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| Quarter | Site | Title | Description | |
|---|---|---|---|---|
| 05000335/FIN-2012004-02 | 2012Q3 | Saint Lucie | Failure to Implement Procedure EN-AA-205, Design Change Packages | A self-revealing, non-cited violation (NCV) of Technical Specification (TS) 6.8.1, was identified which requires written procedures be established, implemented, and maintained covering activities referenced in NRC Regulatory Guide 1.33, Revision 2, dated February 1978, including safety-related activities carried out during operation of the reactor plant. The licensees safety-related design control procedure EN-AA-205, Design Change Packages, was not implemented as written when a plant modification was performed on the reactor regulating system and steam bypass control system that affected a safety-related maintenance procedure that was not revised to reflect the design change. The licensee entered this violation in their corrective action program as action request 1786565. The licensees failure to fully implement procedure EN-AA-205, Design Change Packages, was a performance deficiency. The finding was determined to be more than minor because if left uncorrected, the deficiency could lead to a more significant safety concern. The inspectors evaluated the risk of this finding under the initiating events cornerstone using IMC 0609, Significance Determination Process, Appendix G, Shutdown Operations Significance Determination Process. The inspectors determined that the finding was of very low safety significance because it did not require a quantitative assessment as determined in Checklist 1. The finding involved a crosscutting aspect of complete and accurate procedures in the resources component of the human performance area (H.2.(c)). Specifically, the licensee failed to ensure that an adequate maintenance procedure was up to date to prevent an unexpected reactor plant temperature transient. |
| 05000335/FIN-2012004-03 | 2012Q3 | Saint Lucie | Licensee-Identified Violation | 10 CFR 20.1501(a)(2) requires licensees to make or cause to be made surveys that are reasonable under the circumstances to evaluate the magnitude and extent of radiation levels, concentrations or quantities of radioactive material, and the potential radiological hazards. Furthermore, 10 CFR 20.1003 defines a survey as an evaluation of the radiological conditions and potential hazards incident to the presence of radioactive material. Contrary to the above, on August 12, 2012, the licensee performed Tri-Nuc filter (vacuum) maintenance activities in the Unit 2 containment lower cavity without an adequate evaluation of the potential for the contamination to disperse and impact workers performing maintenance activities in the upper cavity area and containment. Specifically, the workers within the lower cavity who were supplied with bubble hood respiratory protective equipment disturbed elevated levels of alpha contamination within the lower cavity while moving their tangled respirator lines. Dispersion of these contaminants to the upper cavity area and containment was exacerbated by operation of the containment coolers and purge exhaust. The dispersed contamination resulted in unanticipated elevated airborne concentrations of radionuclides in the upper cavity and containment with subsequent intakes by workers involved with polar crane operation and upper cavity reactor head maintenance activities. The elevated airborne levels were discovered approximately one hour after the start of the lower cavity work through the evaluation of routine air samples collected for the work in the upper cavity. Immediate corrective actions taken upon discovery included evacuation of the Unit 2 containment and whole-body counting of all potentially impacted workers. The whole-body count evaluations identified eight workers with potential intakes of radioactive materials. Detailed analyses of whole-body count data and air sample results to identify hard-todetect radionuclides (alpha-emitters) for the affected workers resulted in a maximum assigned committed effective dose equivalent (CEDE) of 24.4 millirem (mrem) to one individual. For the other seven individuals identified with positive intakes, licensee estimates of dose (CEDE) were less than 10 mrem. An apparent cause evaluation performed by the licensee determined the causes to be inadequate work practices and planning. The corrective actions were documented under AR 01793148. The violation was evaluated using the Occupational Radiation Safety Significance Determination Process and was determined to be of very low safety significance (Green) because this finding was not an over-exposure, did not have a substantial potential for over-exposure because of continuous air monitors (CAMs) that would have alarmed with increasing airborne levels, and the ability of the licensee to assess dose was not compromised. |
| 05000335/FIN-2015010-01 | 2015Q4 | Saint Lucie | Implementation of Commitments and Aging Management Programs | The inspectors identified a URI associated with the implementation status of various commitments and AMPs. Description: The inspectors identified that there were pending actions for various regulatory commitments/AMPs as a result of commitment changes implemented by the licensee after the renewed operating license was issued. The licensee informed the NRC of such changes, and submitted correspondence to the NRC for review and approval. At the time of this inspection, the NRC was still in the process of reviewing the licensees submittals. While the licensee met its commitment to submit the proposed changes to the NRC prior to the PEO, the inspectors were unable to determine whether the licensees implementation of the affected AMPs was consistent with the staffs final position, which will be provided through the issuance of SERs. The affected commitment items, and their respective pending actions, are summarized below. Commitment 1, Condensate Storage Tank Cross-Connect Buried Piping Inspection On May 12, 2015, the licensee informed the NRC of a commitment change based on the as-found configuration of the cross-tie line after excavation. On September 1, 2015, the NRC issued a Request for Additional information, for which the licensee provided responses in letter L2015-258, dated October 6, 2015. At the time of this inspection the NRC was reviewing the licensees response to the Request for Additional Information, and no SER had yet been issued. Commitments 4 and 5, Reactor Vessel Internals Inspection Program As described in the inspection scope section of this report, the licensee submitted several letters to the NRC after the renewed operating license was issued describing the proposed program to manage the aging effects of the reactor vessel internals. At the time of this inspection, the NRC was reviewing the licensees submittals and no final SER had yet been issued. Commitment 6, Small Bore Class 1 Piping Inspection Program On May 11, 2015, the licensee submitted a revision to the previously approved Small Bore Class 1 Piping Inspection Program for NRC review and approval. The revision was related to the use of destructive examinations in lieu of volumetric examinations. At the time of this inspection, the NRC was reviewing the licensees submittal and no final SER had yet been issued. Commitment 20, Environmentally-Assisted Fatigue of the Pressurizer Surge Line On October 29, 2015, the licensee submitted its proposed program for managing environmentally-assisted fatigue of the pressurizer surge line to the NRC. The inspectors noted that the proposal detailed the licensees intent to utilize the ASME BPVC, Section XI ISI Program (UFSAR Section 18.2.2) to manage the recurring inspections, and the associated evaluations for any flaws noted. At the time of this inspection, the NRC was reviewing the licensees submittal and no SER had yet been issued. In addition to the commitment changes under NRC review, the inspectors identified a followup item for Commitment 17, Reactor Vessel Integrity Program. The inspectors noted that the licensee credited fleet procedure ER-AA-110 to meet the regulatory commitment associated with the integration of all four reactor vessel integrity subprograms into a single program document. Fleet procedure ER-AA-110 requires a plant-specific procedure be developed for each site describing the important parameters needed to meet the regulatory requirements specific to that station. The inspectors noted that the plant-specific procedure for Unit 1, procedure ADM 17.38, was still under development with a target completion date of March 1, 2016. Therefore, the inspectors concluded that there still were pending actions associated with the development of the site-specific program, and additional inspection was required to verify that the Reactor Vessel Integrity Program was implemented as intended. The licensee initiated AR 02094578 to enter this item in the CAP. The inspectors determined that it was necessary to open a URI to further review the implementation of the commitments/AMPs, and verify that the commitments were met as approved by the NRC in the final SERs. This issue requires followup inspection, and will be tracked as URI 05000335/2015010-001, Implementation of Commitments and Aging Management Programs. |
| 05000338/FIN-2011011-01 | 2011Q4 | North Anna | Seismic Instrumentation Implementation | The team reviewed records and interviewed personnel to determine whether the seismic instruments at the North Anna Power Station were maintained and calibrated properly to provide accurate information for making decisions on safe shutdown during and following a seismic event and for subsequent engineering analysis. The team completed this task by reviewing seismic instrument manuals, and other related documents, and a sample of calibration documents. The team also interviewed licensee engineers and inspected instrument scratch plates that recorded the initial seismic activity. The team found that two potential generic issues exist related to the seismic instrumentation system and implementation. These issues and one related URI are described in this section. A second related URI is described in Section 7.5. The team conducted walk-downs of all seismic instruments located in Unit 1 Containment and Auxiliary Buildings. During the walk-downs, the team visually inspected all of the seismic instruments at various levels of elevation of the two buildings. The installation of seismic equipment appeared consistent with the equipment vendor manuals. The licensees records indicated that seismic equipment, including both Engdahl and Kinemetrics, was checked every 18 months during refueling outages. Through review of records and interviews with licensee personnel, the team noted the following issues with seismic instruments: 1. All the seismic instrumentation was located on plant structures, and no seismometers were installed on a free surface in the free field; therefore, the team questioned whether the instrumentation would provide a reliable indicator for determining whether an earthquake had exceeded Operating Basis Earthquake (OBE) or Safe Shutdown Earthquake (SSE) ground motion levels. 2. A seismic alarming system panel lost power during the event and it was not connected to an uninterruptible electric power supply. In addition, some other equipment issues were observed during the event follow-up. The team questioned whether the seismic equipment and associated alarming systems were adequate to perform their expected function considering the equipment issues observed during the event. Because these two issues may be applicable to other operating nuclear power plants, the team determined that they represented potential generic issues. Specific issues with the equipment included: A seismic alarming system panel lost power during the event and it was not connected to an uninterruptible electric power supply. The team questioned whether the seismic equipment and associated alarming systems were adequate to perform their expected function considering equipment issues observed during the event. Seismic recordings were inconsistent between the Kinemetrics and Engdahl scratch plates located on the base-mat of Unit 1. Some of the Engdahl scratch plates did not record any ground motion. Both orientations of Kinemetrics and Engdahl scratch plate equipment located at different elevation levels were misidentified; therefore, the data for East-West and North-South was initially swapped. A deficiency was previously identified by the licensee on the seismic alarming system, affecting one of the panels alarms, but remained pending repair (Work Order 59102235553 and Condition Report (CR) 403883). Instrument Panel OBE and SSE values were not consistent with FSAR 3.7.4 (OBE exceedance) and the licensees system training manual (Module NCRODP-72-NA: amber light indicates 67 percent of DBE for frequency of a particular reed in either the L, T or V direction; red light indicates 100% DBE for the frequency of a particular reed in either the L,T or V direction). The licensee entered this issue into their corrective action program as CR 442880. Based on the review of maintenance and calibration records, the team did not find documentation indicating performance of cross-checks and calibration of different types of seismic equipment against each other to ensure the signals recorded were consistent with regard to frequency and amplitudes. Seismic recordings were not clocked or referenced to the plants event recorders; therefore, the start time of seismic activity time history recordings required estimation. The team determined that the issues with seismic instrument implementation warranted additional NRC review and follow-up considering that information from this system served as an input into event response decision making. Additional review by the NRC will be needed to determine whether any of the issues represents a performance deficiency. An unresolved item will be opened pending completion of this review. The issue will be identified as URI 05000338, 339/2011011-01, Seismic Instrumentation Implementation. |
