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	Quarter	Site	Title	Description
05000280/FIN-2012005-01	2012Q4	Surry	Submerged Cables Identified in SAFETY-RELATED Manhole	The inspectors identified a Green non-cited violation of Technical Specification 6.4.A.7, which requires appropriate corrective maintenance procedures which would have an effect on the safety of the reactor. Specifically, Dominion procedure 0-MCM- 1207-01, Pumping of Security and Electrical Cable Vaults, was inadequate to prevent or detect submerged cables in a safety-related manhole, which is a performance deficiency. The inspectors determined that Dominion procedure 0-MCM-1207-01, Pumping of Security and Electrical Cable Vaults was inadequate to accomplish its intended purpose, which constitutes a performance deficiency in accordance with Technical Specification 6.4.A.7, which requires appropriate corrective maintenance procedures which would have an effect on the safety of the reactor. The inspectors determined that the finding was more than minor because it was associated with the mitigating systems cornerstone attribute of equipment performance and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, this condition could lead to cable degradation, increased likelihood of cable failure, and subsequent risk associated with the failure of safety-related equipment. The inspectors screened this finding in accordance with IMC 0609, Significance Determination Process, Attachment 4, Initial Characterization of Findings, dated June 19, 2012, and IMC 0609, Appendix A, SDP for Findings At-Power, dated June 19, 2012 and determined the finding was of very low safety significance, Green, since it was a deficiency determined not to have resulted in the loss of operability or functionality of a single train for greater than its TS allowed outage time. The finding had a cross-cutting aspect in problem identification and resolution, corrective action program, P.1(c), because the corrective actions taken to address previous NRC identified concerns in the same manhole did not thoroughly evaluate the problem such that resolutions addressed the causes.
05000280/FIN-2013005-01	2013Q4	Surry	Application of ASME Section XI, Table IWB 2500-1, Item B10.10, Inspection Requirements and Note 1 Exemptions	The inspectors identified an unresolved item related to the inspection of the reactor pressure vessel (RPV) component supports as required by ASME BPVC Section XI, for which additional information is needed to determine if the issue of concern represents a performance deficiency or a violation of the regulatory requirements. The code of record for the current ISI program at Surry Power Station Unit 1 is the 1998 Edition of the ASME BPVC Section XI with the 2000 addenda. This Code edition includes inspection requirements for both nuclear class 1 piping and vessel supports (Subsection IWF) and their attachment welds (Subsection IWB). Subsection IWB, Table IWB-2500-1, item number B10.10, describes the examination requirements for welded attachments for vessels, piping, pumps, and valves. Note 1 of Table IWB- 2500-1 states that attachment welds (weld buildup) on nozzles that are in compression under normal load conditions and provide only component support are excluded from the surface examination requirements. The note also provides additional conditions to identify what type welded attachment configurations require inspection. Table IWB- 2500-1 also references Figures IWB-2500-13, -14 and -15 to further describe the examination requirements. The inspectors noted that the scope of the Surry Unit 1 ISI program for the inspection of the nuclear class 1 RPV supports did include the requirements for the IWF portion of the ASME Section XI code required inspections. However, the inspectors identified that the licensee excluded the surface examination requirements for the RPV support attachment welds required by Table IWB-2500-1, item number B10.10 based on the exemptions provided by Note 1 of the table. The licensees position was that the surface examinations are not required based on the exclusion criteria provided in Note 1 for attachment welds under compressive loads during normal conditions and the configurations described in Figures IWB-2500-13, -14 and -15. The inspectors reviewed design basis documents for the Unit 1 RPV supports and identified that the normal loading conditions of the supports included both compressive and shear loads. The inspectors determined that additional information and discussion with the NRC Office of Nuclear Reactor Regulation (NRR) staff was required, in order to determine if the licensees interpretation and implementation of the exemptions in Table IWB-2500-1 were in compliance with the ASME BPVC Section XI. Therefore, the NRR and Region II staff agreed to submit a Task Interface Agreement (TIA), which could involve the submittal of a formal inquiry to the applicable ASME BPVC committee to request an interpretation of the examination requirements and exemptions in Table IWB- 2500-1 for welded attachments for vessels and piping. The NRC initiated TIA-2014-02 to determine the staffs position on whether the configuration of the RPV supports at Surry meets the exclusion criteria in ASME BPVC Section XI. This issue remains unresolved until the resolution of TIA-2014-02 to determine if the issue of concern represents a performance deficiency or a violation of regulatory requirements. This issue is identified as URI 05000280/2013005-01, Application of ASME Section XI, Table IWB 2500-1, Item B10.10, Inspection Requirements and Note 1 Exemptions.
05000280/FIN-2015002-01	2015Q2	Surry	Failure to conduct a detailed visual examination of the concrete-liner interface for the Unit 1 containment	An NRC-identified NCV of 10 CFR 50.55a, Codes and Standards, was identified for the licensees failure to conduct a detailed visual examination of the concrete-liner interface for the Unit 1 containment, per the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code (BPVC) Section XI, Subsection IWE 1241, Table IWE-2500-1, Category E-C, Item E 4.11. This issue was documented in the licensees CAP as CR 578448. The licensees failure to conduct a detailed visual examination of the concrete-liner interface of the Units 1 and 2 containment in accordance with the ASME BPVC Section XI, Subsection IWE 1241, Table IWE-2500-1, Category E-C, Item E 4.11, was a PD that was within the licensees ability to foresee and correct. Using Manual Chapter 0612, Appendix B, Issue Screening, dated September 7, 2012, the inspectors determined that the PD was more than minor because, if left uncorrected, it had the potential to lead to a more significant safety concern. Specifically, detailed visual inspections of the containment metallic liner provides assurance that the liner remains capable of performing its intended safety function, and in the absence of such inspections, corrosive conditions could progress to challenge that capability. Using Manual Chapter 0609.04, Initial Characterization of Findings, dated June 19, 2012, the finding was determined to affect the Barrier Integrity Cornerstone. The inspectors screened the finding using IMC 0609, Appendix A, Significance Determination Process (SDP) for Findings at-Power, dated June 19, 2012, and determined that the finding was of very low safety-significance (Green) because the finding did not represent an actual open pathway in the physical integrity of the reactor containment. The team determined that no cross cutting aspect was applicable to this performance deficiency because this finding was not indicative of current licensee performance.
05000280/FIN-2015002-02	2015Q2	Surry	A MDAFW Pump Motor Outboard Bearing Damaged	A self-revealing NCV of Surry Technical Specification (TS) 6.4.D was identified because the Unit 1 A motor driven auxiliary feedwater (MDAFW) pump motor outboard bearing thermocouple was improperly installed while installing a new motor on the MDAFW pump in November, 2013. The improper thermocouple installation in the bearing caused the bearing to fail while the pump was running on January 5, 2015. This issue was documented in the licensees corrective action program (CAP) as condition report (CR) 568663. The inspectors concluded that the failure of the licensee to use a procedure to remove and reinstall the A MDAFW pump motor thermocouples was a performance deficiency (PD). Using Manual Chapter 0612, Appendix B, Issue Screening, dated September 7, 2012, the inspectors determined that the PD was more than minor because it was associated with the human performance attribute of the Mitigating Systems Cornerstone, and it adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the incorrect installation of the motor outboard bearing thermocouple eventually damaged the bearing and caused the A MDAFW pump to become inoperable. Using Manual Chapter 0609.04, Initial Characterization of Findings, dated June 19, 2012, the finding was determined to affect the Mitigating Systems Cornerstone. The inspectors screened the finding using IMC 0609, Appendix A, Significance Determination Process (SDP) for Findings at-Power, dated June 19, 2012, and determined that it screened as Green because the deficiency did not affect the design or qualification of the AFW system and it did not represent a loss of system safety function. This finding has a cross-cutting aspect in the Challenge the Unknown aspect of the human performance area, H.11, because the individuals involved in removing and installing the thermocouples did not stop when faced with a work order that did not have the appropriate procedure reference for the action they were taking.
05000280/FIN-2016004-01	2016Q4	Surry	Change of Surveillance Frequency Caused the Charging Service Water Header to Become Biologically Fouled	A self-revealing NCV of 10 CFR 50, Appendix B, Criterion XVI was identified because the surveillance procedure frequency used to flush the service water (SW) piping in Mechanical Equipment Room (MER)-3 and MER-4 was changed from two weeks to four weeks without sufficiently considering the effects of river conditions on biological growth and without getting management permission to change the periodicity. As a result of the periodicity change, the B charging (CH) and main control room (MCR) SW header became blocked with biological growth and was declared inoperable on September 22, 2016, during the performance of 0-OSP-VS-012, High Flow Flush of SW Strainers and Piping in MER 3 and MER 4. As immediate corrective action, the licensee cleaned the clogged SW strainer and completed the backflushing of the SW header. The SW flushing periodicity was restored to a two week frequency to be seasonally and risk assessed and reduced as heavy fouling season ends. This issue was documented in the licensees corrective action program (CAP) as CR 1048251. The inspectors reviewed Inspection Manual Chapter (IMC) 0612, Appendix B, Issue Screening, dated September 7, 2012, and determined the performance deficiency (PD) was more than minor because it was associated with the equipment performance attribute of the Mitigating Systems Cornerstone, and it adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Using IMC 0609.04, Initial Characterization of Findings, Table 2, dated June 19, 2012, the finding was determined to affect the Mitigating Systems Cornerstone. The inspectors screened the finding using IMC 0609, Appendix A, Significance Determination Process (SDP) for Findings at-Power, dated June 19, 2012, and determined that it screened as Green because the deficiency did not affect the design or qualification of the charging pump service water pump system and it did not represent a loss of system safety function. This finding has a cross-cutting aspect in conservative bias aspect of the human performance area, H.14, because the licensee did not use decision making-practices that emphasize prudent choices over those that are simply allowed.
