action program;
- Emergency preparedness program issues entered into the licensees corrective action program; and,
- Emergency response organization and emergency planner training records.
The inspector reviewed summaries of corrective action program reports associated with emergency preparedness during this period and selected 18 to review against program requirements, to determine the licensees ability to identify, evaluate, and correct problems in accordance with the requirements of planning standard 10 CFR 50.47(b)(14) and 10 CFR Part 50, Appendix E, IV.F. The inspector verified that the licensee accurately and appropriately identified and corrected emergency preparedness weaknesses during critiques and assessments.
The inspector verified that the licensee had properly implemented an alternate facility for mustering in the event that access to the site was not available in accordance with the requirements of Appendix E to 10 CFR Part 50, Section IV.E(d). The inspector verified that the licensee had implemented a process for determining protective action recommendations for the public which considered the results of Evacuation Time Estimate studies in accordance with the requirements of Appendix E to 10 CFR Part 50, Section IV.3. The inspector verified that the licensee had performed an analysis of the duties of on-shift emergency response organization personnel in accordance with the requirements of Appendix E to 10 CFR Part 50, Section IV.A(9), and properly maintained that analysis.
These activities constitute completion of one sample of the maintenance of the licensees emergency preparedness program, as defined in Inspection Procedure 71114.05.
b. Findings
No findings were identified.
RADIATION SAFETY
Cornerstones: Public Radiation Safety and Occupational Radiation Safety
2RS2 Occupational ALARA Planning and Controls
a. Inspection Scope
The inspectors assessed licensee performance with respect to maintaining occupational individual and collective radiation exposures as low as is reasonably achievable (ALARA). During the inspection, the inspectors interviewed licensee personnel and reviewed licensee performance in the following areas:
- 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 These activities constitute completion of one sample of occupational ALARA planning and controls, as defined in Inspection Procedure 71124.02.
b. Findings
No findings were identified.
2RS4 Occupational Dose Assessment
Inspection Scope The inspectors evaluated the accuracy and operability of the licensees personnel monitoring equipment, verified the accuracy and effectiveness of the licensees methods for determining total effective dose equivalent, and verified that the licensee was appropriately monitoring occupational dose. The inspectors interviewed licensee personnel, walked down various portions of the plant, and reviewed licensee performance in the following areas:
- External dosimetry accreditation, storage, issue, use, and processing of active and passive dosimeters
- The technical competency and adequacy of the licensees internal dosimetry program
- 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 These activities constitute completion of one sample of occupational dose assessment, as defined in Inspection Procedure 71124.04
b. Findings
No findings were identified.
OTHER ACTIVITIES
Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity, Emergency Preparedness, Public Radiation Safety, Occupational Radiation Safety, and Security
4OA1 Performance Indicator Verification
.1 Drill/Exercise Performance (EP01)
a. Inspection Scope
The inspector reviewed the licensees evaluated exercises and selected drill and training evolutions that occurred between the third quarter 2013 and third quarter 2014 to verify the accuracy of the licensees data for classification, notification, and protective action recommendation (PAR) opportunities. The inspector reviewed a sample of the licensees completed classifications, notifications, and PARs to verify their timeliness and accuracy. The inspector used definitions and guidance contained in Nuclear Energy Institute Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7, to determine the accuracy of the data reported.
These activities constituted verification of the drill/exercise performance indicator, as defined in Inspection Procedure 71151.
b. Findings
No findings were identified.
.2 Emergency Response Organization Drill Participation (EP02)
a. Inspection Scope
The inspector reviewed the licensees records for participation in drill and training evolutions between the third quarter 2013 and third quarter 2014 to verify the accuracy of the licensees data for drill participation opportunities. The inspector verified that all members of the licensees emergency response organization (ERO) in the identified key positions had been counted in the reported performance indicator data. The inspector reviewed the licensees basis for reporting the percentage of ERO members who participated in a drill. The inspector reviewed drill attendance records and verified a sample of those reported as participating. The inspector used definitions and guidance contained in Nuclear Energy Institute Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7, to determine the accuracy of the data reported.
These activities constituted verification of the emergency response organization drill participation performance indicator, as defined in Inspection Procedure 71151.
b. Findings
No findings were identified.
.3 Alert and Notification System Reliability (EP03)
a. Inspection Scope
The inspector reviewed the licensees records of Alert and Notification System tests conducted between the third quarter 2013 and third quarter 2014 to verify the accuracy of the licensees data for siren system testing opportunities. The inspector reviewed procedural guidance on assessing Alert and Notification System opportunities and the results of periodic alert and notification system operability tests. The inspector used definitions and guidance contained in Nuclear Energy Institute Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7, to determine the accuracy of the data reported.