| 05000338/FIN-2011011-02 | 2011Q4 | North Anna | Failure of 2H Emergency Diesel Generator Jacket Water Cooling Gasket Resulting in Inoperability during Dual Unit LOOP | To adequately evaluate the performance of the EDGs in response to the seismically induced LOOP (including the 2H EDG coolant leak and any identified anomalies), the team performed the following activities: FnConducted walk-downs of the EDGs to evaluate the material condition FnConducted interviews with plant personnel (maintenance, engineering, and operations; root cause investigation team) to determine an accurate account of events related to the EDGs FnReviewed design and engineering documents to verify appropriateness of licensee actions in accordance with design and licensing basis FnObserved corrective maintenance and testing to assess the licensees actions to restore the EDGs In addition, the team reviewed corrective action CRs to evaluate the licensees response to identified deficiencies associated with the EDGs. The vendor manual was referenced to verify alignment with licensee maintenance procedures. Industry operating experience was referenced to identify any potential generic industry issues similar to what was observed at North Anna with respect to the EDGs performance. The team found some issues with EDG performance and identified two URIs that are described in this section. Following the seismic event on August 23, 2011, at 1:51 p.m., all four EDGs started and loaded their respective emergency buses due to a loss of offsite power on both units. About 45 minutes after the EDGs started, a coolant leak was observed on the 2H EDG. At 1:40 p.m., the 2H EDG was manually tripped and secured and the associated emergency bus de-energized. The 2H emergency bus was subsequently re-energized by the SBO diesel. Additionally, the 1J EDG was observed to have minor frequency oscillations. This issue is discussed in further detail in Section 6.0 of this report. Upon further investigation, it was determined that the 2H EDG coolant leak was caused by failure of a fiber gasket located between the exhaust belt and the jacket water cooling inlet jumper on the opposite control side (OCS) of the diesel engine. Initial discovery found the gasket soft and extruding from the flange edge. Due to the excessive coolant leak and in response to a High Jacket Coolant Temperature annunciator that came in during the event, the licensee inspected the cylinder liners, pistons, and rings for damage. No engine damage was found to have occurred. During restoration of the 2H EDG, a small exhaust leak was also identified during the post-maintenance test. The licensee subsequently replaced one exhaust gasket and the extension pipe. The small leak did not have an impact on the EDG to perform its safety function. In May 1999, EDG vendor Fairbanks-Morse issued a Marketing Information Letter, Vendor Technical Manual (VTM) Addenda 72, detailing a new, fiber gasket to replace the previous rubber gaskets for the cooling water bypass fittings. The licensee began installation of the new gaskets in 2001. One major difference was the new fiber gasket was 1/8 thick as opposed to 1/16 for the rubber gasket. The letter also provided recommendations for gasket installation. These recommendations included: FnAllowing a minimum dry time of 10 minutes following application of the gasket adhesive; FnEnsure the fitting surfaces for the exhaust belt and the water inlet flange have the appropriate finish; FnAssemble fitting to exhaust belt and torque nuts to 70 ft/lbs +/- 10 Maintenance procedure, 0-MCM-0701-27, Replacement of Emergency Diesel Generator Cylinder Liners, Revision 19, was used for replacement of the gaskets on 2H EDG in May 2010. The procedure did not include a dry time following application of the adhesive (RTV). Improper curing time for the adhesive could impact the proper alignment of the gasket; too short a time can allow the gasket to move out of place, too much time can harden the adhesive. Following overhaul of the 2H EDG in May 2010, which included replacement of the gaskets, the licensee performed a hydrostatic test to ensure proper restoration. During this test, water pressure was applied (at approx. 50 psi) to the engine block above the normal operating pressure (approx. 30 psi) to ensure no external leakage was occurring; however, coolant leakage was observed on all of the gaskets. It was determined at this time, as documented in Condition Report (CR) 383161 and Corrective Action (CA) 172549, that the RTV adhesive should be allowed to set for 30 V 60 minutes on the gaskets prior to installation for improved sealing. The 2H EDG gaskets were removed and re-installed and passed a subsequent hydrostatic post maintenance test. A subsequent revision to the procedure was approved and implemented in September 2010 to include the adhesive cure time. When the 2H EDG was taken out of service for corrective maintenance following discovery of the coolant leak on August 23, 2011, the licensee removed the OCS heat shields and stress bars, drained the remainder of the coolant, and removed the exhaust components as necessary to gain access to the jacket water inlet elbow. Initial inspection of the water by-pass inlet revealed the gasket protruding past the inlet fitting indicating that the gasket might not have been properly aligned when originally installed in May 2010, despite having been installed twice and satisfactory completion of the hydrostatic testing. Additional investigation by the licensee revealed that in addition to potential misalignment of the water bypass inlet gasket, the jacket water bypass inlet header adjustable screw and jam nut were potentially inappropriately installed. The adjustable screw and jam nut act as a cantilever on the engine block and bypass inlet fittings. Excessive tightening of the adjusting screw can place more compression on the top of the gasket and cause the gasket to extrude and leak on the bottom of the inlet pipe joint. There was no guidance in procedure 0-MCM-0701-27 for tightening the adjustment screw and jam nut; the procedure has since been revised to include detailed instructions. Following installation of the gaskets in May 2010, 0-MCM-0701-27 required the water bypass fitting bolts be torqued to 50 -55 ft-lb; however, this was in conflict with the vendor recommended 70 Ft.-lbs. as outlined in VTM Addenda 72. According to the vendor, the 50 ft-lb torque specification was applicable to the previous rubber gasket and was specified to reduce the thickness of the gasket from 1/16 (.062 ) to .040-.050 . The new gasket was thicker at 1/8 and the 70 Ft.-lbs. was the specified torque. There are two bolts per fitting and are torqued to ensure appropriate compression was applied between the bypass fitting, the gasket, and the exhaust belt. This discrepancy in torque values was identified by the licensee and documented in CR 347658 in September 2009. After discussion with the EDG vendor, the licensee determined that the lower torque value was acceptable given no leakage up to that time had been observed during hydrostatic testing or operation of the diesel; however, the vendor maintained a recommendation of 70 Ft.-lbs. if leakage was observed. In response to the 2H EDG coolant leak on August 23, 2011, the licensee conducted follow-up discussions with the vendor to determine if 50 Ft.-lbs. was acceptable. The vendor restated the recommendation of 70 Ft.-lbs. and performance of a hydrostatic test at 50 psi. The team questioned whether the lower 50 Ft.-lbs. torque value being applied to the new thicker gasket provided the appropriate compression for sealing. A lack of compression can allow the gasket to absorb water and soften, which can lead to gasket extrusion from the flange edge. The licensee was going to perform a technical evaluation to demonstrate adequate compression was available to the gasket. The procedure has since been revised to include the recommended 70 Ft.-lbs. torque specification. Additionally, in September 2009, the licensee documented in CR 347783 that the EDG water bypass fittings had the incorrect surface finish and were not in accordance with the VTM Addenda 72 recommendation of ensuring the exhaust belt had a 125 micro-inch finish and the inlet flange had a 250 micro-inch finish. Though the CR was written to resolve the discrepancy before the next EDG outage (1J), the procedure was not revised until August 2011, following the 2H EDG coolant leak. The team concluded the licensee failed to properly incorporate or evaluate vendor recommendations regarding installation of the cooling water gaskets. At the time of the teams review, the licensee planned to continue evaluating whether the seismic event accelerated the failure of the gasket. Though the licensee eventually inspected all four EDGs following the discovery of the leak on 2H EDG, the team questioned why the licensee initially determined the leak to be an isolated event without having known the cause. The TS requires a common cause evaluation if one EDG is determined to be inoperable. If the cause cannot be confirmed not to exist on the remaining EDGs, the EDGs should be tested to provide reasonable assurance and the corrective action program should continue to evaluate the common cause possibility for the other EDGs. In the case of the 2H EDG leak, the apparent cause was known to be the gasket failure as documented in CR 439091 on August 24, 2011. At the time, the other EDGs were running at full load to support plant shutdown; however, it was not known if the gaskets were installed properly on these EDGs. The CR recognized that previous related issues existed (i.e., multiple coolant leaks across multiple EDGs); however, the licensee still determined the leak was an isolated event. The team observed that this conclusion was based on lack of visible evidence or result (i.e., coolant leakage), but not on a determination of the actual cause. The licensee did submit work orders to inspect the gaskets on the remaining EDGs, but the initial assessment of this being an isolated event did not appear in accordance with proper corrective action program common cause evaluations. The failure of the jacket water cooling gasket caused a leak on the 2H EDG and consequently, inoperability of the 2H EDG during a dual unit LOOP following a seismic event on August 23, 2011. Additional review by the NRC will be needed to determine whether the lack of adequate procedural guidance for EDG cooling water gasket installation represents a performance deficiency. An unresolved item will be opened pending completion of this review. The issue will be identified as unresolved item (URI) 05000338, 339/2011011-02: Failure of 2H Emergency Diesel Generator Jacket Water Cooling Gasket Resulting in Inoperability During Dual Unit LOOP |
| 05000338/FIN-2011011-03 | 2011Q4 | North Anna | Missing Orifice Plate on 1J EDG | Following the seismic event on August 23, 2011, and subsequent failure of the 2H EDG, all four EDGS were subject to thorough inspection and corrective maintenance. On September 3, 2011 during a post-maintenance EDG run, a leak was observed on 1J EDG engine-driven jacket coolant water pump. When the pump was removed for rebuild, it was discovered the pump did not have an orifice plate installed on the discharge of the pump. The orifice plate was subsequently found still attached to the discharge flange of the previously removed pump. An extent of condition was performed and it was observed that the 2J EDG was also missing its orifice plate on the jacket cooling water pump. A missing orifice plate on the jacket cooling water pump discharge flange can cause increased flow and pressure in the jacket cooling system, which in turn can cause 1) operating pressures to reach limitations; (2) degraded cooling capabilities; and (3) potential pipe strain that could lead to leakage or pump and piping fatigue. An installed orifice plate creates a pressure drop and corresponding decrease in flow throughout the system. As flow decreases, the temperature delta must increase to maintain the same amount of heat removal. It was determined the 2J EDG was missing its orifice plate since the last time it was worked on in 2004. A review of past performance data for the 2J EDG (back to 2005) was conducted and it was observed that due to the increased parameters, the temperature delta is lower at full load than normally (4-5 deg. vs. 10-14 delta T normally). Additionally, the 2J engine has required more work input from the engine which lowered the available horsepower to turn the electrical generator; however, past surveillance testing has demonstrated the ability of the 2J EDG to reach rated load. Because the degraded 2J EDG engine driven coolant pump caused some parameter changes on the 2J EDG and could have caused some degradation to the diesel since 2004, additional review by the NRC will be needed to determine whether the missing orifice plate represents a performance deficiency. An unresolved item will be opened pending completion of this review. The issue will be identified as URI 05000338, 339/2011011-03: Missing Orifice Plate on 1J and 2J EDG |