05000281/FIN-2011002-01	2011Q1	Surry	Reactor Coolant System Instrumentation Erratic Level Indication	On February 2, 2011, while Unit 2 was operating at 100% power, the C loop RCS cold leg loop isolation valve, 2-RC-MOV-2595, experienced stem to disc separation resulting in a low RCS flow condition in the C RCS loop and subsequent automatic reactor trip. The licensee decided to repair the valve in Cold Shutdown by draining the RCS to mid-loop. The RCS standpipe is relied upon to provide both local and remote indication of RCS level during reduced inventory and mid-loop configurations. The licensee drained to reduced inventory and was forced to re-fill the RCS due to the unreliable level indication of 2-RC-LR-200A. Troubleshooting was performed on the 13 Enclosure electronics of the level recorder and associated circuitry and the instrument was tested before a second attempt at draining to mid-loop was commenced. During the second attempt 2-RC-LR-200A again became unreliable and operators were again forced to refill the RCS. The licensee then performed more in-depth troubleshooting of the instrumentation and performed a third drain down to mid-loop conditions once it had been returned to service. The third attempt was successful, although the instruments still experienced several instances of erratic indication. The licensee entered this issue into their CAP as CR413227, and initiated Apparent Cause Evaluation (ACE) 018543. The inspectors require additional information, including the licensees completed investigation in ACE018543 to determine if there is a performance deficiency which is more than minor. This issue is identified as URI 05000281/2011002-01, Reactor Coolant System Instrumentation Erratic Level Indication.
05000281/FIN-2016004-02	2016Q4	Surry	Inadequate Design Change Post Maintenance Testing Causes Water Intrusion into Station Service Transformer and a Reactor Trip	A self-revealing finding was identified because the test requirements section of the station service transformer (SST) design change (DC) was not comprehensive in that it did not test that the isolated phase bus ducting terminal boxes were constructed to prevent water intrusion into the boxes. This was discovered during a significant rainfall event partially caused by Hurricane Matthew, which filled up the A SST terminal box with water and eventually shorted the A phase of the main generator causing a Unit 2 main generator, main turbine, and subsequent reactor trip on October 9, 2016. As corrective action, sealant was applied to the SST terminal boxes on all seams and bolt holes; and weep holes with drain assemblies were installed on each box. This issue was documented in the licensees CAP as CR 1049987. The inspectors reviewed Inspection Manual Chapter (IMC) 0612, Appendix B, Issue Screening, dated September 7, 2012, and determined the PD was more than minor because it was associated with the design control attribute of the Initiating Events Cornerstone, and it adversely affected the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Using IMC 0609.04, Initial Characterization of Findings, Table 2, dated October 7, 2016, the finding was determined to affect the Initiating Events Cornerstone. The inspectors screened the finding using Manual Chapter 0609, Appendix A, SDP for Findings at-Power, dated June 19, 2012, and determined that it screened as Green because although the deficiency did cause a reactor trip, it did not cause a loss of mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition. This finding has a cross-cutting aspect in the Operating Experience aspect of the Problem Identification and Resolution area, P.5, because the licensee did not evaluate and implement relevant external operating experience.
05000287/FIN-2017004-02	2017Q4	Oconee	Failure to Properly Risk Screen Work Within Two Feet of a Single Point Vulnerability Component	A self-revealing Green NCV of Oconee Nuclear Station TS, Section 5.4, Procedures, was identified for the licensees failure to identify and properly risk screen work within 2 feet of a single point vulnerability (SPV) component in accordance with procedure AD-OP-ALL-0201, Protected Equipment. Specifically, the transmission and Oconee organizations failed to recognize that planned maintenance on a breaker in the 525 kilovolt (kV) switchyard was within 2 feet of an SPV component and, as a result, appropriate planning and oversight were not in place to prevent a plant trip during maintenance activities. The licensee entered this issue into their CAP as NCR 02138958. Corrective actions included revisions to station and transmission procedures to ensure inclusion of appropriate SPV program information, addition of the SY special emphasis code to all switchyard type work which require coordination of transmission resources, and the addition of the T1 trip/transient risk special emphasis code to all breaker failure relays in the 230 kV and 525 kV switchyard cabinets containing SPV components.The licensees failure to identify and properly risk screen the planned maintenance on PCB-57 as work within 2 feet of an SPV component in accordance with AD-OP-ALL-0201 was a performance deficiency. The performance deficiency was determined to be more than minor because it was associated with the human performance attribute of the initiating events cornerstone and adversely affected the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, human errors led to a Unit 3 main generator lockout, which resulted in a reactor trip. The finding was assessed using IMC 0609, Attachment 4 and IMC 0609, Appendix A. The inspectors determined the finding was of very low safety significance (Green) because the finding did not represent a transient initiator that caused both a reactor trip and the loss of mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition (i.e. loss of condenser, loss of feedwater). The inspectors utilized IMC 0310, Aspects Within the Cross-Cutting Areas, dated December 4, 2014, and determined the finding had a cross-cutting aspect of work management in the human performance area, because the organization failed to implement a process of planning, controlling, and executing work activities such that nuclear safety is the overriding priority. The work process failed to include the identification and management of risk commensurate to the work and the need for coordination with different groups or job activities. (H.5)
05000287/FIN-2018002-01	2018Q2	Oconee	Failure to Perform ISI General Visual Examinations of Containment Moisture Barrier Associated with Containment Liner Leak Chase Test Connection Piping	The inspectors identified a Green NCV of 10 CFR Part 50.55a, Codes and Standards, involving the licensees failure to properly apply Subsection IWE, of ASME Section XI, for conducting general visual examinations of the leak chase test connection piping at the concrete floor interface which provides a moisture barrier to the containment liner seam welds.