These activities constituted verification of the alert and notification system reliability performance indicator, as defined in Inspection Procedure 71151.
b. Findings
No findings were identified.
.4 Mitigating System Performance Index: Emergency AC Power Systems (MS06), High
Pressure Injection System (MS07), Heat Removal System (MS08), Residual Heat Removal Systems (MS09), and Cooling Water Systems (MS10)
a. Inspection Scope
The inspectors reviewed the licensees mitigating system performance index data for the period of October 2013 through September 2014 to verify the accuracy and completeness of the reported data. The inspectors used definitions and guidance contained in Nuclear Energy Institute Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6, to determine the accuracy of the reported data.
These activities constitute verification of five mitigating system performance indicators:
emergency ac power systems, high pressure injection system, heat removal system, residual heat removal systems, and cooling water systems, as defined in Inspection Procedure 71151.
b. Findings
No findings were identified.
4OA2 Problem Identification and Resolution
.1 Routine Review
a. Inspection Scope
Throughout the inspection period, the inspectors performed daily reviews of items entered into the licensees corrective action program and periodically attended the licensees condition report screening meetings. The inspectors verified that licensee personnel were identifying problems at an appropriate threshold and entering these problems into the corrective action program for resolution. The inspectors verified that the licensee developed and implemented corrective actions commensurate with the significance of the problems identified. The inspectors also reviewed the licensees problem identification and resolution activities during the performance of the other inspection activities documented in this report.
b. Findings
No findings were identified.
.2 Semiannual Trend Review
a. Inspection Scope
On December 9, 2014, the inspectors reviewed Condition Report CR-GGN-2013-06422, as part of an effort to identify trends that might indicate the existence of a more significant safety issue. This condition report addressed a condition where the plant was operating with an offgas inleakage that was much higher than the design value described in the final safety analysis report as updated.
The inspectors performed a detailed historical review of the offgas system, dates ranging from 1994-2014, and determined that although elevated offgas inleakage has been a long-standing issue, the licensees corrective actions were appropriate in that the necessary assessments and evaluations were performed to verify that operating with elevated offgas inleakage did not result in offgas release exceeding any limits set forth in 10 CFR Part 50, Appendix I, 10 CFR Part 20, plant technical specifications, and the offsite dose calculation manual. Furthermore, the inspectors verified the licensee performed appropriate 10 CFR 50.59 screens and determined that operating with elevated offgas inleakage did not require commission approval.
The inspectors assessed the licensees operational decision-making issue (ODMI)process, problem identification threshold, apparent cause evaluation report, cause analyses, and compensatory actions. The inspectors verified that the licensee appropriately prioritized the planned corrective actions and that these actions were adequate to correct the condition.
Documents reviewed by the inspectors are listed in the attachment.
These activities constitute completion of one semiannual trend review sample, as defined in Inspection Procedure 71152.
b. Observations and Assessments The inspectors review of the trends identified above produced the following observations and assessments:
- The licensee has been dealing with this issue of increased inleakage into the offgas system for approximately 20 years, and they have taken actions to reduce the amount of inleakage into the offgas system. For example, they performed online helium gas shoots to determined areas where inleakage occurred and corrected these piping defects when identified. Additionally during the last several refueling outages, the licensee performed various inspections and modifications to reduce the amount of inleakage into the offgas system.
- Prior to Refueling Outage 19 in the spring of 2014 and due to increased inleakage rate after Refueling Outage 18 in June 2012, the licensee put together a task force of plant and industry experts to determine a plan going forward to aggressively deal with this issue. During Refueling Outage 19, they performed an extensive seal steam drain line piping replacements on both ends of the high pressure turbine. Although they reduced the amount of inleakage from 130 SCFM to 100 SCFM into the offgas system, it was still was much higher than what the licensee was expecting.
- Additionally, the licensee is sensitive to the added gaseous effluent release rate due to the increased inleakage. Although the licensee is well within regulatory limits of offsite release rates; they are still working on plans for the upcoming outage to perform additional seal steam drain line piping replacements and other activities to reduce the offgas inleakage rate to approximately 30 SCFM.
- The inspectors determined that although the offgas inleakage issue has been a long standing problem at the site and that it has contributed to a small increase in offsite gaseous effluent release rate, it is still well within regulatory limits. The licensee has actively taken actions over the years to reduce the rate of inleakage to the offgas system and has performed the necessary reviews and evaluations required by regulations due to the increase rate. After reviewing the corrective action plan, the inspectors believe that moving forward, the licensee appears to have a success path in place to reduce inleakage to the offgas system to approximately 30 SCFM as specified in the site final safety analysis.
c. Findings
No findings were identified.