| 05000338/FIN-2011011-04 | 2011Q4 | North Anna | 1J EDG Frequency Oscillation | Following the seismic event on August 23, 2011, while the 1J EDG was supplying power to the 1J emergency bus, control room operators identified frequency oscillations on the 1J EDG bus as well as 1-III and 1-IV inverter momentary trouble alarms when the pressurizer heaters were cycled. During personnel interviews, bus frequency was reported as oscillating between 59 and 61Hz. The inspectors noted a Technical Specification Limit of 59.5 and 60.5Hz. Engine load cycled between 1600 and 2000KW while the 1J EDG was supplying power to the bus, varying as pressurizer heater loads cycled. The PCS did not have a data point for emergency bus frequency so actual emergency bus frequency was not recorded and could not be conclusively obtained. The licensee entered this issue into the corrective action program as CR 440231. There was a PCS data point that indicated engine speed (rpm), which could have been used to calculate frequency with quality data available; however this PCS point for the 1J EDG was very noisy during the event and could not provide any useful data to determine the magnitude of frequency oscillations. All four EDG speed points on the PCS were trended using engine run data since the seismic event occurred. Each engine was operating parallel to the grid (stable at 900rpm) to observe stability of the data point. There was noise in each data point: 1H, 2H and 2J showed oscillations of 20-30rpm when paralleled and had a nominal speed indication between 895 and 920rpm. The 1J data point showed oscillations of 100rpm in isochronous mode and when paralleled to the grid and could therefore not be used to conclusively determine the 1J emergency bus frequency. This data point was used for indication only and was not related to actual engine stability. On September 5, the licensee conducted a PMT of the 1J EDG in manual mode. During that run, a troubleshooting sheet was prepared in response to CR 440231 and qualified test equipment was used to measure engine frequency/voltage, electronic governor null voltage, and the PCS rpm data point. Frequency responded as expected when control was switched from the mechanical governor to the electric governor actuator and was measured stable at 60.2Hz. The licensee was not able to test the 1J EDG in isochronous mode, which was the configuration during the event due to current plant conditions; however, the licensee was scheduled to recreate the scenario during the upcoming refueling outage. The engine RPM indication is a separate issue that may also be addressed during this evolution. An unresolved item will be opened pending completion and results of licensee testing. This issue will be identified as URI 05000338, 339/2011011-04, 1J EDG Frequency Oscillations. |
| 05000338/FIN-2011011-05 | 2011Q4 | North Anna | Unit 1 Turbine Driven Auxiliary Feedwater Pump Trouble Alarm | The team conducted an independent review of control room activities with respect to the EOPs to determine if licensee staff responded properly during the events. The team also reviewed the licensees implementation of abnormal, alarm and normal operating procedures used during the event. The review included the effectiveness of the procedures in addressing the event. With respect to operator awareness and decision making, the team was specifically focused on the effectiveness of control board monitoring, communications, technical decision making, and work practices of the operating crew. With respect to command and control, the team specifically focused on actions taken by the control room leadership in managing the operating crews response to the event. The team performed the following activities in order to understand and/or confirm the control room operating crews actions to diagnose the event and implement corrective actions: nConducted interviews with control room operations personnel on shift during the event. nReviewed procedures, narrative logs, event recorder data, system drawings, and plant computer data. nReviewed the crews implementation of emergency, abnormal, and alarm procedures as well as Technical Specifications Reviewed Operations administrative procedures concerning shift manning and procedure use and coordination b. Observations and Findings The team concluded that EOPs were performed consistent with training. The team determined that operators exhibited fundamental operator competencies when responding to the event while using EOPs. Specifically, the team determined that the operating crew identified important off-normal parameters and alarms in a timely manner for the external seismic event and the subsequent LOOP. Additionally, the team determined that crew supervision exercised effective oversight of plant status, crew performance, and site resources. Monitoring of Plant Parameters and Alarms Through a review of plant data, the team determined that the crews response to the seismic event was effective in stabilizing the plant. Through interviews and review of plant data, the team determined that the crew recognized the seismic event and resulting LOOP. Based on interviews, the on-shift crews for each unit assessed the plant conditions as being consistent with what was experienced during simulator training for a LOOP. Based on the sequence of events, a review of plant data, and operator interviews, the team concluded that the LOOP prevented the normal access to plant online Alarm Response Procedures (ARPs) because the document server was powered from offsite power. The procedures were available in the control room as paper copies. EOPs and Abnormal Procedures (APs) were readily available during the event with no delay. Based on operator interviews, the team concluded that the operators completed a satisfactory review and evaluation of alarm conditions after the event. Command and Control Based on NRC inspector observations during the event and interviews and a review of plant data, the team determined that the Shift Manager (SM) and Shift Technical Advisor (STA) maintained oversight of the plant, which included awareness of major plant parameters such as RCS temperature and pressurizer level, during the event. Based on observation and interviews, the team determined that the SM effectively managed the frequency and duration of crew updates and crew briefs during the event. Crew updates were reasonable based on the implementation of EOPs. The team concluded that the SM and Control Room Supervisor (CRS) ensured monitoring and diagnosis of key major plant parameters, such as RCS temperature, pressurizer level, and VCT level, by control room crew members. Based on a review of plant data, the team concluded that the management expectation for establishing positive control of equipment configuration was implemented by the operating crew. Through interviews and a review of plant data and alarm response 39 Enclosure procedures, the team determined that the SM and CRS ensured that sufficient information necessary to assess abnormal electric plant status was collected and evaluated prior to performing steps within a procedure that assumed a normal electric plant configuration. During interviews, operators stated that the loss of the document computer for ARPs was not a common scenario in training packages. The licensee was considering addressing this in their training program. The team determined that the loss of the document computer only affected ARPs and did not significantly affect operator performance during the event. Resource Utilization Through interviews, the team determined that the Balance of Plant (BOP) operators and off-shift operators were available to assist the control room operators in recognizing and diagnosing off-normal issues. The seismic event occurred on dayshift which provided additional resources to the control room crew. The utilization of operators during the dual unit trip was adequate. Other Operating Procedures The team observed that procedure 1-AR-F-D8, Turbine Driven AFW Pump Trouble or Lube Oil Trouble did not state that the low lube oil level switch was powered from non-vital power. Upon a loss of power, the lube oil level switch will generate an alarm signal and the alarm, which has a different power source, will activate. The alarm procedure did not recognize this issue. During interviews, operators revealed they were unsure as to why the alarm was lit and the issue required additional troubleshooting. This resulted in a short delay in the alignment of the Unit 1 terry turbine AFW pump to the steam generator. An unresolved item will be opened pending completion of this review. The issue will be identified as URI 05000338, 339/2011011-05: Unit 1 Turbine Driven Auxiliary Feedwater Pump Trouble Alarm. |
| 05000338/FIN-2011011-06 | 2011Q4 | North Anna | Seismic Alarm Panel | The team reviewed the licensees implementation of the emergency preparedness (EP) procedures used during the event. The review focused on the circumstances surrounding the events to determine if the licensees EP classification and notifications were appropriate and timely. The team interviewed members of the licensees organization and other individuals involved with EP aspects of the event. The team reviewed the event timeline, logs, statements by individuals who responded to the event, the North Anna emergency action level (EAL) matrix, event notification worksheets, and other documents related to EP classifications. b. Observations and Findings. The team concluded that emergency planning declarations were appropriate. The team identified one URI described in this section. In order to determine the appropriateness of the EP classifications, the team performed a detailed assessment of the event timeline with particular attention to those activities that are entry points for the EAL matrix. On August 23, 2011, at 1:51 p.m., the site experienced a magnitude 5.8 earthquake with an epicenter twelve miles southwest of the plant. Both reactors tripped. A LOOP occurred at 1:51:12 p.m. All four EDGs auto started to their respective emergency bus (1H, 1J, 2H, and 2J) at 1:51:20 p.m. An Alert was declared at 2:03 p.m. for HA6.1, SM judgment, due to an inability to enter the seismic EAL for seismic event because the seismic monitoring panel earthquake trouble alarm to notify operators of a seismic event did not illuminate. HA1.1, earthquake response, required that the strong motion accelerograph peak shock annunciator illuminates, which would indicate a seismic event greater than OBE (0.06g horizontal or 0.04g vertical) and an earthquake confirmed by any of the following: FnEarthquake felt in plant FnNational Earthquake Information Center (NEIC) FnControl Room indication of degraded performance of any safety-related structure, system, or component The strong motion accelerograph peak shock annunciator did not illuminate. The seismic monitoring panel has two recording systems, one provided by Kinemetrics Inc. and the other provided by Engdahl. Both systems provide input to the main control room via a common instrumentation panel on the Unit 2 side of the control room. All sensors for the Kinemetrics system are located inside Unit 1 containment. The Kinemetrics system has a seismic trigger, which activates at 0.01g in a any direction. In addition, there is a seismic switch which activates at 0.04g vertical and 0.06 horizontal. Neither the seismic switch nor the seismic trigger activated the earthquake trouble alarm. Locally at the seismic panel, the seismic trigger was activated and a tape recording of the event was recorded. Therefore, operators determined that the seismic monitoring panel was inoperable for making a decision about the strength of the earthquake. The team determined that the lack of control panel alarm from the seismic monitoring panel did not delay an Alert declaration, because the SM used HA6.1, SM judgment. Because of the issues identified with the seismic monitoring panel and because it is used as an input for EAL decisions, additional review by the NRC will be needed to determine whether this issue represents a performance deficiency. An unresolved item will be opened pending completion of this review. The issue will be identified as URI 05000338, 339/2011011-06: Seismic Alarm Panel. Personnel in the plant monitoring the 2H EDG reported the coolant leak to the control room via face-to-face communication. Operators tripped the 2H EDG at 2:40 p.m. An Alert was declared at 2:55 p.m. for SA1.1, AC power, for Unit 2, because the AC capability was reduced to a single source with 2J EDG. The team determined that notifications to the State and Counties and to the NRC Operations Center were timely and accurate. The Alert event was downgraded to a Notice of Unusual Event (NOUE) at 11:16 a.m. on August 24, for HU1.1, seismic activity, due to the potential for aftershocks. The NOUE was exited on August 24, 2011, at 1:15 p.m. The decision to terminate the event was based on the following: (1) no public issues existed that would necessitate the continued activation of the State and County Emergency Operations Facilities; (2) the licensees Outage Control Center had established a technical focus and was aligned for the recovery activities; and (3) no additional aftershocks were received at the plant. The team determined that downgrade of the Alert event at 11:16 a.m. was appropriate. |