05000302/FIN-2008002-01	2008Q1	Crystal River	Inoperable Fire Penetration Seal	The inspectors identified a Green non-cited violation (NCV) of Crystal River Unit 3 Operating License Condition 2.C(9), Fire Protection Program. The NCV was associated with an inoperable fire penetration seal in the 3-hour fire rated ceiling of the makeup system valve alley. The licensee declared the penetration seal inoperable. Corrective actions included establishing an hourly fire watch and repairing the penetration to its designed condition. The finding adversely affected the fire confinement capability defense-in-depth element. The finding is greater than minor because it is associated with the protection against external factors attribute, i.e., fire, and degraded the mitigating systems cornerstone objective to ensure the availability of systems that respond to initiating events. Using NRC Inspection Manual Chapter (IMC) 0609, Appendix F, Fire Protection Significance Determination Process, the finding was determined to have a very low safety significance since the gap in the fire penetration seal was small (less than 1/8 inch in width)
05000302/FIN-2008002-02	2008Q1	Crystal River	Failure to Implement Adequate Equipment Protection Resulted in a Plant Transient	A self-revealing finding was identified for failure to prevent inadvertent bumping of the condensate pump control switch during maintenance activities. As a result of bumping the control switch, a condensate pump had to be secured and reactor power was rapidly reduced to 61 percent to prevent a reactor trip. Corrective actions included removing the control switch handle to prevent it from being bumped. The finding was more than minor since it affected the equipment performance attribute of the Initiating Events Cornerstone and affected the cornerstone objective of limiting the likelihood of those events that upset plant stability and challenged critical safety functions. The inspectors referenced Inspection manual Chapter 0609.04, Significance Determination process (SDP), Phase 1 screening and determined the finding to be of very low safety significance (Green) because the finding did not contribute to both the likelihood of a reactor trip and the likelihood that mitigation equipment or functions will not be available. A contributing cause of this finding is related to the crosscutting area of human performance, with a work control component. Specifically, the licensee did not adequately plan work activities to protect the condensate pump control switch from being bumped
05000302/FIN-2008002-03	2008Q1	Crystal River	Licensee-Identified Violation	Improved Technical Specification (ITS) 3.3.17, Post Accident monitoring (PAM) Instrumentation, requires, in part, that both channels of the function, Degrees of Subcooling, shall be operable in MODES 1, 2, and 3. ITS 3.3.17, Condition C, states that with one or more functions with two required channels inoperable, restore one channel to operable within 7 days. Contrary to the above, on January 25, 2008, during surveillance testing, the licensee determined that both channels of the function, Degrees of Subcooling, had been inoperable since a software change on August 13, 2007. The inspectors determined that the failure to comply with ITS was of very low safety significance since the Degrees of Subcooling function would have remained available during the most limiting accident conditions (incore temperatures less than 1250oF ). The software change only affected the Degrees of Subcooling function above incore temperatures of 1250oF. This issue is documented in the licensees corrective action program as NCR 263310
05000302/FIN-2008002-04	2008Q1	Crystal River	Licensee-Identified Violation	10 CFR 55.33 (b) states that if an applicants general medical condition does not meet the minimum standards under 55.33(a)(1), the Commission may approve the application and include conditions to accommodate the medical defect. Contrary to the above, one licensed operator stood watch in a TS position as Operator at the Controls on 19 different occasions between July 9 and August 30, 2007, without complying with a newly issued license condition to take prescribed medication while performing licensed duties. Because of the extenuating circumstances that resulted in the operator not being properly informed of the new restriction, compliance with his license was reasonably beyond his control. This finding is of very low safety significance because other licensed operators were available to man the controls and the restricted operator was under supervision at all times. This event is documented in the licensees corrective action program as NCR 244615
05000302/FIN-2008002-05	2008Q1	Crystal River	Licensee-Identified Violation	10 CFR 50, Appendix B, Criterion V, Instructions Procedures and Drawings, requires that activities affecting quality shall be prescribed by documented instructions, procedures or drawings of a type appropriate to the circumstances and these instructions, procedures and drawings shall include appropriate quantitative or qualitative acceptance criteria for determining that the important activities have been satisfactorily accomplished. Contrary to these requirements, there were no written instructions to inform personnel implementing dissimilar metal weld inspections on what to do if the coverage of greater than 90 percent required by MRP-139 is not obtained. This resulted in the plant returning to power from RFO 15 without the ultrasonic examinations being conducted in accordance with the requirements of MRP-139. This finding is determined to be of very low safety significance because the deficiency was identified and examinations that met the requirements of MRP- 139 were performed during a forced outage prior to the due date in MRP-139. The licensee entered the finding into their corrective action program as NCR 270077
05000302/FIN-2009005-01	2009Q4	Crystal River	Failure to Follow a Plant Procedure Resulted in an Inoperable HPI System	A self-revealing Non-Cited Violation (NCV) of Improved Technical Specification (ITS) 5.6.1.1.a was identified for the failure to follow a plant procedure which resulted in a loss of a 480 volt engineered safeguards motor control center (ES MCC)-3B1. Concurrent with pre-existing conditions, the high pressure injection (HPI) system was declared inoperable and ITS 3.0.3 was entered for a period of one hour and 24 minutes. The licensee entered this issue into the corrective action program as nuclear condition report (NCR) 333515. The finding was more than minor since it affected the equipment availability attribute of the mitigating system cornerstone and resulted in ITS 3.0.3 entry for the HPI system being inoperable. The finding was evaluated against NRC Phase 1 Significance Determination Process (SDP) and Phase 2 SDP was required due to a loss safety function of the HPI system. A Regional Senior Reactor Analyst performed a Phase 3 SDP evaluation and concluded this finding was of very low safety significance (Green). The major assumptions of the evaluation were that the HPI function was out of service for exposure period (1 .5 hours) and there would be no recovery of the de-energized motor control center. The dominant accident sequence involved a support system failure of the Emergency Feedwater (EF) Indication and Control System rendering Main Feedwater and automatic control of EF unavailable, operators were unable to manually control EF flow causing its failure and with the HPI function lost due to the performance deficiency, core damage ensued. The inspectors determined the cause of the finding is related to the cross-cutting area of Human performance with a work practices aspect H.4 (c)). Specifically, work scope changes involving safety-related equipment did not receive the appropriate level management oversight resulted in a plant procedural violation
05000302/FIN-2009005-02	2009Q4	Crystal River	Manual Reactor Trip Due to Group 7 Control Rods Insertion Caused by Inadequately Protected Test Jumper	A self-revealing NCV of Improved Technical Specification (ITS) 5.6.1.1.a was identified for the failure to follow the provisions of preventative maintenance procedure PM-126, Electrical Checks of CRD (Control Rod Drive) Power Train. Failure to follow PM-126 caused the failure of the Group 7 control rod programmer during maintenance and resulted in the unexpected insertion of the Group 7 control rods fully into the core. This unexpected insertion of these control rods into the core caused control room operations personnel to manually trip the reactor from 100 percent power. The licensee entered this issue into the corrective action program as NCR 351705. This finding was determined to be more than minor because it was associated with the initiating events cornerstone attribute of Human Performance, and adversely affected the cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during at-power operations. The finding was evaluated using Phase 1 of the At-Power SDP, and was determined to be of very low safety significance (Green) because it did not contribute to both the likelihood of a reactor trip and the likelihood that mitigating equipment or functions were not available. The cause of this finding was directly related to the cross-cutting area of Human Performance with a work practices aspect (H.4 (b)). Specifically, the workers failed to follow the preventative maintenance procedure
05000302/FIN-2009005-03	2009Q4	Crystal River	Licensee-Identified Violation	The following issue of very low safety significance (Green) was identified by the licensee and was a violation of NRC requirements. This issue met the criteria of Section VI of the NRC Enforcement Policy, NUREG-1600, for being dispositioned as a Non-Cited Violation. 10 CFR 26.205(d) requires, in part, that individuals subject to work hour controls do not exceed 26 work hours in any 48-hour period and 72 work hours in any 7-day period; requires a 34-hour break in any 9-day period; and a 10-hour break between successive work periods. During the period of October 12 to October 19, 2009, one worker exceeded 26 hours in a 48-hour period; nine workers exceeded 72 hours in a 7-day period; five workers did not have a 34-hour break in a 9-day period; and two workers did not have the required 10-hour break between successive work periods. The violation was limited to one work group, Florida Transmission Personnel, who were on-site to support outage work. The licensee determined that the Transmission personnel did not have a firm understanding of the revised 10 CFR Part 26 requirements. The finding was more than minor because, if left uncorrected, it would become a more significant safety concern. Specifically, the excessive work hours would increase the likelihood of human performance errors during plant maintenance activities that could affect equipment performance. The finding is of very low safety significance because no significant events or human performance issues were directly linked to personnel fatigue as a result of the hours worked. This issue was documented in the licensees corrective action program as NCR 361777
05000321/FIN-2010002-01	2010Q1	Hatch	Review Licensee\'s EPD Calibration Methodology	The inspectors reviewed calibration records for EPDs at the licensees facility. The licensees EPDs were found to be capable of measuring Deep Dose Equivalent (DDE) and Shallow Dose Equivalent (SDE). The SDE feature was disabled and not used during routine radiological monitoring. EPDs were primarily used to estimate worker exposure for DDE, but were also used as a method of controlling worker exposure for entries in High Radiation Areas in accordance with TS 5.7.1b.The inspectors identified three different methods used to calibrate EPDs. New EPDs purchased directly from the manufacturer were calibrated to a tolerance level of +/-10%of a known Cs-137 source traceable to a United Kingdom National Standard. Subsequent calibrations were performed by the licensees Environmental Laboratory to respond to a tolerance level of +/- 15% of a known Cs-137 source traceable to NIST.EPDs that required repair were sent to a calibration vendor located in West Columbia, South Carolina for repair and subsequently calibrated at that facility to a tolerance level of +/-10% using an Am-241 source traceable to NIST. Licensee procedure 60AC-HPX-017-0, Radiation Protection Instrumentation Program, required radiation survey instruments used to assign or control worker exposure be initially and subsequently calibrated to read within +/-10% of the actual calibration source dose rates using radiation sources traceable to NIST. Additionally, 10 CFR20.1501 (b) requires licensees to ensure that instruments and equipment used for quantitative radiation measurements (e.g., dose rate and effluent monitors) are calibrated periodically for the radiation measured. Although the EPD is not generally used as a substitute for typical dose rate survey meters, it is used to initiate worker actions in lieu of a survey meter in accordance with TS 5.7.1.b which requires incorporation of the EPD into the routine instrument calibration program. From a review of licensee records and discussions with cognizant licensee representatives, the inspectors determined that the licensee had not established a site specific standard for calibrating EPDs or compared the response of the EPDs using the different sources. The use of an Am-241 source, a low level gamma emitter was not representative of the energy ranges in the licensees isotopic mix. In addition, the inspectors determined that the calibrations performed by the licensees environmental laboratory were not consistent with the licensees calibration methods for other instruments used to control worker exposure. This item is unresolved pending NRC review of the licensees evaluation of the EPDs response using NIST traceable sources representative of the energy spectrum of radiation fields at the licensees facility and a review of the licensees specific calibration method for EPDs. URI 05000321, 366/2010002-01, Review Licensees EPD Calibration Methodology.