.3 Annual Follow-up of Selected Issues
a. Inspection Scope
The inspectors selected two issues for an in-depth follow-up:
- During the week of November 3, 2014, the inspectors performed in-depth review of items related to security at the site.
The inspectors reviewed condition reports related to the screening of personnel, vehicles, and materials; adequate lighting in the protected area; and correction of deficiencies on vital area doors. The inspectors assessed the licensees problem identification threshold, cause analyses, extent of condition reviews, and compensatory actions. The inspectors verified that the licensee appropriately prioritized the planned corrective actions and that these actions were adequate to address deficiencies.
- On November 19-21, 2014, the inspectors performed a review of operator workarounds.
The inspectors evaluated the licensees implementation of their process used to identify, 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. They also evaluated the potential for improper operation of the system, for negative impacts on multiple systems, and for negative impacts on the operators ability to respond to plant transients or accidents. 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, was entering them into their corrective action program, and was proposing or implementing appropriate and timely corrective actions. 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. 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 two annual follow-up samples, which included one operator work-around sample, as defined in Inspection Procedure 71152.
b. Findings
No findings were identified.
4OA3 Follow-up of Events and Notices of Enforcement Discretion
Partial Loss of Plant Service Water Due to Trip of E and F Pumps a. Inspector Scope On November 4, 2014, at approximately 00:32 AM, plant service water pumps E and F tripped unexpectedly. The operating crew entered Procedure 05-1-02-V-11, Loss of Plant Service Water, Revision 36, and operators and an electrician were dispatched to the radial well pump house five at the river to investigate the pump trips. The control room supervisor established critical parameters limits for component cooling water and turbine building cooling water temperatures to be 100°F. The operating crew started standby plant service water pump J from the main control to increase plant service water supply to the plant. The operating crew stabilized the plant service water flow, discharged pressure, and did not have to reduce plant power. The initial report from the radial well house five was that the pre-lube oil tank for plant service pumps E and F was empty. This was determined to be the cause of the pump trips (trip on a low tank level of 12 gallons). The inspectors verified that the plant systems responded as designed and that the operators stabilized the plant in accordance with station procedures. Through their investigation, the licensee determined that on November 1, 2014, when rounds were performed, the recorded level of the lube oil tank for well five was 52 gallons (two gallons above the minimum level required per procedure). It was also discovered that a discrepancy of approximately 25 gallons existed between the tank level reading in the control room and the actual oil level locally at the tank. The licensee determined that the operator crew failed to evaluate the tank level readings for trending and failed to write a condition report on the adverse trend and the discrepancy in the readings. The licensee entered this event into the corrective actions program and established actions to prevent a repeat of the event, which included an operations department stand down to review the event.
These activities constitute completion of one event follow-up sample, as defined in Inspection Procedure 71153.
b. Findings
No findings were identified.
4OA5 Other Activities
.1 IP 92723 Follow Up Inspection for Three or More Severity Level IV Traditional
Enforcement Violations in the Same Area in a 12-Month Period
a. Inspection Scope
Consistent with the guidance provided in Inspection Procedure 92723, the inspectors evaluated the licensees response to multiple Severity Level IV (SL IV) violations that occurred within a single traditional enforcement area. Specifically, the inspectors examined the licensees response to a number of recent SL IV violations associated with impeding the regulatory process. These violations involved the following regulatory issues:
- Accuracy and completeness of USFSAR (10 CFR 50.71(e)(4))
- Accuracy and completeness of information in License Renewal Process (10 CFR 54.13)
- Failure to report changes to the Emergency Plan (10 CFR Part 54(q))
- Failure to obtain a license amendment prior to implementing a new fluence evaluation (10 CFR 50.59 and 10 CFR 50.90)
Documents reviewed by the inspectors are listed in the attachment. These activities constituted one sample of a follow up inspection, as defined in Inspection Procedure 92723.
b. Findings and Observations
No findings were identified.
.2 (Closed) Violation 05000416/2013201-01: Violation for Grand Gulf 2012 Findings
The inspector reviewed the corrective actions associated with the Severity Level IV violation for failure to provide complete and accurate information to the NRC during licensing reviews, as required by 10 CFR 54.13(a). The violation was documented in Notice of Violation and Inspection Report 05000416/2013201, dated September 18, 2013 (ML13239A398). In addition, the inspector evaluated information provided in Letter GNRO-2013/00083, Reply to Notice of Violation; EA-13-058, dated October 17, 2013 (ML13291A126), as requested in the notice of violation transmittal letter.