| 05000338/FIN-2011011-07 | 2011Q4 | North Anna | Safety Related Instrumentation Anomalies | During the post event review, the licensee identified some unexpected anomalies that occurred during the event, related to safety related instrumentation. The team independently reviewed event recorders, plant records, and interviewed personnel to determine whether the licensee had identified and appropriately addressed any observed equipment performance issues. The team found that some plant instrumentation anomalies warranted follow-up. The team identified one URI described in this section. The licensee had identified and recorded a number of instrument anomalies, many of which were attributed to the earthquake. Some examples of instruments affected included: Minor perturbations in Units 1 and 2 Safety Injection Accumulator and Refueling Water Storage Tank (RWST) levels Nuclear Instrumentation Loop 1C High Delta Temperature Hi-Hi Steam Generator Level RWST Chemical Addition Tank Temperature The team questioned whether these anomalies were indications of actual parameter changes in level, pressure, etc. due to the seismic event or false indications that were seismically induced. If the indications were seismically induced, the team inquired whether the instrument exceeded their seismic qualification or whether the seismic qualification of the instrument was appropriate. The licensee planned to determine the most likely cause of the anomalies through their root cause assessment of the August 23, 2011 seismic event. Because some of the anomalies identified with the safety related instrumentation could have been seismically induced and thus potentially calls into question the seismic qualification of the instruments, additional review by the NRC will be needed to determine whether this issue represented a performance deficiency. An unresolved item will be opened pending completion of this review. The issue will be identified as URI 05000338, 339/2011011-07: Safety Related Instrumentation Anomalies. |
| 05000348/FIN-2002006-01 | 2002Q3 | Farley | Failure to Obtain NRC Approval Prior to Implementing Changes to the Approved Fire Protection Program | A Severity Level IV NCV of Farley Unit 1 Operating License Condition 2.C.(4) and Farley Unit 2 Operating License Condition 2.C.(6) was identified for the licensee making a change to the approved fire protection program (FPP) without prior Commission approval. On January 20, 1992, and February 20, 1998, the licensee inappropriately used the 10 CFR 50.59 change process to revise the FPP to accept five fire areas (Fire Areas 51, 1-004, 1-042, 2-004, and 2-043) that did not satisfy the fire detection and suppression requirements of 10 CFR 50, Appendix R, Section III.G.3. These five fire areas contained unprotected, redundant electrical cables for both main control room (MCR) air conditioning (A/C) units. On Unit 1, the change decreased the effectiveness of the program in the event of a fire, while on Unit 2 the change adversely affected the ability to achieve and maintain safe shutdown (SSD) in the event of a fire The team concluded that the finding had a credible impact on safety because the licensees failure to properly evaluate changes to the FPP could adversely affect or degrade the reliability of SSD capability from the MCR. However, the team determined that this finding was of very low significance because the overall SSD capabilities in the affected fire areas and related FFP features were still adequate to ensure SSD capability. Therefore, this finding is characterized as Green. |
| 05000348/FIN-2008006-01 | 2008Q2 | Farley | Fire Procedure Credits Unreliable Indication | The team identified a non-cited violation of Technical Specification 5.4.1, Procedures, in that Units 1 and 2 post-fire safe shutdown abnormal operating procedures AOP 28.1, Fire or Inadvertent Fire Protection System Actuation in the Cable Spreading Room, and AOP 28.2, Fire in the Control Room, credited diagnostic instrumentation that would have been potentially unreliable due to fire damage from a postulated fire in the control room or cable spreading room. The finding was entered into the licensees corrective action program as Condition Report 2005103665. This issue is a performance deficiency because the safe shutdown procedure relies on an indication which was not protected from fire damage. The finding is more than minor because it is associated with the procedure quality attribute of the Mitigating Systems cornerstone and it affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The inspectors assessed the finding using Inspection Manual Chapter 0609, Appendix F, Fire Protection Significance Determination Process. The finding was assigned a low degradation rating because it was determined to be a minor procedural deficiency that is compensated by operator experience or familiarity. Because the finding was assigned a low degradation rating, the team determined that this finding was of very low safety significance (Green) |
| 05000348/FIN-2008006-02 | 2008Q2 | Farley | Areas Where Omas Are Performed DID Not Have Elus Installed | The team identified a non-cited violation of Farley Unit 2 Operating License Condition 2.C.(6), for the licensees failure to fully implement the approved fire protection program, in that emergency lighting units (ELUs) were not installed in all areas where local operator manual actions were required to support post-fire safe shutdown. Specifically, the team determined that there were no ELUs installed to illuminate the front panels of the Reactor Coolant Pump (RCP) switchgear, located in the Train A switchgear room, where post-fire safe shutdown local operator manual actions were required to trip the RCP 4160 Volt alternating current breakers. The finding was entered into the licensees corrective action program under Condition Reports 2008103335, 336, and 337. The finding is greater than minor because it is associated with the reactor safety Mitigating Systems cornerstone attribute of protection against external factors (i.e., fire) and it affects the cornerstone attribute of ensuring reliability and capability of systems that respond to initiating events. Specifically, the finding adversely affected the ability to perform local operator manual actions required to achieve and maintain safe shutdown conditions following a fire in the cable spreading room. The inspectors assessed the finding using IMC 0609, Appendix F, Fire Protection Significance Determination Process. The team determined that this finding was of very low safety significance (Green) because the operators had a high likelihood of completing the task using flashlights, which operators are directed to carry with them by procedure while performing local actions |
| 05000348/FIN-2008006-03 | 2008Q2 | Farley | ELU Test Failures Were Not Documented in CRS as Required by Procedure | The team identified a non-cited violation of Farley Unit 2 Operating License Condition 2.C.(6), for the licensees failure to fully implement test control requirements incorporated in approved plant procedures associated with the periodic testing of emergency lighting units. As a consequence, condition reports (CRs) were not initiated as required, when battery conductance measurements did not meet acceptance criteria. The finding was entered into the licensees corrective action program as Condition Report 2008103290. This issue is a performance deficiency because the licensee did not properly document ELU test failures on CRs for trending and evaluation in accordance with the surveillance test procedures. The finding involved systems or components (i.e., emergency lights) required for post-fire safe shutdown of the reactor. The finding is greater than minor because it is associated with the reactor safety Mitigating Systems cornerstone attribute of protection against external factors (i.e., fire) and it affects the cornerstone attribute of ensuring reliability and capability of systems that respond to initiating events. The team determined that this finding was of very low safety significance (Green) because the operators had a high likelihood of completing the task using flashlights, which operators are directed to carry with them by procedure while performing local actions |
| 05000361/FIN-2010006-01 | 2010Q2 | San Onofre | Inadequate Operability Determination for Turbine-Driven Auxiliary Feedwater Pump Steam Admission Valves | The inspectors identified a noncited violation of 10 CFR Part 50, Appendix B, Criterion V, \\\"Instructions, Procedures, and Drawings,\\\" involving the failure to follow procedural requirements for performing operability determinations. Specifically, the licensee\\\'s operability evaluation for a degraded turbine-driven auxiliary feedwater pump steam admission valve failed to address all the specified safety functions of the affected component as described in the Final Safety Analysis Report and design basis documents. For exampie, the operabiiity determination incorrectly stated that manual closure of the valves was not a credited safety function and incorrectly assumed nonsafety-related instrument air would always be available to close the valves. This finding was entered into the licensee\\\'s corrective action program as Nuclear Notifications 200869281 and 200887620. The licensee\\\'s corrective actions included re-performing the evaluation and emphasizing with licensee staff the importance of ensuring ali design basis information is considered in operability evaluations. The finding was more than minor because it impacted the Mitigating Systems Cornerstones and its objective to ensure the availability and reliability of equipment that responds to initiating events. Using Inspection Manual Chapter 0609 the issue screened to a Phase 3 analysis because it represented a loss of safety function for greater than the allowed technical specification allowed outage time and it screened to greater than Green using the Phase 2 pre-solved worksheet. The senior reactor analyst determined that this finding was of very low safety significance (Green) based on a bounding calculation which assumed inoperability of the component for a year. The senior reactor analyst determined that the combined significance of these scenarios was a delta-core damage frequency of 1.3E-7/yr and a delta-large early release frequency of 4.2E-8/yr. Therefore the violation was determined to be of very low safety significance (Green). The analyst determined that the cause of the finding has a crosscutting aspect in the area of human performance associated with decision making. Specifically, the licensee utilized unsupportable assumptions in its evaluation that were not consistent with the Final Safety Analysis Report or the valve vendor manual. |
| 05000361/FIN-2010006-02 | 2010Q2 | San Onofre | Failure to Translate Design Basis Information for Turbine-Driven Auxiliary Feedwater Pump Steam Admission Valves | The inspectors identified a noncited violation of 10 CFR Part 50, Appendix B, Criterion Ill, \"Design Control,\" involving the failure to translate nonconservative errors in calculations and procedures identified during review of external operating experiences. The first example involved the sizing calculation for the condensate storage tank failing to account for effects of auxiliary feedwater pump heat during recirculation. The second example involved the failure to update procedural guidance concerning the adverse effects of placing the low pressure safety injection system into operation following use of the residual heat removal system in the shutdown cooling mode of operation above 200F. This issue was entered into the licensee\'s corrective action program as Nuclear Notification 200886265. The licensee initiated actions to correct its procedure and calculation for each instance. The finding is of more than minor significance because it adversely affects the design control attribute of the mitigating systems cornerstone objective. Using Inspection Manual Chapter 0609.04, Phase 1, \"Initial Screening and Characterization of Findings,\" the finding was determined to have a very low safety significance (Green) because the finding did not result in a loss of system safety function, an actual loss of safety function of a single train for greater than its technical specification allowed outage time, or screen as potentially risk significant due to a seismic, flooding, or severe weather initiating event. The finding has a crosscutting aspect in the area of problem identification and resolution associated with the operating experience component because the licensee failed to implement and institutionalize operating experience information, including vendor recommendations, through changes to plant processes, procedures, equipment, and training programs. |