05000321/FIN-2010002-02	2010Q1	Hatch	Failure to Implement Adequate Configuration Control on Unit 2 Main Generator Stator Water Cooling Temperature Control Instrument Loop, 2N43-F100	A self-revealing finding was identified for the licensees failure to create, implement, and make available to maintenance personnel, quality processes or documents for configuration control. Specifically, the licensee failed to maintain the correct configuration of the stator water cooling (SWC) temperature control instrument loop air operated valve, 2N43-F100, as required by licensee procedure NMP-ES-014, Air Operated Valve Program. The failure to implement adequate configuration control on the SWC temperature control instrument loop directly resulted in a Unit 2 reactor scram on June 20, 2009. The licensee has addressed this issue in their Corrective Action Program (CAP) and developed corrective actions in CR 2009106326. As part of the licensee\'s immediate corrective actions the Unit 2 SWC instrument loop was reconfigured to the correct alignment, and changes were made to procedure NMP-ES-014.This performance deficiency was more than minor because it was associated with the Configuration Control attribute of the Initiating Events cornerstone and adversely affected the cornerstone objective to limit the likelihood of those events that upset plant stability. Specifically, inadequate configuration control resulted in a Unit 2 reactor scram on June 20, 2009. The significance of this finding was screened using the Phase 1 of the Significance Determination Process (SDP) in accordance with NRC Inspection Manual Chapter 0609Attachment 4. Because the finding contributed to a reactor scram, but did not affect mitigation equipment availability, the finding screened as Green. This finding had a crosscutting aspect in the Resources component of the Human Performance area, because the licensee did not provide complete, accurate and up-to-date design documentation, procedures, and work packages, and correct labeling of components. Specifically, the licensee did not implement a means of configuration control of the SWC temperature control instrument loop.
05000321/FIN-2011003-01	2011Q2	Hatch	Failure to promptly identify and take corrective actions to ensure Bussmann fuses identified by the Part 21 notification 2005-37 were removed from use in safety related applications	A self-revealing NCV of 10 CFR 50, Appendix B, Criterion XVI, Corrective Actions, was identified for failure to promptly identify and take corrective actions to ensure Bussmann fuses identified by the Part 21 notification 2005-37, were removed from use in safety related applications. Corrective actions taken include replacing the KTN-R 10 amp fuses on the 1B emergency diesel generator with fuses manufactured after 1991, placing a hold on all KWN-R and KTN-R fuses size 30 amps below manufactured between 1987 and 1991, and replacement of these fuses with new KWN-R and KTN-R fuses with a date code 2009 or newer. This violation has been entered into the licensees corrective action program as condition report (CR) 2010116039. Failure to promptly identify and take corrective actions to ensure Bussmann fuses identified by the Part 21 notification 2005-37 were removed from use in safety related applications is a performance deficiency. This performance deficiency is more than minor because it is associated with the Equipment Performance attribute and adversely affected the Mitigating Systems Cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, on December 23, 2010, the Hatch 1B emergency diesel generator #3 stop circuitry operability light was discovered not illuminated on panel 1R43-P003B. Without power to this circuitry the 1B emergency diesel generator is inoperable and unavailable to provide its required safety function. The significance of this finding was screened using IMC 0609 Attachment 4, table 4a. The risk significance screening required a Phase 3 analysis, because the finding screened as potentially risk significant due to a seismic initiating event. The regional senior reactor analyst (SRA) performed a Phase 3 analysis for the finding. The analysis included two parts, the first covering the time period of total inoperability of the fuse; and the second covering the exposure time from when the non qualified fuses were installed until they were replaced, when they were subject to potential seismic failure. Calculations were performed using the NRCs plant specific risk models. The short exposure time for the first analysis, and the low likelihood of a seismic event at the plant for the second analysis, caused the combined result to be a very low risk condition. The finding was determined to be Green in the SDP. Because the performance deficiency occurred in 2006 and is outside the past three years, no cross-cutting aspect is assigned.
05000321/FIN-2013003-01	2013Q2	Hatch	Licensee-Identified Violation	A licensee-identified violation of 10 CFR 50 Appendix B, Criterion V, Procedures, was discovered on March 18, 2013 when Unit 2 HPCI turbine control valve did not open as expected during the HPCI pump operability 165 psig test. 10 CFR 50 Appendix B, Criterion V, requires in part that activities affecting quality shall be prescribed by documented instructions, procedures, or drawings, of a type appropriate to the circumstances and shall be accomplished in accordance with these instructions. Contrary to this requirement, the licensee failed to correctly install hydraulic lines between the E-GR actuator and the remote servo during performance of Procedure 52PM-E41-002-0, HPCI Turbine and Auxiliaries Major Inspection. The inspectors determined per IMC 0612 Appendix B, Issue Screening, dated September 7, 2012 and IMC 0609, Appendix A, The Significance Determination Process For Findings At-Power, dated July 1, 2012, that a detailed risk assessment was required. Regional senior reactor analysts reviewed the detailed risk assessment which determined the associated risk was less than 1E-6 core damage Frequency and less than 1E-7 large early release frequency due to the short exposure time. Therefore, this violation screened as Green. The licensee entered this violation into their corrective action program as CR 608230.
05000321/FIN-2013003-02	2013Q2	Hatch	Operation with Potential to Drain Reactor Pressure Vessel in Mode 5 Without Secondary Containment	A violation of Unit 2 TS 3.6.4.1 was identified. However, the licensee performed actions to ensure water inventory was maintained and defense in-depth criteria were place prior to performing activities with the potential to drain the reactor vessel as described in Enforcement Guidance Memorandum 11-003. In addition, the violation occurred during the discretion period stated in Memorandum. Therefore, the NRC is exercising enforcement discretion in accordance with Section 3.5, Violations Involving Special Circumstances, of the NRC Enforcement Policy and, therefore, will not issue enforcement action for this violation, subject to a timely license amendment request being submitted.
05000321/FIN-2013007-01	2013Q4	Hatch	Failure to Update the UFSAR Following a Change in Neutron Fluence Calculation Methodology	The inspectors identified an NRC-identified Severity Level IV non-cited violation (NCV) of 10 CFR 50.71(e) for the licensees failure to update the UFSAR following the change in methodology used to calculate reactor vessel neutron fluence. Specifically, the licensee did not completely update the UFSAR to reflect the change in fluence calculation methodology from the General Electric methodology to the Radiation Analysis Modeling Application (RAMA) methodology described in BWRVIP-114-A, BWR Vessel and Internals Project, RAMA Fluence Methodology Theory Manual. The licensee entered this issue into their corrective action program as condition report (CR) 744853. The inspectors determined that the failure to update the UFSAR as required by 10 CFR 50.71(e) was a performance deficiency. The performance deficiency was greater than minor because the failure to provide complete licensing and design basis information in the UFSAR could result in either the licensee making an inappropriate licensing interpretation or the NRC making an inappropriate regulatory decision based on incomplete information in the UFSAR. This performance deficiency was dispositioned using the traditional enforcement process because failing to update a UFSAR had the potential to adversely impact the NRCs ability to perform its regulatory function. The performance deficiency was characterized as a Severity Level IV violation in accordance with the NRC Enforcement Policy (dated July 9, 2013), Section 6.1.d.3. Since this issue was dispositioned using traditional enforcement, there was no cross-cutting aspect associated with this violation.
05000321/FIN-2014002-01	2014Q1	Hatch	Failure to Install Seismic Restraints of the Unit 2 LOCA LOSP Timer Cabinet Doors Following Inspection	The inspectors identified a Green NCV of 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, when the licensee failed to prescribe in documented instructions, procedures, or drawings appropriate to the circumstances the inspection of the Unit 2 loss of coolant accident (LOCA)/loss of offsite power (LOSP) emergency diesel generator loading timers. The licensee restored compliance by adding a step within the operator rounds to confirm the LOCA/LOSP emergency diesel generator loading timer cabinet door fasteners are reengaged and tightened. This violation has been entered into the licensees corrective action program as CR 793669. Failure to engage and tighten the Unit 2 LOCA/LOSP emergency diesel generator loading timer cabinet doors following inspection on January 2, 2014, was a performance deficiency. The performance deficiency was more than minor, because it is associated with the mitigating systems cornerstone protection against external factors attribute and adversely affected the corner objective to ensure the reliability of systems that respond to initiating events to prevent undesirable consequences. Specifically, with none of the latches engaged the reliability of circuitry within the cabinet following a seismic event was adversely affected. The inspectors screened this finding using IMC 0609, Appendix A, The Significant Determination Process (SDP) For Findings At-Power , dated June 19, 2012. The finding screened as Green per Section A. of Exhibit 2, Mitigating Systems Screening Questions, because each of the four screening questions were answered no. The inspectors determined the finding had a cross-cutting aspect of resources in the human performance area because the licensee did not ensure that procedures were available and adequate for performing the nightly inspection of the Unit 2 LOCA/LOSP emergency diesel generator loading timers.