During this in-office inspection, the inspector evaluated the corrective actions taken by the licensee to address the notice of violation. The licensee performed a root cause analysis and documented their corrective actions in Condition Report CR-2013-04074.
The licensee used three different tools to determine the root cause: event and causal factor chart, barrier analysis, and change analysis. The licensee evaluated organizational factors and safety culture factors that contributed to the condition.
The licensee attributed the root cause to a lack of sufficient engagement and oversight by station personnel in the development and approval of responses to requests for additional information because the licensee failed to obtain the certification and team reviews required by Procedure EN-LI-106, NRC Correspondence, Revision 9. The licensee identified contributing causes as:
- (1) weaknesses in the governing documents because they failed to describe what should be considered a technically complex issue and
- (2) implementing procedures failed to identify significant wall thinning as an initial screening criterion that required initiation of a condition report. The inspector determined the licensee performed a thorough root cause evaluation.
The inspector verified that the licensee implemented the short-term corrective actions for the contributing causes identified in the root cause analysis. As a corrective action to prevent recurrence, the licensee modified Procedure EN-LI-106 to ensure that the procedure drives the engagement of multiple departments and/or sites when developing responses to requests for additional information when more than one response is referring to the same issue, the issue is technically complex, or when it involves organizations external to the site. The inspector determined that licensee effectiveness reviews verified that the licensee had opportunities to verify effectiveness of request for additional information submittals to the NRC and had identified no concerns.
However, the inspector identified an additional concern during review of the attachment provided to correct the information contained in Letter GNRO-2013/00053, Follow-up Actions from Teleconference held on Thursday, August 1, 2013, related to Pre-Decisional Enforcement Conference between NRC and Grand Gulf held on Tuesday, July 16, 2013, dated August 8, 2013 (ML13221A272). Specifically, the inspector informed the licensee that the revised attachment in Letter GNRO-2013/00083 contained additional incorrect information. The licensee documented this deficiency in Condition Report CR-2014-03515 and initiated a human error evaluation to identify the factors that contributed to this additional inaccurate submittal, which was prepared by the licensing organization. The inspector determined that this violation constitutes an additional example of violation 05000416/2013201-01 and is not being cited individually.
No additional response to violation 05000416/2013201-01 is required.
The licensee identified the following actions contributed to this additional example of providing inaccurate information:
- (1) engineering programs did not take ownership of the certifications and concurrences since they had not developed nor requested to review the response;
- (2) regulatory affairs inappropriately performed certification and concurrence instead of requiring engineering programs to develop the response; and
- (3) regulatory affairs did not maintain their independence and perform the required observations and coaching to ensure that Procedure EN-LI-106, Section 5.4[2](c), was followed.
The inspector determined that the human error evaluation attributed the errors of this additional example to overconfidence on the part of a single individual and to failure to follow Procedure EN-LI-106 by both regulatory affairs and engineering programs personnel. The inspector determined that the error occurred within a few days of the corrective actions being included into Procedure EN-LI-106 and prior to close out of Condition Report CR-2013-04074. The inspector verified that Letter GNRO-2014/00046, Revision to Reply to Notice of Violation EA-13-058, dated July 14, 2014 (ML14195A141), provided the revised accurate description originally requested in the notice of violation cover letter. The inspector noted that the incorrect information occurred within the site organization and did not involve the external interfaces that the effectiveness reviews had been established to evaluate. The inspector determined that had the changes been implemented for a longer period of time, they would likely have prevented this additional error because of the additional formalized peer checks and independent technical reviews.
4OA6 Meetings, Including Exit
Exit Meeting Summary
On January 8, 2015, the inspectors presented the inspection results to Mr. K. Mulligan, Site Vice President of Plant Operations, and other members of the licensee staff. The licensee acknowledged the issues presented. The licensee confirmed that any proprietary information reviewed by the inspectors had been returned or destroyed.
On October 24, 2014, the inspector presented the results of the onsite inspection of the emergency preparedness program to Mr. T. Coutu, Director Regulatory & Performance Improvement, and other members of the licensee staff. The licensee acknowledged the issues presented. The licensee confirmed that any proprietary information reviewed by the inspector had been returned or destroyed.
On November 20, 2014, the inspectors presented the radiation safety inspection results to Mr. T. Coutu, Director, Regulatory Assurance and Performance Improvement, and other members of the licensee staff. The licensee acknowledged the issues presented. The licensee confirmed that any proprietary information reviewed by the inspectors had been returned or destroyed.