| 05000361/FIN-2010006-03 | 2010Q2 | San Onofre | Lack of Preventive Maintenance Results in Valve Failure and Inoperable Condensate Storage Tank | The inspectors identified a noncited violation of Technical Specification 3.7.6, which requires, in part, that Condensate Storage Tank T-120 be operable. Specifically, the tank isolation valve 2HV5715 had been inoperable for a period greater than the allowed outage time of seven days while Unit 2 was in Modes 1, 2, and 3. The valve isolates nonseismic piping from the tank and is required to be manually closed within 90 minutes following a seismic event. The licensee had not performed preventive maintenance on the valve resulting in the valve failing to close during an in-service test on January 26, 2010. This finding was entered into the licensee\'s corrective action program as Nuclear Notification 200765235. The licensee\'s corrective actions included repairing the isolation valve. This finding is more than minor because it impacted the Mitigating Systems Cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Using Inspection Manual Chapter 0609, Phase 1, \"Initial Screening and Characterization of Findings,\" a Phase 2 analysis was performed because the condensate storage, Tank T-120, was inoperable greater than that allowed in technical specifications. Phase 2 analysis resulted in a potential greater than Green issue therefore, a Phase 3 was performed. The analyst performed a Phase 3 using San Onofre seismic information and fragility data associated with the piping that could not be isolated because of the failed condition of valve 2HV5715. The frequency of a seismic event that would cause a pipe break and drain tank T-120 was estimated to be 2.7E-5/yr. Given a seismic event that causes a loss of offsite power (nearly 100 percent of seismic events that rupture the piping would also cause a loss of offsite power), operators are compelled by procedure to cool down and initiate shutdown cooling. The amount of water that is protected with valve 2HV5715 failed to open, which includes inventory from tank T-121 and water below the break line in tank T-120, given that operators close the working manual isolation valve within 30 minutes, is more than what is needed to get to shutdown cooling in natural circulation with only 1 of 2 steam generator atmospheric dump valves in operation, even if there is a 4-hour hold time at hot standby. The analyst estimated that the failure probability of operators to cool down and initiate shutdown cooling is 1.0E-2. Therefore, assuming a zero base case, the estimated delta- core damage frequency of the finding is 2.7E-5/yr. (1.0E-2) =2.7E-7/yr. The inspectors also determined that the cause of the finding has a crosscutting aspect in the area of human performance associated with resources in that the licensee did not ensure that equipment was available and adequate to assure nuclear safety by minimization of long-standing equipment issues in that the valve was not being maintained through a preventive maintenance program. |
| 05000361/FIN-2010006-04 | 2010Q2 | San Onofre | Failure to Report Conditions That Could of Prevented Fulfillment of Safety Function | The inspectors identified a Severity Level IV noncited violation of 10 CFR 50.73, \"Licensee Event Report System,\" in which the licensee failed to submit a licensee event report within 60 days following discovery of an event meeting the reportability criteria. On January 26, 2010, the valve which isolates nonseismic piping from condensate storage tank T-120 failed its in-service test when the hand wheel stem snapped after a leveraging device was used in an attempt to close the valve. This isolation valve, 2HV5715, must be closed within 90 minutes of an operating basis earthquake in order to prevent the loss of condensate storage tank T-120 water inventory from a line break in the nonseismic portion of the condensate system. The failure of this valve resulted in a condition prohibited by Technical Specification 3.7.6 and therefore was reportable. This finding was entered into the licensee\'s corrective action program as Nuclear Notification 200888616, and the licensee was taking actions to send a licensee event report to the NRC for this event. The inspectors determined that traditional enforcement was applicable to this issue because the NRC\'s regulatory ability was affected. Specifically, the NRC relies on the licensee to identify and report conditions or events meeting the criteria specified in regulations in order to perform its regulatory function. The inspectors determined that this finding was not suitable for evaluation using the significance determination process, and as such, was evaluated in accordance with the NRC Enforcement Policy. The finding was reviewed by NRC management, and because the violation was determined to be of very low safety significance, was not repetitive or willful, and was entered into the corrective action program, this violation is being treated as a Severity Level IV noncited violation consistent with the NRC Enforcement Policy. This finding was determined to have a crosscutting aspect in the area of problem identification and resolution associated with the corrective action program in that the licensee failed to appropriately evaluate corrective maintenance as a basis for past operability. |
| 05000361/FIN-2010006-05 | 2010Q2 | San Onofre | Control Room Operators\' Failure to Adhere to Conduct of Operations Procedural Requirements | The inspectors identified a noncited violation of Technical Specification 5.5.1.1.a involving the failure of control room operators to follow San Onofre Procedure S0123-0-A1, \"Conduct of Operations.\" These included failures to: implement alarm response procedure place-keeping, announce alarms to the control room supervisor, stop conversations when an alarm annunciated and cleared, perform three-way communication during pre-job briefing, review the summarize, anticipate, foresee, evaluate and review questions during a pre-job brief, review the prerequisites of a procedure prior to use, and remain cognitive of the re-activity change evolution by a control room supervisor. This issue was entered into the licensee\'s corrective action program as Nuclear Notification 200871332, and operations management immediately began actions to institute a recovery plan to improve operator performance. The finding was more than minor because it was associated with the Initiating Events Cornerstone attribute of human performance, and it affected the associated cornerstone objective to limit the likelihood of those events that upset plant stability and that challenge critical safety functions during shutdown, as well as during power operations. Using the Inspection Manual Chapter 0609, \"Significance Determination Process,\" Phase 1 Worksheet, the inspectors concluded that the transient initiator did not contribute to both the likelihood of a reactor trip and to the likelihood that mitigation equipment or functions would not be available. As a result, the issue was of very low safety significance (Green). The finding has a crosscutting aspect in the area of human performance associated with the work practices because the licensee did not ensure supervisory and management oversight of work activities. |
| 05000361/FIN-2010006-06 | 2010Q2 | San Onofre | Failure to Provide Adequate Procedure for Boron Dilution Activities | The inspectors reviewed a self-revealing noncited violation of Technical Specification 5.5.1.1.a involving the failure to maintain adequate instructions in San Onofre Procedure S023-3-2.4, \"RCS Purification and De-borating Ion Exchanger Operation,\" Revision 21 to control borating of ion exchangers. The failure to maintain an adequate procedure resulted in an unplanned power reduction by control room operators. This issue was entered into the licensee\'s corrective action program as Nuclear Notification 200721702. Immediate corrective actions included revising the procedure and operator crew training. The finding was more than minor because it was associated with the Initiating Events Cornerstone attribute of human performance, and it affected the associated cornerstone objective to limit the likelihood of those events that upset plant stability and that challenge critical safety functions during shutdown, as well as during power operations. Using the Inspection Manual Chapter 0609, \"Significance Determination Process,\" Phase 1 Worksheet, the inspectors concluded that the transient initiator did not contribute to both the likelihood of a reactor trip and to the likelihood that mitigation equipment or functions would not be available. As a result, the issue was of very low safety significance (Green). The finding has a crosscutting aspect in the area of human performance associated with the work practices because licensee supervisory personnel did not ensure activities associated with re-activity control were performed in a controlled manner such that nuclear safety was assured. |
| 05000361/FIN-2010006-07 | 2010Q2 | San Onofre | Failure to Establish Component Cooling Water Radiation Monitoring Procedures | The inspectors identified a noncited violation of Technical Specification 5.5.1.1.a, \"Scope,\" involving the failure to establish procedures for component cooling water system alignments such that leakage of radionuclides to the environment would be monitored during all operational alignments of component cooling water. Specifically, radiation monitors could be aligned to only one train of component cooling water at a time and the licensee\'s procedures had no provision for monitoring the second train when both trains were in-service. This finding was entered into the licensee\'s corrective action program as Nuclear It Notification 200871387, and actions were implemented to require periodic grab sampling of the train which was not being monitored. The inspectors determined that this finding was more than minor because this issue impacted the Public Radiation Protection Cornerstone and its objective to ensure adequate protection of public health and safety from exposure to radioactive materials released into the public domain as a result of routine civilian nuclear reactor operation. Specifically, the radiation monitors for component cooling water were not sufficient to ensure adequate release measurements. The inspectors evaluated the significance of this finding using Phase 1 of Inspection Manual Chapter 0609.04 and determined that the finding screened to Inspection Manual Chapter 0609, Appendix D, \"Public Radiation Safety Significance Determination Process.\" The inspectors evaluated the significance of this finding using Inspection Manual Chapter 0609, Appendix D, and determined that the finding was of very low safety significance (Green) because dose did not exceed Appendix I criteria. This finding was determined to have a crosscutting aspect in the area of problem identification and resolution associated with the corrective action program in that the plant operators did not have a low threshold for identifying deficiencies in procedures. |
| 05000361/FIN-2010006-08 | 2010Q2 | San Onofre | Failure to Maintain Written Procedures Covered In Regulatory Guide 1.33 | The inspectors identified a cited violation of Technical Specification 5.5.1.1.a, involving the failure to maintain adequate written procedures. Specifically, as of April 23, 2010, the licensee\\\'s controls over its backlog of procedure change requests associated with plant modifications were inadequate to prevent licensee personnel from using outdated procedures with known technical errors in the plant. The performance deficiency of failing to control the backlog of procedure changes, such that procedures with known technical errors were in use in the plant were previously identified by the NRC on two occasions and were documented as noncited violations 05000361; 05000362/2009003-09 and 2009009-02. Because the licensee failed to restore compliance within a reasonable time after the previous noncited violations were identified, this violation is being cited in a Notice of Violation in accordance with Section Vl.a.1 of the NRC\\\'s Enforcement Policy. This finding was entered into the licensee\\\'s corrective action program as Nuclear Notification 200888919. The licensee\\\'s corrective action included immediate actions to administratively suspend these procedures until they could be revised and to evaluate changes needed to its program to prevent recurrence. The failure to maintain procedures covered by Regulatory Guide 1.33 is a performance deficiency. The finding is of more than minor significance because, if left uncorrected, the failure to maintain and control procedures would have the potential to lead to a more significant safety concern. Using Inspection Manual Chapter 0609, Phase 1,\\\"Initial Screening and Characterization of Findings,\\\" the finding was determined to have a very low safety significance because the finding did not result in a loss of system safety function, an actual loss of safety function of a single train for greater than its technical specification allowed outage time, or screen as potentially risk significant due to a seismic, flooding, or severe weather initiating event. The finding has a crosscutting aspect in the area of problem identification and resolution associated with the corrective action program component, because problems were not thoroughly evaluated, such that the resolutions addressed the causes and extents of condition. This includes properly classifying and prioritizing conditions adverse to quality. |