05000321/FIN-2014002-02	2014Q1	Hatch	Failure to Scope Safety System MOVs in the GL 96-05 Periodic Verification Program	The inspectors identified a Green NCV of 10 CFR 50.55a, Codes and Standards, for the licensees failure to establish a periodic verification program for the core spray, high pressure core injection, and reactor core injection cooling systems pump outboard discharge motor-operated valves (MOVs) to ensure their long-term capability to perform their design bases safety functions. The licensee provided operators with interim instructions to declare the affected systems inoperable until permanent corrective actions are implemented. This violation has been entered into the licensees corrective action program as CR 799261. Failure to establish a periodic verification program for the core spray, high pressure core injection, and reactor core injection cooling systems pump outboard discharge MOVs to ensure their long-term capability to perform their design basis safety functions was a performance deficiency. The performance deficiency was more than minor because it adversely affected the equipment performance attribute of the mitigating systems cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, failure to ensure the long-term capability of the valves to perform their design basis safety functions overestimated the availability and reliability of the core spray, high pressure core injection, and reactor core injection cooling systems during testing or other activities that would place the valves in their non-safety position. The inspectors screened this finding using IMC 0609, Appendix A, The Significant Determination Process (SDP) For Findings At-Power , dated June 19, 2012. The finding screened as Green per Section A of Exhibit 2, Mitigating Systems Screening Questions, because each of the four screening questions were answered no. The inspectors determined the finding had a cross-cutting aspect of evaluation in the problem identification and resolution area because in 2013 the licensee had corrective actions in the corrective action program to evaluate the adequacy of the MOV periodic verification program scope and failed to identify that reliance on the valves to reposition when in the closed position required the valves to be in the program.
05000321/FIN-2014002-03	2014Q1	Hatch	Failure to Operate the Unit 2 Master Feedwater Controller In Accordance With Procedures	A self-revealing Green non-cited violation (NCV) of Technical Specification 5.4, Procedures, was identified when an automatic recirculation pump runback occurred after improper operations of the Unit 2 master feedwater controller PF push button. The licensee restored compliance when the crew responded to the runback using approved procedures, and restored reactor water level to the correct setpoint. The violation was entered into the licensees corrective action program as condition report (CR) 759497. Failure to operate the Unit 2 master feedwater controller, 2C32-R600, in accordance with plant procedures on January 17, 2014, was a performance deficiency. This performance deficiency was more than minor because it is associated with the human performance attribute of the initiating events cornerstone and adversely affected the cornerstone objective to limit the likelihood of events that upset plant stability during power operations. Specifically, the performance deficiency directly resulted in an unplanned transient when plant systems automatically reduced reactor power. The inspectors screened this finding using IMC 0609, Appendix A, The Significant Determination Process (SDP) For Findings At-Power , dated June 19, 2012. The finding screened as Green per Section B. of Exhibit 1, Initiating Events Screening Questions, because the finding did not cause a reactor trip and the loss of mitigation equipment, a high energy line-break, internal flooding, or a fire. Inspectors determined the finding had a cross-cutting aspect of avoid complacency of the human performance area because the operator did not implement the error reduction tool (reading the placard below the controller) prior to performing an action.
05000321/FIN-2014002-04	2014Q1	Hatch	Licensee-Identified Violation	A licensee-identified violation of Hatch Unit 1 Technical Specification 5.4, Procedures, occurred on February 10, 2014, when operators withdrew the wrong control rod during performance of procedure 34GO-OPS-066-0, Control Rod Withdrawal in Shutdown or Refuel. Technical Specification 5.4.a. requires in part that written procedures shall be implemented covering the applicable procedures recommended in Regulatory Guide 1.33, Revision 2, Appendix A, February 1978. Regulatory Guide 1.33, Appendix A, Section 1.l. requires procedures for refueling and core alternations. Hatch procedure 34GO-OPS-066-0 is a procedure developed for performing activities during refueling and core alterations. Contrary to the above, on February 10, 2014, the licensee failed to implement procedure 34GO-OPS-066-0 when control rod 42-47 was fully withdrawn outside of procedural controls. This violation screened as Green in accordance with IMC 0609, Appendix G, Figure 1, because the IMC 0609, Appendix G, Attachment 1, Checklist 7, screening did not require a quantitative assessment to be performed. The licensee entered this violation into their corrective action program as CR 771623.
05000321/FIN-2014002-05	2014Q1	Hatch	Failure to institute pre-fire plans for the Units 1 and 2 drywell and torus areas in accordance with the Hatch updated fire hazards analysis	Hatch Unit 1 License Condition 2.C.(3) and Hatch Unit 2 License Condition 2.C.(3)(a) state in part, that Southern Nuclear shall implement and maintain in effect all provisions of the fire protection program, which is referenced in the updated final safety analysis report for the facility, as contained in the updated fire hazards analysis and fire protection program for the Edwin I. Hatch Nuclear Plant, Units 1 and 2, which was originally submitted by letter dated July 22, 1986. Hatch updated Fire Hazards Analysis Section 9.1, Appendix A Fire Protection Program Plan, Subpart 6.2, Pre-Fire Planning, states in part, that pre-fire plans for fighting fires in all safetyrelated areas have been instituted at Hatch Nuclear Plant. Contrary to the above, Southern Nuclear failed to implement and maintain in effect all provisions of the fire protection program, as contained in the updated fire hazards analysis. Specifically, Southern Nuclear failed to institute pre-fire plans for fighting fires in safety-related fire areas 1201, Unit 1 Drywell and Torus and 2201, Unit 2 Drywell and Torus. This violation has existed since initial plant start-up. The licensee entered this violation into their corrective action program as CR 788963. Because the licensee committed to adopt NFPA 805 and change their fire protection licensing bases to comply with 10 CFR 50.48(c), the NRC is exercising enforcement and reactor oversight process (ROP) discretion for this issue in accordance with the NRC Enforcement Policy, Section 9.1, Enforcement Discretion for Certain Fire Protection Issues (10 CFR 50.48) and Inspection Manual Chapter 0305. Specifically, this issue was identified and will be addressed during the licensees transition to NFPA 805, was entered into the licensees corrective action program (immediate corrective action and compensatory measures were taken), was not likely to have been previously identified by routine licensee efforts, was not willful, and it was not associated with a finding of high safety significance (i.e., Red).
05000321/FIN-2015001-01	2015Q1	Hatch	Failure to perform adequate surveys of air samples for alpha activity	An NRC-Identified non-cited violation (NCV) of 10 CFR 20.1501(a) was identified for failure to perform an adequate survey. Air samples obtained in the reactor cavity and on the refuel floor during a contamination event indicating greater than 0.3 beta-gamma Derived Air Concentration (DAC) fraction level were not analyzed for alpha activity as required by the licensees procedures. Previous characterization of the area had determined the area to be an Alpha Level II area requiring additional assessment and evaluation of air samples. This violation was entered into the licensees CAP as CR 10033022. This finding is greater than minor because it was associated with the Occupational Radiation Safety Cornerstone attribute of Program and Process (Monitoring and RP Controls) and adversely affected the cornerstone objective in that failure to identify potentially significant contributors to internal dose could lead to unmonitored occupational exposures. The finding was determined to be of very low safety significance (Green) because it was not related to As Low As Reasonably Achievable (ALARA) Planning and the ability to assess dose was not compromised during these instances. The cause of this finding was directly related to the cross-cutting aspect of leaders ensuing equipment, procedures, and other resources are available and adequate in the Resources component of the Human Performance area.
05000321/FIN-2015001-03	2015Q1	Hatch	Failure to Identify Embedded Conduit prior to Core Drill Operations	A self-revealing non-cited violation (NCV) of 10 CFR 50, Appendix B, Criterion V, Procedures, Instructions, and Drawings, was identified for failure to identify existing embedded conduit in the vicinity of prescribed core drills location. The violation was entered into the licensees corrective action program (CAP) as condition report (CR) 902506. Failure to provide adequate instructions in Design Change Package (DCP) SNC467474 to perform core drills in the Unit 2 control building to support conduit installations was a performance deficiency. This performance deficiency is more than minor because it affected the Equipment Performance attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective in that 2P41F316A was rendered incapable of performing its safety related function of closing in the event of an accident condition. The finding was screened as Green because the inoperability did not last longer than the technical specification (TS) allowed outage time. The inspectors determined the performance deficiency has a cross-cutting aspect of work management in the human performance area, because the licensees work process did not identify and manage the risk commensurate to the core drill work.