On December 18, 2014, the inspector obtained the final annual cycle results and telephonically exited with Mr. R. Liddell, Operations Training Superintendent,. The inspector did not review any proprietary information during this inspection.
On December 31, 2014, the result of the review of the Severity Level IV Violation 05000416/2013201-01 was discussed with Mr. R. Meister, Acting Regulatory Affairs Manager. The licensee acknowledged that the closure of the violation resulted in an additional example of the violation and no new violation would be identified. The inspector confirmed that no proprietary information was reviewed.
4OA7 Licensee-Identified Violations
The following Severity Level IV violation was identified by the licensee and is a violation of NRC requirements, which meets the criteria of the NRC Enforcement Policy, Section 2.3.2.a for being dispositioned as a non-cited violation.
- Title 10 of the Code of Federal Regulations, Appendix E to Part 50,Section V, Implementing Procedures states, in part, that licensees who are authorized to operate a nuclear power facility shall submit any changes to the emergency plan or procedures to the Commission, as specified in 10 CFR 50.4, within 30 days of such changes. Title 10 of the Code of Federal Regulations, Section 50.54(q)(5) states, in part, that licensees shall submit a report of changes made after February 21, 2012, that includes a summary of its analysis, within 30 days after the change is put into effect. Contrary to the above, Grand Gulf Nuclear Station did not submit changes to emergency plan implementing procedures within 30 days of such changes, and did not submit a summary of its analysis of the changes within 30 days after the changes were put into effect.
Specifically, the license did not submit changes to the following procedures; EN-EP-305, Emergency Planning 10CFR50.54(Q) Review Program, Revision 3, EN-EP-306, Drills and Exercises, Revisions 4 and 5, EN-EP-307, Hostile Action Based Drills and Exercises, Revision 2, EN-EP-308, Emergency Planning Critiques, Revision 2, EN-EP-310, Emergency Response Organization Notification System, Revisions 1 through 3, EN-EP-311, Emergency Response Data System (ERDS) Activation Via the Virtual Private Network (VPN), Revision 2, EN-EP-313, Offsite Dose Assessment Using the Unified RASCAL Interface, Revision 0, EN-EP-801, Emergency Response Organization, Revision 8, EN-TQ-110, Emergency Response Organization Training, Revision 7, and EN-TQ-110-01, Fleet E-Plan Training Course Summary, Revision 10.
The licensee did not have a process to ensure that fleet procedures necessary to implement the site emergency plan were submitted to the NRC in accordance with the requirements of Appendix E to 10 CFR 50. This violation was evaluated using the NRC Enforcement Policy because the licensees failure to submit required procedures affected the NRCs ability to perform adequate regulatory oversight. The significance of the violation was evaluated at Severity Level IV (Section 6.6.d of the Enforcement Policy) because it did not affect the licensees ability to perform notification or assessment during an emergency. This issue has been entered into the licensees corrective action program as Condition Reports CR-HQN-2014-00380, CR-HQN-2014-00597, and CR-GGN-2014-05539.
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee Personnel
- C. Boschetti, Manager Nuclear Oversight
T. Burnett - Director Emergency Planning
- T. Coutu, Director, Regulatory Compliance and Performance Improvement
- H. Farris, Assistant Operations Manager
V. Fallacara - General Manager Plant Operations
- M. Godwin, Assistant Operations Manager
- G. Hawkins, Manager, Site Projects
C. Lewis - Manager Emergency Planning
- R. Liddell, Operations Training Superintendent
R. Meister - Senior Licensing Specialist
- M. Milly, Manger, Maintenance
- R. Miller, Manager, Radiation Protection
- K. Mulligan, Site Vice President
J. Nadeau - Manager Regulatory Assurance
- C. Robinson, Regulatory Affairs Manager (departed)
R. Scarbrough - Senior Licensing Specialist
T. Tankersley - Manager Recovery
- T. Thornton, Manager, Design Engineering
- D. Wiles, Director, Engineering
- E. Wright, Supervisor, Radiation Protection
NRC Personnel
- G. Replogle, Senior Reactor Analyst
- J. Gavula, Senior License Examiner, Division of License Renewal
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED
Opened and Closed
- 05000416/2014005-01 NCV Failure to Assure Quality Installation on RCIC Steam Line (Section 1R15)
Closed
- 05000416/2013201-01 VIO Violation for Grand Gulf, 2012 Findings (Section 40A5)
Attachment 1