| 05000361/FIN-2010006-09 | 2010Q2 | San Onofre | Failure to Establish Goals And Monitor for A(A) Auxiliary Feedwater Trains | Two examples of a noncited violation of 10 CFR 50.65(a)(1) were identified involving the failure to monitor the unavailability time associated with equipment failures which were maintenance induced. The first example involved maintenance inadvertently bending the fuse holder contacts such that there was a loose connection on the power supply on the turbine-driven auxiliary feedwater pump resulting in its failure. The second example involved the failure to perform maintenance associated with a condensate storage tank isolation valve resulting in its failure during in-service testing. In both cases, if the licensee had assessed the unavailability time due to the maintenance induced failures, the systems would have exceeded the 10 CFR 50.65(a)(2) monitoring criteria, necessitating the systems to be placed in 10 CFR 50.65(a)(1) goal setting. The licensee\'s corrective actions included evaluating its procedures to prevent recurrence, and re-evaluating these systems to determine the impact of accounting for unavailable time. This finding is more than minor because it affects the equipment performance attribute of the Mitigating Systems Cornerstone per Inspection Manual Chapter 612, Appendix 8. Using Inspection Manual Chapter 0609, Phase 1, \"Initial Screening and Characterization of Findings,\" the inspectors determined the finding to be of very low safety significance (Green) because they did not represent the loss of a system safety function and did not screen as potentially risk significant due to a seismic, flooding, or severe weather initiating event The cause of the finding was determined to have a crosscutting aspect in the area of human performance. Specifically, personnel failed to use a formal decision making process to determine how to count unavailable hours for the maintenance rule. |
| 05000361/FIN-2010006-10 | 2010Q2 | San Onofre | Failure to Identify and Correct Use of Deficient Relays | The inspectors identified a noncited violation of 10 CFR Part 50, Appendix 8, Criterion XVI, \"Corrective Action,\" in that, from October 2008 to April 2010, the licensee failed to promptly identify and correct potentially degraded motor-driven relays in safety-related systems and components. Specifically, after identifying a degraded relay affecting an emergency diesel generator, the licensee replaced all similar relays in the other diesel generators but failed to evaluate the use of these potentially degraded relays in other safety-related systems. The licensee entered this issue into the corrective action program as Nuclear Notification 200146292, and developed a plan to replace the 62 degraded relays that were installed in other safety-related equipment This finding was more than minor because it impacted 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. Using Inspection Manual Chapter 0609.04, Phase 1, initial screening and Characterization of Findings,\" the inspectors determined the finding to be of very low safety significance (Green) because it did not represent the loss of a system safety function and did not screen as potentially risk significant due to a seismic, flooding, or severe weather initiating event. This finding has a crosscutting aspect in the area of human performance associated with the decision-making component, in that the licensee did not use conservative assumptions in making decisions about the extent of condition. |
| 05000361/FIN-2010006-11 | 2010Q2 | San Onofre | Failure to Secure Loose Items in the Electrical Switchyard | The inspectors identified a noncitied violation of Technical Specification 5.5.1.1.a involving the failure to follow procedural guidance of S0123-XX-11, \"Switchyard Work Performance.\" Specifically, the inspectors identified temporary equipment stored in the switchyard that was not tethered or otherwise secured in accordance with the procedure. The licensee entered a notification in its corrective action program as Nuclear Notification 200870138, and removed or secured the items. This finding is more than minor because it impacts the protection against the external factors attribute of the Initiating Events Cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown and power operations. Using the Inspection Manual Chapter 0609 \"Significance Determination Process,\" Phase 1 Worksheet, the inspectors determined that the finding was of very low safety significance (Green) because it did not contribute to both the likelihood of a reactor trip and the likelihood that mitigation equipment or functions would not be available. This finding also has a human performance crosscutting aspect associated with the work control component in that personnel failed to appropriately plan work activities involving job site conditions which may impact plant structures, systems and components. |
| 05000361/FIN-2010006-12 | 2010Q2 | San Onofre | Failure to Maintain Design Basis Information | The inspectors identified a noncited violation of 10 CFR Part 50, Appendix B, Criterion III, \\\"Design Control\\\" in that the licensee failed to translate design basis information into procedures for the turbine-driven auxiliary feedwater pump steam admission valves. Specifically, the licensee did not translate into procedures the design requirements to manually close and gag the valves within 30 minutes in response to high energy line breaks, a fire in the auxiliary feedwater pump room, or a steam generator tube rupture event. This issue was entered into the licensee\\\'s corrective action program as Nuclear Notification 200887620. Immediate actions included posting a leveraging device for operators to use should it be necessary, training operators, and scheduling lubrication of the valves. The finding is more than minor because it impacted the Mitigating Systems Cornerstones and its objective to ensure the availability and reliability of equipment that responds to initiating events. The analyst screened the issue to more than one cornerstone due to its effect on early release (steam generator tube rupture), fire protection, and mitigating systems (high energy line break). The analyst performed a Phase 3 analysis that considered the effects of a high energy line break in the pump room, a steam generator tube rupture, and fires in the pump room and auxiliary feedwater pipe tunnel. The analyst determined that the combined significance of these scenarios was a delta- core damage frequency of 5.E-9/yr and a delta- large early release frequency of 1.6E-9/yr. Therefore, the violation was determined to be of very low safety significance (Green). The inspectors determined that cause of the finding has a crosscutting aspect in the area of problem identification and resolution associated with the corrective action program. Specifically, the licensee had previous opportunities to identify this problem when the valve was removed from the in-service testing program and when they evaluated relevant external operating experience. |
| 05000361/FIN-2010006-13 | 2010Q2 | San Onofre | Failure to Meet Action Plan for Substantive Crosscutting Issues | The inspectors identified a Green finding associated with the licensee\\\'s failure to meet the actions described to the NRC in letters dated April 21,2009, and October 29 and 30, 2009, addressing corrective actions to improve site performance in the areas of human performance and problem identification and resolution. Specifically, 16 actions were not implemented on time and a number of actions were modified from what was previously described, all prior to informing the NRC. These findings were documented in Nuclear Notification 200848923. The inspectors determined that the licensee\\\'s failure to perform actions as documented in its plan to the NRC was more than minor because if left uncorrected could result in a more significant safety concern. Using Inspection Manual Chapter 0609, Appendix M, this finding was reviewed by NRC management and was determined to be of very low safety significance (Green). This finding has a crosscutting aspect in the areas of human performance. |
| 05000369/FIN-2004003-02 | 2004Q1 | Mcguire McGuire | Failure to Update the UFSAR - (Two Examples) | The inspectors identified a non-cited violation for failure to update the Updated Final Safety Analysis Report (UFSAR) as required by 10 CFR 50.71(e) for inclusion of all aspects of the fire protection program, including the standby shutdown facility (SSF) and fire protection safe shutdown methodology. This issue is greater than minor because the failure to include descriptive information on fire protection defense-indepth features in the UFSAR could have an impact on future design or operational changes to the safe shutdown methodology or SSF. However, it is of very low safety significance because use of the un-updated UFSAR did not result in unacceptable changes to the facility or procedures. The inspectors identified an additional example of a previously identified non-cited violation (05000369,370/2004003-02) for failure to update the Updated Final Safety Analysis Report (UFSAR) as required by 10 CFR 50.71(e). Specifically, the inspectors noted a failure to resolve an UFSAR discrepancy with the Design Basis Document regarding feedwater isolation valve stroke time requirements. This issue is greater than minor because the failure to include descriptive information on feedwater isolation valve stroke time requirements could have an impact on future stroke time tests and subsequent performance of the isolation valves. However, it is of very low safety significance because use of the un-updated UFSAR did not result in unacceptable changes to the facility or procedures. |
| 05000369/FIN-2004005-02 | 2004Q3 | Mcguire McGuire | Failure to Obtain a License Amendment Prior to Implementing an Unreviewed Safety Question Associated with the Nuclear Service Water System | The inspectors identified a non-cited violation of 10CFR50.59 for failure to obtain a license amendment prior to implementing a change to plant procedures that involved an unreviewed safety question. The unreviewed safety question dealt with extending the availability of non- seismic condenser circulating water piping to perform a safety-related function following a seismic event. This issue is more than minor because it would require NRC review prior to implementation. A subsequent engineering evaluation determined that the non-seismic piping would not collapse or kink, and although it may leak, it will provide the necessary minimal service water flow function. Since the technical issue was determined to be of very low safety significance, the regulatory significance was categorized as a Severity Level IV violation. |
| 05000369/FIN-2004005-03 | 2004Q3 | Mcguire McGuire | Failure to Obtain a License Amendment Prior to Implementing a Design Change to the Facility Associated with the Auxiliary Feedwater System | A non-cited violation of 10CFR50.59 was identified by the inspectors for changing the design of the auxiliary feedwater system as described in the Updated Final Safety Analysis Report without performing a safety evaluation or obtaining a Technical Specification change. The change reduced the required number of trains of auxiliary feedwater from three independent trains to two independent trains to safely shutdown the reactor. This failure to perform a safety evaluation and submit a Technical Specification change is more than minor because it would require an NRC review prior to implementation. Because there was no evidence to indicate that the licensee had used the change the safety significance was determined to be very low. Consequently, the regulatory significance was categorized as a Severity Level IV violation. |
| 05000369/FIN-2005002-08 | 2005Q1 | Mcguire McGuire | Failure to Report a Condition Prohibited by Technical Specifications | A non-cited violation was identified by the inspectors for failure to report a condition prohibited by Technical Specifications related to past inoperability for main steam isolation valve 1SM-1, as required by 10 CFR 50.73. Based on the very low safety significance of the technical issue, this violation is categorized as a Severity Level IV violation under the NRC Enforcement Policy, Supplement I. |
| 05000369/FIN-2005004-02 | 2005Q3 | Mcguire McGuire | Failure to Update the UFSAR for Caprms | A non-cited violation was identified by the inspectors for failure to update the UFSAR as required by 10 CFR 50.71(e) related to inclusion of the license amendment request safety analysis information pertaining to the use of alternative instrumentation and procedures in place of seismic qualification for the Containment Atmosphere Particulate Monitors (CAPRMs) The issue was greater than minor because the failure to include in the UFSAR the alternative methodology for RCS leakage detection after a seismic event with unqualified CAPRMs, as described in the licensees safety analysis, was material to the acceptability of the license amendment requests. The inspectors found no subsequent changes made to the facility that were based on the erroneous information in the UFSAR section. Consequently, this issue was considered to meet the criteria of a severity level IV violation. This finding involved the crosscutting aspect of Problem Identification and Resolution. |