05000321/FIN-2015001-04	2015Q1	Hatch	Licensee-Identified Violation	10 CFR Part 50.48(b)(1) required that all nuclear power plants licensed to operate prior to January 1, 1979, must satisfy the applicable requirements of 10 CFR Part 50, Appendix R, Sections III.G.2 or III.G.3. Contrary to the above, since November 1985, the licensee has not met the requirements of 10 CFR Part 50, Appendix R, Sections III.G.2 or III.G.3, in that the licensee failed to provided adequate protection of cables and equipment of redundant trains of systems necessary to achieve and maintain hot shutdown conditions located in the same fire area by either (a) a 3-hour rated fire barrier; (b) 20 feet of spatial separation with detection and suppression installed in the fire area; or (c) a 1-hour rated fire barrier with detection and suppression installed in the fire area; or by providing alternative shutdown capability for the areas where adequate cable protection was not provided. This violation was determined to be of very low safety significance (Green) based on the results of the IMC 0609, Appendix F, Fire Protection Significance Determination Process, Phase III Quantitative Screening Approach. This violation was documented in the licensees CAP as CRs 687178, 688543, 687173, and 692904
05000321/FIN-2015001-05	2015Q1	Hatch	Licensee-Identified Violation	Technical Specification 5.7.2 requires areas with radiation levels greater than or equal to 1000 mrem/hr, measured at 30 cm from the radiation source or from any surface the radiation penetrates, but less than 500 Rads in 1 hour measured at 1 meter from the radiation source or from any surface the radiation penetrates shall be provided with a locked or continuously guarded doors to prevent unauthorized entry. Contrary to this on 12/18/14, a RPT found the Unit 1 Recombiner Preheater B room door propped open and not posted as a LHRA. Follow-up surveys of the area identified maximum radiation levels of 1600 mR/hr at 12 inches from surface of the preheater. This finding was of very low safety significance (Green) because there was no substantial potential for overexposure and the licensees ability to assess dose was not compromised. This violation was documented in the licensees CAP as CAR 249078.
05000321/FIN-2015001-06	2015Q1	Hatch	Unfused DC Ammeter Circuits Result in an Unanalyzed Condition	On April 28, 2014, the licensee submitted an LER documenting the discovery of a condition of non-compliance with the sites fire protection program (FPP). This condition could prevent operators from achieving and maintaining safe shutdown (SSD) of the plant, in the case of a postulated fire. The inspectors reviewed documents related to the LER and discussed the event with plant personnel to assess if the licensees compensatory measures and corrective actions were adequate. The licensee identified a non-compliance with Hatch Renewed License Conditions 2.C.(3) and 2.C.(3)(a), for Units 1 and 2. The licensee failed to provide short circuit protection for non-safety-related associated circuits which could result in a secondary fire in another fire area and adversely affect SSD capability. Description: During a review of industry operating experience (OE) related to unfused DC ammeter circuits the licensee determined that certain DC ammeter circuits lacked short circuit protection. A postulated fire in a fire area containing affected DC ammeter circuit cabling could result in concurrent shorts in the circuit. Due to the lack of short circuit protection, the resultant excessive current flow in the DC ammeter cable could result in a secondary fire in another fire area and adversely affect SSD equipment or cables for SSD equipment. Multiple fire areas in the Control Building were potentially affected. Section 9.6.2.4 of Appendix E of the licensees Fire Hazards Analysis (FHA) categorizes associated circuits of concern into 3 types. Type C associated circuits were defined as nonsafe shutdown circuits which shared a common enclosure with safe shutdown circuits and were not electrically protected by an automatic fault protection device or were not inherently self-protected because the circuit lacks sufficient energy to cause circuit damage. A subsequent paragraph in Section 9.2.6.4 stated that Type C associated circuits are electrically protected by automatic fault interrupting devices, do not carry sufficient energy to cause cable damage, and will not propagate fire into a common enclosure in another fire area. The licensees OE review determined that certain DC ammeter circuits were not provided with automatic fault interrupting devices, and thus, invalidates the SSD evaluation bases stated in Section 9.6.2.4 of the FHA. Upon discovery, the licensee implemented roving fire watches for the affected areas. Analysis: The licensees failure to provide short circuit protection for DC ammeter circuits is a performance deficiency. This finding is more than minor because it is associated with reactor safety mitigating system cornerstone attribute of Protection Against External Events (i.e., fire) and adversely affected the cornerstone objective in that not providing circuit protection could have affected the licensees SSD capability. Because this issue relates to fire protection, and this noncompliance was identified by the licensee as a part of the sites transition to NFPA 805, this issue is being dispositioned in accordance with Section 9.1, Enforcement Discretion for Certain Fire Protection Issues (10 CFR 50.48) of the NRC Enforcement Policy. In order to verify that this non-compliance was not associated with a finding of high safety significance (Red), a bounding phase 3 SDP risk analysis was performed by a regional SRA using the guidance from NRC Inspection Manual Chapter 0609 Appendix F and NUREG/CR 6850 revision 0 and Supplement 1. The analysis used inputs from the licensees NFPA 805 project for ignition frequency and cable routing data. The major analysis assumptions were: a one year exposure period, two proper DC polarity hot shorts required to achieve the high current conditions for secondary fires, and all ignition sources for each affected fire zone assumed to damage the ammeter cables. Based on this bounding risk analysis, the regional SRA determined that this performance deficiency resulted in a CDF increase for each Hatch Unit 1 and 2 of less than 1E-4/year (i.e., less than Red). The licensee also performed a risk assessment using their Hatch fire probabilistic risk assessment model which also produced a result
05000321/FIN-2016001-01	2016Q1	Hatch	Reactor Coolant System N2E Weld Flaw	The inspectors identified an unresolved item associated with a flaw identified in the safe end-to-nozzle weld of the Reactor Coolant System N2E Nozzle. In July 2015, the licensee submitted a proposed alternative to ASME Code, HNP-ISI-ALT-15-01 (ML15183A354), to install a full-structural weld overlay on reactor coolant nozzle N2E (1B31-1RC-12-BR-E). This proposed alternative was approved by the NRC in December 2015 (ML15349A973). The licensee implemented this proposed alternative during the February 2016 refueling outage (1R27). After removing all but 1/16 of the existing overlay, the licensee performed a liquid penetrant examination and noted a pair of linear indications. Subsequently, the licensee determined that these indications were actually a single indication, and that it exceeded allowable size limitations according to ASME Code. Upon further review, the licensee realized that these indications were potentially the result of growth of an inner-diameter, surface-connected intergranular stress corrosion cracking (IGSCC) flaw found in 1988. The licensee has repaired the flaw, installed the full-structural weld overlay, and completed all required post-installation examinations. This is an unresolved item pending review of whether the licensee performed all required examinations of the N2E nozzle between 1988 and 2016, and whether the flaw exceeded minimum wall limitations at some point during prior operation. The issue will be tracked as URI 05000321/2016001-01, Reactor Coolant System N2E Weld Flaw.
05000321/FIN-2016003-01	2016Q3	Hatch	Unit Downpower Caused by RFP Vent Line Failure	A self-revealing finding was identified when the licensee failed to install a reactor feed pump (RFP) vent line weld in accordance with plant procedures resulting in a failure that required an unplanned Unit 1 power reduction greater than 20%. Failure to install the correct weld thickness on the unit 1 B RFP vent line, as required by procedures, was a performance deficiency. This performance deficiency was more than minor because it was associated with the Equipment Performance attribute of the Initiating Events cornerstone and adversely affected the cornerstone objective in that an unplanned reactor power reduction was required from 100 percent to 60 percent RTP. The inspectors determined this finding was of very low safety significance (Green) because there was not a reactor trip or loss of mitigation equipment. The inspectors determined that this finding had a cross-cutting aspect in the Resolution aspect of the problem identification and resolution area, because the organization did not take effective corrective actions to address the previous weld configuration issue. (P.3)
05000321/FIN-2016003-02	2016Q3	Hatch	Failure to Ensure Work Hours are Within Work Hour Limits	An NRC-identified non-cited violation (NCV) of 10 CFR Part 26, Fitness for Duty Programs, was identified when the licensee failed to ensure that personnel subject to work hour controls did not exceed 72 hours in a work week. The licensee entered this condition into their corrective action program as Condition Report 10214872 and restored compliance when the affected individuals received an adequate rest period. The failure to ensure that work hours for personnel subject to work hour controls were tracked in accordance with licensee procedures was a performance deficiency. The finding was more than minor because, if left uncorrected, the failure to appropriately implement work hour limitations for covered workers could adversely impact the conduct and oversight of work on safety significant components. The inspectors determined that the finding was of very low safety significance (Green) because the finding did not result in an adverse impact to plant safety due to worker fatigue. The inspectors determined this performance deficiency had a cross-cutting aspect of Consistent Process in the Human Performance area because the licensee failed to assess which workers were subject to work hour limits. (H.13)
05000321/FIN-2016010-02	2016Q2	Hatch	Failure to Identify N2E Nozzle Weld Through-Wall Flaw	The inspectors identified a Green NCV of 10 CFR 50, Appendix B, Criterion XVI, Corrective Actions, for the licensees failure to promptly identify a condition adverse to quality regarding a through-wall flaw in the safe end-to-nozzle weld of the reactor coolant system N2E nozzle. The licensee has since repaired the flaw, completed all required postrepair examinations, and entered this issue entered this into their corrective action program as CR 10247856. The performance deficiency was more than minor because it was associated with the Equipment Performance attribute of the Initiating Events cornerstone and adversely affected the cornerstone objective of limiting the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. The inspectors screened this finding using IMC 0609, Appendix A, The Significance Determination Process (SDP) For Findings At-Power, dated June 19, 2012. Because after a reasonable assessment of degradation, the finding could neither result in exceeding the RCS leak rate for a small LOCA, nor likely affected other systems used to mitigate a LOCA resulting in a total loss of their function, the finding screened as Green. This finding has a cross-cutting aspect of Challenge the Unknown in the area of Human Performance (H.11) because upon discovery of a less robust configuration of the N2E nozzle overlay, the licensee failed to consider the implications on the flaw that had existed in that component since 1988.