| 05000369/FIN-2006004-02 | 2006Q3 | Mcguire McGuire | Failure to Adequately Correct UFSAR Deficiencies for the Ssf | A non-cited violation (NCV) was identified for failing to take adequate corrective action for the last Updated Final Safety Analysis Report (UFSAR) which did not include all the important information for the standby shutdown facility (SSF), the subject of two previous NCVs. The UFSAR did not include that the turbine-driven auxiliary feedwater (TDAFW) pump suction condenser circulating water makeup source was isolated by two dc power-operated valves which open automatically on low pump suction pressure, even though it was important information to demonstrate required system power source and suction supply diversity. This finding is in the licensees corrective action program as Plant Investigation Process (PIP) M-06-3240. This finding is more than minor because it had the potential for impacting the NRCs ability to perform its regulatory function and had a material impact on licensed activities. The inadequate UFSAR information had been used in a 10 CFR 50.59 screening that resulted in not performing a safety evaluation when required, to determine whether prior NRC approval was needed. This issue was considered as traditional enforcement and was characterized as a Severity Level IV. The failure to adequately update the UFSAR for the SSF was the subject of two previous violations (NCVs 05000369,370/2004003- 02, and NCV 05000369,370/2005004-01 for untimely corrective action). The cause of the finding is related to the cross-cutting area of Problem Identification and Resolution because the licensee failed to thoroughly evaluate similar problems such that the extent of condition was considered and the cause resolved to prevent recurrence. |
| 05000369/FIN-2006004-03 | 2006Q3 | Mcguire McGuire | Failure to Adequately Update the UFSAR for Station Blackout | An NRC-identified NCV was identified for failure to adequately update the Updated Final Safety Analysis Report (UFSAR) for the station blackout rule (10 CFR 50.63) implementation. Some station blackout (SBO) mitigating equipment described in the submitted information and analysis have been changed, and because they were not contained in the UFSAR, were not evaluated under 10 CFR 50.59 for their effect on station blackout mitigation, to determine whether prior NRC approval was needed. This finding is in the licensees corrective action program as Plant Investigation Process (PIP) M-06-3244. The finding is more than minor because it had a material impact on licensed activities. The missing UFSAR information identified the systems and methodology used to combat a station blackout as described in the station blackout rule. This issue was considered as traditional enforcement because it had the potential for impacting the NRCs ability to perform its regulatory function. This issue was considered to meet the criteria for a severity level IV violation. The cause of the finding is related to the crosscutting area of Problem Identification and Resolution because the licensee failed to thoroughly evaluate similar problems such that the extent of condition was considered and the cause resolved to prevent recurrence. |
| 05000369/FIN-2006004-04 | 2006Q3 | Mcguire McGuire | Failure to Perform 72.48 Evaluations for 72.212 Changes | An NRC-identified non-cited violation of 10 CFR 72.212 was identified for failing to evaluate changes to the written evaluations required by 72.212(b)(2) using the requirements of 72.48(c). Even though licensee procedure NSD 211, 10 CFR 72.48 Process, required that one be performed, the licensee had not performed any 72.48(c) evaluations for any changes to the 72.212(b)(2) written evaluations for the NAC-UMS casks or the TN-32 casks since the requirement was included in the rule (5 revisions). This finding is in the licensees corrective action program as Plant Investigation Process (PIP) M-06-3729. This issue is greater than minor because the failure to perform 72.48(c) evaluations on any changes to 72.212 written evaluations had a reasonable likelihood that the changes could require NRC review and approval. This issue was considered as traditional enforcement because it had the potential for impacting the NRCs ability to perform its regulatory function and was characterized as a Severity Level IV violation. |
| 05000369/FIN-2006007-01 | 2006Q2 | Mcguire McGuire | Failure to Follow Procedure During ND Pump 1B Performance Test | The team identified an unresolved item (URI) for failure to follow procedures during performance of a TS required PT for ND pump 1B. Specifically, steps in completed procedure PT/1/A/4204/001B were signed by an individual that was not qualified to sign the steps, the individual signed steps as completed which were not performed, and the individual designated a non-conditional step as being not applicable (N/A). This item is unresolved pending further NRC review of the circumstances surrounding these examples of failure to follow procedures.Analysis: Failure to follow procedures PT/1/A/4204/001B and OMP 4-1 is a performance deficiency. This finding is related to the procedure quality attribute of the mitigating systems cornerstone and affects the objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The failure to follow procedures did not affect the pump performance during the periodic test and there was no actual loss of safety function. Enforcement: 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 shall be accomplished in accordance with these instructions, procedures, or drawings. Procedure OMP 4-1, Use of Operating and Periodic Test Procedures, Revision 28 stated that procedure users shall be qualified to perform the task, initial or check each step after the action is completed, and shall not N/A any non-conditional step, unless approved. Contrary to the above, during the performance of PT/1/A/4204/001B, 1B ND Pump Performance Test, Revision 72, on October 2, 2005, the procedure user signed certain steps without having the appropriate qualifications, initialed steps as being completed that were not performed, and marked N/A on a non-conditional step without documented approval. This condition has existed since October 2, 2005. The licensee entered this item into the corrective action program as PIP M-06-1462. This finding is identified as URI 05000369/2006007-01, Failure to Follow Procedure During ND Pump 1B Performance Test. This finding is unresolved pending further NRC review of the circumstances surrounding these examples of failure to follow procedures. |
| 05000369/FIN-2007003-01 | 2007Q2 | Mcguire McGuire | Debris in Unit 1 ECCS Sump | While reviewing PIP M-07-1609, the inspectors discovered that on March 17, 2007, the licensee found fire wrap/blanket in the Unit 1 Train B ECCS sump. The blanket was folded over multiple times and partially stuffed into the annular area between the ECCS suction pipe penetration bellows and the bellows guard pipe. The licensee performed an extent of condition inspection for train A, and found a similar fire wrap/blanket in the same respective location. In addition, the PIP indicated that there was other additional material found inside the screened sump structure, behind the suction piping supports, which included non-transportable debris (i.e., two 16P nails, 12\\\" drill bit, 3\\\" cutting wheel, 12\\\" nut, and a 4\\\" partial welding rod stick) and transportable debris (i.e., 3\\\"x6\\\" paper tag dated 3/13/04, a cigarette butt, an empty cigarette package, and several small pieces (<2\\\"x3\\\") of aged, friable duct-tape). The licensee performed several evaluations with regard to this issue during the inspection period which were documented in a Materials Lab Report, dated April 30, 2007, and a Reportability Support Evaluation for PIP M-07-1609, dated May 21, 2007. The Materials Lab Report was included as Attachment 1 to the Reportability Support Evaluation, a thermal expansion analysis was included as Attachment 2, and Attachment 3 was a February 21, 2007, test on ECCS Throttle Valve Duct Tape Flow Testing, which was conducted as part of an evaluation for the Unit 2 duct tape issue documented in Unresolved Item (URI) 05000370/2006005-01. The licensee plans to conduct a more refined throttle valve test for the Unit 2 duct tape issue in the near future. The Unit 1 ECCS debris in the sump issue is greater than minor because if left uncorrected the transportable debris could have had a detrimental affect on the availability and reliability of both trains of the Unit 1 ECCS when called upon during an accident. Specifically, the debris had the potential to have detrimental effects on the high pressure and low pressure ECCS recirculation function. This issue is unresolved pending completion of the NRC review of the licensees reportability evaluation and the results of the more refined duct tape testing. It is identified as URI 05000369/2007003- 01, Debris in the Unit 1 ECCS Sump. |
| 05000369/FIN-2007003-02 | 2007Q2 | Mcguire McGuire | Reactor Vessel Head Lift Practices Related to Design and Licensing Basis | Based on a review of the documents listed in the Attachment of this report related to heavy load lifts of the reactor vessel head and discussions with licensee personnel, the inspectors identified the following issues: The licensee could not demonstrate that a risk assessment had been performed for the increase in risk associated with the lifting and setting of the reactor vessel head. The licensee could not demonstrate that their reactor vessel head lifts, which lift the head to approximately 38 feet over the irradiated fuel in the reactor vessel, were bounded by any design calculations which evaluated the drop of the head through air onto the reactor vessel, upper internals, and irradiated fuel. The licensee could not demonstrate that their procedures for the reactor vessel head removal and installation, ever limited their head lifts to the bounds contained in an August 17, 1984 letter sent to the NRC concerning a load drop analysis for reactor vessel head lifts. The licensee could not demonstrate that their UFSAR had been adequately updated to reflect information and analyses provided to the NRC as the result of all generic communications relative to their resolution of heavy loads issues. The licensee issued PIPs M-07-3099, M-07-3410, and G-07-0449 to address the above issues. A complex maintenance plan was issued for the most recent head installation that occurred on May 18, 2007, to manage risk. A multi-site team has been formed to address the issues above and to work with vendors to determine whether an alternative design and licensing basis exists that bounds past practices. The issues identified above are greater than minor because they are associated with the design control attribute of the Initiating Events Cornerstone and affected the cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown. The issues are also greater than minor because the failure to update the UFSAR could have an impact on safety and may require a license amendment for resolution. These issues are unresolved pending the completion of the licensees investigation into whether an alternative design and licensing basis exists and whether reactor vessel head lifts were ever performed within the bounds of that basis. They are identified as URI 05000369,370/2007003-02, Reactor Vessel Head Lift Practices Related to Design and Licensing Basis |
| 05000369/FIN-2007005-02 | 2007Q4 | Mcguire McGuire | Failure to Control a LOCKED-HIGH Radiation Area Barrier | No findings of significance were identified. However, on September 30, 2006, during a refueling outage on Unit 2, a radiation protection technician left the reactor head inspection stand locked-high radiation area (LHRA) barrier unlocked and unguarded from approximately 5:05 to 5:21 a.m., contrary to the requirements of Technical Specification 5.7.2. Dose rates as high as 10 rad/hr at 30 cm and 4 rad/hr general area were present inside the reactor head stand LHRA. This event was appropriately reported to the NRC as an occupational radiation safety cornerstone performance indicator occurrence. The licensees root cause failure analysis report determined the root cause to be that the radiation protection technician did not perform the procedure steps as written (to ensure the barrier was secure) due to poor work practices and failure to validate assumptions; however, the inspectors determined that additional review and discussion of the details of the event, the licensees root cause analysis, and the implemented corrective actions were required to characterize the significance of the event. Therefore, this issue is identified as URI 05000370/2007005-02, Failure to Control a Locked-High Radiation Area Barrier. This issue is in the CAP as PIP M-06- 4479. |