05000321/FIN-2017001-02	2017Q1	Hatch	Licensee-Identified Violation	Unit 2 Technical Specification 3.6.1.3 requires each PCIV be operable in Mode 1. With one PCIV inoperable, the affected penetration flow path must be isolated by use of at least one closed and de -activated automatic valve, closed manual valve, blind flange, or check valve with flow through the valve secured. Contrary to the above, on November 6, 2016 at 21:51 operators tagged valve 2E41F111, a PCIV, open with the breaker off. Subsequently, a licensed operator performing a main control room board walk down noted the PCIV was inoperable and, on November 8 at 0151, operators closed and de -activated an automatic valve in the line to rest ore compliance. Inspectors screened the finding in accordance with IMC 609 Appendix A The Significance Determination Process (SDP) for Findings at -Power. The finding screened as very low safety significance (Green) because the questions in Appendix A E xhibit 3 for reactor containment were answered no. This issue was documented in the licensees corrective action program as CR 10295889. (Section 4OA3.2)
05000321/FIN-2017001-03	2017Q1	Hatch	Licensee-Identified Violation	Technical Specification 5.7.1 requires, in part, entrances into areas in which the intensity of r adiation is > 100 mrem/hr but < 1000 mrem/hr, measured at 30 cm from the radiation source or from any surface the radiation penetrates, to be controlled by requiring issuance of a Radiation Work Permit (RWP). Contrary to this, On September 9, 2016, two in dividuals entered a High Radiation Area in the Unit 2 SE Diagonal 87' elevation to calibrate an RHR Service water transmitter without the proper briefing or RWP. The individuals were briefed and permitted to enter the HPCI Room area instead of this area. This finding was of very low safety significance (Green) because there was no substantial potential for overexposure and the licensees ability to assess dose was not compromised. The immediate corrective actions were documented in CR 10271667. The long term corrective actions include continuing training suc h that all craft personnel are exposed to the remediation scenario. (Section 2RS1 )
05000321/FIN-2018001-01	2018Q1	Hatch	Failure to comply with Type B shipping container Certificate of Compliance (CoC) requirements.	An NRC Identified Green NCV of 10 Code of Federal Regulations (CFR)71.17, General license: NRC-approved package, was identified for the licensees failure to comply with the Type B shipping container Certificate of Compliance (CoC) requirements. 10 CFR 71.17(c)(2)states, in part, that a holder of a General license to utilize an NRC-approved package shall comply with the terms and conditions of the license, certificate, or other approval, as applicable, and the applicable requirements of subparts A, G, and H of this part. Specifically, on several occasions the licensee placed in transit Type B containers which did not pass the CoC leak test requirement(s).
05000321/FIN-2018001-02	2018Q1	Hatch	Licensee-Identified Violation	This violation of very low safety significant was identified by the licensee and has been entered into the licensee corrective action program and is being treated as a Non-Cited Violation, consistent with Section 2.3.2 of the Enforcement Policy. Violation: Hatch Nuclear Plant Technical Specification (TS) 5.7.2 states in part, areas with radiation levels greater than 1000 mRem/hr, measured at 30 cm from the radiation source or from any surface the radiation penetrates, but less than 500 Rads in 1 hour measured at 1 meter from the radiation source or from any surface that the radiation penetrates, shall be provided with locked or continuously guarded doors to prevent unauthorized entry.Contrary to the above, February 6, 2018, the licensee identified dose rates of 72 Rem/hr on contact, and 3.9 Rem/hr at 30 cm on the U-1 bottom head drain valve located in the 127 foot elevation of the Subpile room, in the Unit 1 Drywell. For approximately 4 hours, the entrance to the room was not locked or continuously guarded to prevent unauthorized entry as required by TS 5.7.2. Significance/Severity: The finding was of very low safety significance (Green) because it was not an as low as reasonably achievable (ALARA) planning issue, there was no overexposure nor potential for an overexposure, and the licensees ability to assess dose was not compromised.Corrective Action Reference(s):The licensee identified and documented the failure to control access to the Lock High Radiation Area (LHRA) in Condition Report 10458608.
05000324/FIN-2008002-01	2008Q1	Brunswick	Review Adequacy of Suppression Pool Temperature Monitoring System Calibration Relative to Technical Specification SR 3.3.3.1.3 Channel Calibration	While reviewing the SPTMS, the inspectors noted that the licensee performs the channel calibration of the complete Suppression Chamber Water Temperature instrumentation loop, including the sensors in two steps. Surveillance Requirement 3.3.3.1.3 requires the licensee to perform channel calibration for each required Post Accident Monitoring (PAM) Instrumentation channel, every twenty-four months. The licensee performs the required calibration in accordance with 0MST-AMI27R and 28R, AMI Div 1 (and II) Suppression Pool Temp Monitor Cal which is an electronic calibration and functional test of the SPTMS microprocessor, recorders and associated input/output based on substitution of M&TE signals in place of the normal resistance temperature detectors (RTDs) inputs. This test does not address the RTDs themselves or the associated cables and connectors. The balance of the calibration is performed in accordance with 1OI-03.1 and 2OI-03.2, Control Operator Daily Surveillance Report. The daily surveillance is a channel check that identifies RTDs that misbehave in a non-gross manner (e.g., drift high or low without reaching the automated gross failure limit). The inspectors are reviewing this methodology of calibration to ensure that the entire loop has a calibration check performed every twenty-four months and that the channel responds to measured parameter changes with the required range and accuracy. As a result of inspectors questions, the licensee initiated AR 267562. Information associated with the validity of this type of calibration is still under review. Pending further NRC review of additional information provided by the licensee, this issue will be identified as URI 05000325,324/2008002-01, Review Adequacy of Suppression Pool Temperature Monitoring System Calibration Relative to SR 3.3.3.1.3 Channel Calibration
05000324/FIN-2008003-04	2008Q2	Brunswick	Evaluate Representativeness of Particulate Sampling for the Reactor Building Roof Vent Monitors, Turbine Building Wide Range Gas Monitors and Plant Stack Wide Range Gas Monitors	An unresolved item (URI) was identified regarding the representativeness of radioactive particulate sampling by the sampling skids used to monitor gaseous effluent releases from the turbine building ventilation system, reactor building roof vent, and plant stack. During plant walk-downs, the inspectors identified one or more T connections and/or elbows on the inlet side of the particulate filter on each of the specified monitoring skids. The licensee had no evaluation of the impact of these bends on the transmission of particles through the sampling lines. The licensee has contacted the vendor requesting documentation of particle transmission studies that may have been performed for the monitors. This item is unresolved pending NRC review and evaluation of any vendor supplied documentation on the particle transmission data obtained by the licensee. URI 05000325,324/2008003-01, Evaluate Representativeness of Particulate Sampling for the Reactor Building Roof Vent Monitors, Turbine Building Wide Range Gas Monitors, and Plant Stack Wide Range Gas Monitors
05000324/FIN-2008004-01	2008Q3	Brunswick	Licensee-Identified Violation	Technical Specification 5.4.1, Administrative Control (Procedures), requires that written procedures shall be established, implemented, and maintained covering applicable procedures recommended in Regulatory Guide 1.33, Appendix A, November 1972. Regulatory Guide 1.33, Section D (7) states, in part, that instructions for energizing, filling, venting, draining, startup, shutdown, and changing modes of operation should be prepared, as appropriate for the Emergency Core Cooling System. Contrary to the above, the licensees procedure OP-19, HPCI System Operating Procedure, Revision 112, was inadequate because it contained unclear actions which resulted in a main pump seal failure from an inadequate fill and vent of the Unit 1 HPCI system crossaround piping after a complete drain and refill during outage B117R1. On April 29, 2008, as a result of inadequate venting of the HPCI pump, the inboard seal failed. This issue is more than minor because it affects the Mitigating Systems Cornerstone objective of ensuring the availability, reliability and capability of systems that respond to initiating events to prevent core damage and is associated with the cornerstone attribute of equipment performance. This finding is of very low safety significance because the HPCI pump did not exceed its allowed TS outage time. This issue has been entered into the CAP as AR 277188
05000324/FIN-2008004-02	2008Q3	Brunswick	Licensee-Identified Violation	Technical Specification 5.4.1, Administrative Control (Procedures), requires that written procedures shall be established, implemented, and maintained covering applicable procedures recommended in Regulatory Guide 1.33, Appendix A, November 1972. Regulatory Guide 1.33, Section I (1) states that maintenance that can affect the performance of safety-related equipment should be properly preplanned, and performed in accordance with written procedures, documented instructions, or drawings appropriate to the circumstances. Contrary to the above, the licensees procedure 0CM-PHM504, Pacific Pumps, Model RHCH, HPCI main pump maintenance, Revision 7, was inadequate because the pump was reassembled with an improper clearance between the seal sleeve and seal plate bushing. On July 18, 2008, the main pump inboard seal failed due to excessive heating at the shaft sleeve due to contact between the seal plate bushing and the shaft sleeve such that the shaft sleeve set screw force applied to the shaft was relieved, and the pump internal pressure forced the seal sleeve out 1/8 inch. This 1/8 inch extension caused excessive force to be applied on the seal faces which resulted in premature failure due to seal face overheating followed by a quench. This issue is more than minor because it affects the Mitigating Systems Cornerstone objective of ensuring the availability, reliability and capability of systems that respond to initiating events to prevent core damage and is associated with the cornerstone attribute of equipment performance. This finding is of very low safety significance because the HPCI pump did not exceed its allowed TS outage time. This issue has been entered into the CAP as AR 287869
05000324/FIN-2008004-03	2008Q3	Brunswick	Licensee-Identified Violation	Technical Specification Limiting Condition for Operation 3.4.3, Safety/Relief Valves, requires 10 safety/relief valves to be operable while in Mode 1 with their lift setpoints within a specified range. Contrary to this, during surveillance testing on safety/relief valves removed from Unit 2 during the Spring 2007 refueling outage (B218R1), four of the eleven valves actuated at pressures outside the technical specification limits. This finding is of very low safety significance because the as-found lift setpoint conditions of the Unit 2 safety/relief valves were analyzed and determined to meet the design basis criteria for an over-pressurization event. This issue has been entered into the CAP as AR 287535
05000324/FIN-2008004-04	2008Q3	Brunswick	Licensee-Identified Violation	10 CFR 50.65(a)(4) states, in part, that before performing maintenance activities, the licensee shall assess and manage the risk that may result from the proposed maintenance activities. Contrary to the above, the licensee did not perform an adequate risk assessment of switchyard activities which involved operating a test device in the generator terminal current sensing circuitry in the switchyard relay house. Unit 2 automatically scrammed due to a spurious power load unbalance (PLU) turbine trip signal while the unit was in operation at 100% rated thermal power. This spurious signal was determined to be generated from the maintenance activities in the switchyard. The licensee determined that procedure 0AP-025 BNP Integrated Scheduling, which was used to implement Engineering Change, 68642, Digital Fault Recorder Replacement (Switchyard), did not adequately evaluate the post modification testing to be performed on the PLU circuit, and therefore did not characterize the maintenance as a contributor to the risk of a plant transient or reactor scram. The finding is of very low safety significance because the incremental core damage probability deficit is less than 1E-6 and the incremental large early release probability deficit is less than 1E-7. This issue has been entered into the CAP as AR 294164
05000324/FIN-2010002-01	2010Q1	Brunswick	Failure to Follow Procedures During Reactor Head Disassembly	A self-revealing Green NCV of Technical Specifications (TS) 5.4.1, Procedures, was identified when reactor head piping was disconnected prior to swapping shutdown range reactor water level transmitters resulting in inaccurate water level indication. The plant procedure for disconnection of the reactor head piping, 0SMP-RPV501, Reactor Vessel Disassembly, used in conjunction with 0GP- 06, Cold Shutdown to Refueling, specifies that prior to removal of head piping, the Shutdown Range Reactor Water Level Transmitters shall be swapped from level transmitters, B21-LT-N027A and B21-LT-N027B, to level transmitters, B21-LT-7468A and B21-LT-7468B. Contrary to this requirement, the common reference leg to the level indicators was disconnected prior to swapping transmitters which resulted in loss of accurate indication of current reactor vessel water level. The licensee reinstalled the disconnected piping, refilled the reference legs for the transmitters, and entered the issue into their corrective action program (AR #383779). The disconnection of the reference leg flange of the reactor vessel head piping prior to realignment of level instrumentation as required by plant procedures is a performance deficiency. The performance deficiency was more than minor because it is associated with the configuration control attribute of the Mitigating Systems cornerstone because it inappropriately altered the reactor level instrumentation reference leg piping. It affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The inaccurate level indication degraded the operators ability to control the reactor vessel water level in the prescribed procedural band and would inhibit their ability to diagnose and prevent loss of residual heat removal (RHR) scenario. In accordance with NRC Inspection Manual Chapter (IMC) 0609, Appendix G, Shutdown Operations Significance Determination Process, Attachment 1, Checklist 8, the inspectors conducted a Phase 1 SDP screening and determined the finding required a Phase 2 analysis. The Phase 2 analysis determined the finding is of very low safety significance (Green) because adequate mitigation capability was maintained. The cause of this finding was directly related to the supervisory and management oversight cross-cutting aspect in the work practices component of the Human Performance cross-cutting area because plant supervisors failed to ensure an adequate pre-job brief, failed to enforce proper communications methods at the job site, and failed to properly supervise workers executing procedure steps (H.4(c))
05000324/FIN-2010002-02	2010Q1	Brunswick	Inadequate Risk Evaluation for Removing the 1A South Condenser from Service	The inspectors identified a Green NCV of 10 CFR Part 50.65 (a)(4), Requirements for monitoring the Effectiveness of Maintenance at Nuclear Power Plants, after Unit 1 experienced a loss of normal reactor feedwater as a result of an abnormal plant configuration during shutdown of the reactor on February 26, 2010. The licensee did not adequately manage the increase in risk that resulted when the 1B reactor feed pump (RFP) was made unavailable while the 1A south condenser was isolated in the hours leading up to the reactor shutdown. This plant configuration led to a high level in the 1A south condenser hotwell soon after the reactor shutdown, which prevented adequate draining of the 1A RFP turbine casing, and led to the loss of the 1A RFP. After the loss of normal feedwater to the reactor, the licensee restored reactor level using the reactor core isolation cooling (RCIC) system. The licensee entered the issue into its corrective action program (AR #383636). The failure to adequately evaluate and manage risk associated with equipment configuration during the Unit 1 shutdown is a performance deficiency. This finding is more than minor because it is associated with the initiating events cornerstone attribute of configuration control and it adversely affected the cornerstone objective of limiting the likelihood of those events that upset plant stability and challenge critical safety functions. Specifically, plant stability was upset by the loss of normal feedwater to the reactor. In accordance with IMC 0609, Appendix K, Maintenance Risk Assessment and Risk Management Significance Determination Process, this finding is of very low safety significance (Green) because the Incremental Core Damage Probability Deficit is <E-6 and the Incremental Large Early Release Probability Deficit is <E-7. The inspectors determined that this finding had a crosscutting aspect in the area of human performance, work control component, because the licensee did not appropriately plan work activities by incorporating risk insights (H.3(a)). Specifically, activities scheduled prior to the reactor shutdown were not properly evaluated to determine their impact on the normal reactor feedwater system.
05000324/FIN-2010002-03	2010Q1	Brunswick	Failure to Ensure Representative Sampling of Particulate Effluents Released from the Reactor Building Roof Vent	The inspectors identified a Green NCV of 10 CFR 20.1302(a) for failure to ensure surveys of particulate radioactive materials in effluents released to unrestricted areas from the reactor building roof vent were adequate to demonstrate compliance with dose limits for individual members of the public. This issue was initially identified as an unresolved item following an inspection in June 2008. The licensee entered the issue into its corrective action program (AR #292216 and AR #393340). The licensee is currently investigating this issue to identify applicable corrective actions. The failure to ensure that the reactor building roof vent effluents were adequately monitored is a performance deficiency. This finding is more than minor because it is associated with the Public Radiation Safety Cornerstone attribute of Plant Facilities/Equipment and Instrumentation (Process Radiation Monitors) and adversely affects the cornerstone objective. Specifically, the cornerstone objective of providing assurance that adequate protection of public health and safety from exposure to radioactive materials released into the public domain as a result of routine civilian reactor operation was affected because the licensee did not ensure that reactor building effluents were accurately monitored. The finding was evaluated using the Public Radiation Safety SDP and determined to be of very low safety significance (Green). The finding, which involved the effluent release program, was determined to be of very low safety significance (Green) because it was not a failure to implement the effluent program and did not result in public dose exceeding the 10 CFR 50 Appendix I criterion or 10 CFR 20.1301(e). This finding does not have a cross-cutting aspect because the failure to evaluate the effect of line losses on particulate sampling is a historical issue

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