| 05000369/FIN-2007005-03 | 2007Q4 | Mcguire McGuire | Failure to Take Adequate Corrective Action for Implementations of SAFETY-RELATED Rn Strainer Backwash | On August 6, 2007, the licensee identified that the procedures for performing a manual backwash of the nuclear service water strainers directed operators to use a nonseismically qualified, non-safety related air system to manipulate the valves required for the manual backwash function. This unqualified air system cannot be relied upon to function during a DBA. These backwash procedures were written as part of a 2003 plant modification (MGMM-14403) to upgrade and reclassify the manual RN filtering and backwash functions to safety-related, in response to NRC concerns (PIP M-02-2427). The concerns were that the changed environment of Lake Norman had caused seasonal macro-fouling of the strainers from increased concentrations of Alewife fish during late July and early August. The basis for reclassification was to ensure proper operation of the strainer in the event that significant fouling from these fish occurred. This modification also failed to identify reliance on other non-safety instrumentation and components for performing safety-related backwashes, including the UFSAR-credited differential pressure instrument. The reliance on non-safety-related systems to perform the safety-related manual backwash function was not recognized during the modification. The inspectors found that the licensee has continued to evaluate this issue after the LER was submitted. These continuing evaluations address such aspects as what happens inside the strainer, at what point does flow become less than what is needed as identified in design calculations, and what actions would operators take that might impact when the minimum flow point is reached. This finding involves the inability to perform a safety-related manual backwash of nuclear service water strainers due to reliance on non-safety systems and motive force to provide the backwash function. Without manual backwash capability during macrofouling season, these strainers could become permanently fouled, which could prevent the nuclear service water system from performing its intended safety function. This issue is more than minor because it affects the availability, reliability, and capability of the nuclear service water system and is related to the design control, protection from external factors (loss of heat sink), and procedure quality attributes of the mitigating systems cornerstone. This issue is unresolved pending NRC review of the licensees evaluations of past strainer operability, including the licensees classification of significant fouling periods and the engineering analyses of the fish clogging effects on the strainer. This item is identified as Unresolved Item (URI) 05000369,370/2007005-03 Failure to Take Adequate Corrective Action for Implementation of Safety-Related RN Strainer Backwash. This issue is in the licensees corrective action program as PIP M- 07-4313. |
| 05000369/FIN-2007005-05 | 2007Q4 | McGuire | Failure to Follow Procedure During Residual Heat Removal Pump 1B Performance Test | Failure to Follow Procedure During Residual Heat Removal (ND) Pump 1B Performance Test (PT). As described in NRC Inspection Report 05000369,370/2006007, this concerned a failure to follow procedures during performance of a TS required PT for ND pump 1B. Specifically, steps in completed procedure PT/1/A/4204/001B were signed by an individual that was not qualified to sign the steps, the individual signed steps as completed that were not performed, and the individual designated a non-conditional step as being not applicable (N/A). On January 30, 2007, the NRC Office of Investigations (OI) completed an investigation pertaining to URI 05000369/2006007-04. Based on a review of the OI investigation, the NRC determined that a violation of NRC requirements occurred. The Severity Level IV violation was cited in an OI letter dated July 17, 2007 (NOTICE OF VIOLATION, EA-07- 130). For administrative purposes this violation (VIO) is designated as VIO 05000369/ 2007005-05, Failure to Follow Procedure During Residual Heat Removal Pump 1B Performance Test. The inspectors have reviewed the licensees August 16, 2007, response to the Notice of Violation and subsequent corrective actions. Because the results of PT/1/A/4204/001B were not affected by the procedural non-compliance and appropriate corrective actions have been taken, URI 05000369/2006007-01 and VIO 05000369/2007005-05 are closed. |
| 05000369/FIN-2008005-02 | 2008Q4 | Mcguire McGuire | Accelerated Sequencer not Described in the UFSAR | While reviewing Unit 1, Train A, engineering safeguard features test deficiency data on October 22, 2008, the inspectors identified that the accelerated sequencer function was not described in the UFSAR. The licensees UFSAR commits to Regulatory Guide 1.70, Standard Format and Content of Safety Analysis Reports for Nuclear Power Plants, Revision 1 and 3, for the format and content of the UFSAR. RG 1.70, Revision 1, Section 8.3.1.1 states to Describe the onsite A.C. power systems with emphasis placed on those portions of the systems that are safety-related. Those portions of the onsite A.C. power system that are not related to safety need only be described in sufficient detail to permit an understanding of their interactions with the safety-related portions. The description of the safety-related portion should include: (8) automatic loading and stripping of buses. The inspectors review concluded that the accelerated sequencer function can sequentially energize various safety equipment (partitioned into load groups) from the safety-related emergency A.C. power system during design basis accidents described in UFSAR Chapter 15. This accelerated sequencer function will automatically energize the next safety load group, after 2 seconds, if the emergency A.C. bus voltage and diesel engine speed recover to values of approximately 92.5% and 97%, respectively. If after energizing certain safety load groups, the bus voltage or diesel speed permissives are no longer met, the accelerated sequencer function will drop out the start signal and those loads will become de-energized until the permissives are met again or the separate UFSAR described load sequencer function re-energizes those loads based on a timed sequence. Pending NRC review of the enforcement aspects of this issue and review of the licensees operability evaluation, this issue is identified as an Unresolved Item: URI 05000369,370/2008005-02, Accelerated Sequencer not Described in the UFSAR. The licensee generated PIPs M-08-6767 and M-09-0063 to address this concern |
| 05000369/FIN-2008008-01 | 2007Q4 | Mcguire McGuire | Failure to Take Adequate Corrective Action for Implementation of Safety-Related RN Strainer Backwash) | On December 31, 2007, the U.S. Nuclear Regulatory Commission (NRC) completed a quarterly integrated inspection at your McGuire Nuclear Station. The inspection findings were documented in NRC Inspection Report 05000369/2007005 and 5000370/2007005, which was issued on January 31, 2008. Section 4OA3 of that report identified Unresolved Item (URI) 05000369,370/2007005-03, which concerned a failure to take adequate corrective action related to implementation of a safetyrelated service water (RN) strainer backwash system. Subsequent to additional inspection, the performance deficiency was identified as a failure to correct a significant condition adverse to quality identified in 2002 related to macro-fouling of the RN strainers, in that the corrective action failed to ensure that the design and licensing basis required ability for manual strainer backwash could be maintained even during accident conditions. More specifically, the 2003 plant modification that was implemented to address the macro-fouling concern (i.e., upgrade and reclassification of the strainer backwash function to safety-related): (1) utilized non-safetyrelated instrument air (VI) to maintain each RN pumps strainer backwash discharge valve open, but did not provide a means to manually open (or bypass) the discharge valve to support backwash operations upon a loss of VI; and (2) did not account for the impact on timely operator response from higher strainer macro-fouling rates (whether from fish or other potential sources) and expected (nuisance) strainer delta pressure alarms (without fouling) at the onset of high RN flow events (i.e., safety injection and loss of VI). As such, between 2003 and August 7, 2007, there was a lack of reasonable assurance that the RN system would be able to perform its safety-related function upon a safety injection or loss of VI event during periods of macrofouling This finding was assessed based on the best available information, including influential assumptions, using the applicable Significance Determination Process (SDP) and was preliminarily determined to be a Greater Than Green Finding. Enclosed is a summary of the SDP Phase 3 analysis. It reflects a finding of greater than very low safety significance because, in the event of a loss of RN backwash capability, either through response to a safety injection signal or a loss of VI, that occurs during a time of high fouling potential, there was a lack of reasonable assurance that the RN system would have been capable of performing its safetyrelated function. The significance of the finding is influenced by uncertainties in the calculation for assumptions made for the initiating event frequency for the loss of VI, and for the calculated exposure time for the periods of fouling. Because of these uncertainties, the result was classified as Greater Than Green. The finding does not represent a current safety concern because temporary modifications and appropriate procedural changes have been made to address periods of potential macro-fouling. The finding is also an apparent violation (AV) of 10 CFR 50 Appendix B Criterion XVI, Corrective Action, for the failure to correct a significant condition adverse to quality related to macro-fouling of the RN strainers. This apparent violation (identified as AV 05000369,370/2008008-01, Failure to Take Adequate Corrective Action for Implementation of Safety-Related RN Strainer Backwash) is being considered for escalated enforcement action in accordance with the NRC Enforcement Policy. Accordingly, for administrative purposes, URI 05000369,370/2007005-03 is considered closed. |
| 05000369/FIN-2009002-01 | 2009Q1 | Mcguire McGuire | Failure to Correct a Condition Adverse to Quality Associated with Abnormal Procedures for Loss of Nuclear Service Water | The inspectors identified a non-cited violation of 10 CFR 50, Appendix B, Criterion XVI, Corrective Action, for the failure to promptly correct a condition adverse to quality associated with the sharing of the nuclear service water system between units in abnormal operating procedures (APs). Specifically, the licensee had neither developed a safety analysis to demonstrate the safety of this activity nor revised the procedural steps that allowed sharing. This finding is more than minor because it affected the availability, reliability, and capability of the Nuclear Service Water (RN) system (ultimate heat sink) and was related to the design control and procedure quality attributes of the Mitigating Systems cornerstone. In addition, this finding could be reasonably viewed as a precursor to a significant event (i.e., loss of RN on both units). The issue was determined to be of very low safety significance in IMC 0609 SDP Phase 1 screening based on the fact that it did not represent an actual loss of system safety function nor a loss of a single train of RN for greater than its Technical Specification allowed outage time, because the subject procedural steps of the APs had never been used. This finding has a cross-cutting aspect of corrective action in the area of Problem Identification and Resolution (P.1.d), because the licensee failed to take appropriate corrective action in a timely manner. The licensee plans to revise the procedure, complete a calculation to support the donating of one train of nuclear service water to the other unit when two trains are available from the donor unit, and perform an associated 10 CFR 50.59 review |
| 05000369/FIN-2009002-02 | 2009Q1 | Mcguire McGuire | Failure to Adequately Describe the Load Squencer Function in the FSAR | The inspectors identified a non-cited violation of 10 CFR 50.34(b)(2) for failing to include in the Updated Final Safety Analysis Report (UFSAR) a description and analysis of the separate accelerated sequencer function that loads the safety-related equipment onto the safety-related emergency A.C. power system buses using different criteria than the committed sequencer function described in the UFSAR. This issue is greater than minor because the failure to have a description of the accelerated sequencer function in the UFSAR had a material impact on licensed activities, in that any modifications to safety-related systems, such as the modification that removed the seal-in function from the control room chiller digital control system, would need to consider the interaction with the accelerated sequencer (in addition to the separate committed load sequencer) to ensure that risk significant equipment, as modified, would function as analyzed. This issue was treated as traditional enforcement, because it had the potential for impacting the NRCs ability to perform its regulatory function. It was characterized as a Severity Level IV violation, because the occurrence of the control room chiller failing to start(after being dropped by the accelerated load sequencer) when required by the committed load sequencer function during testing, had very low safety significance. This issue has a cross-cutting aspect of appropriate corrective action in the area of problem identification and resolution P.1.(d). This aspect was chosen because the licensee recognized, as documented in a January 12, 2007 letter to the NRC, that there were content problems with the UFSAR and was in the process of trying to correct it. However, the inspectors could not find any completed interim corrective action documented in the licensees corrective action program that would alert/caution UFSAR users that compensatory actions were needed in order to perform adequate evaluations such as for operability, reportability, or 10 CFR 50.59.The licensee intends to add the accelerated sequence function to the UFSAR and install seal-in functions for the affected load blocks in the accelerated sequence |
| 05000369/FIN-2009007-01 | 2009Q2 | Mcguire McGuire | Failure to Take Adequate Corrective Action for Appendix R Emergency Lighting Credited for Operator Action | The inspectors identified a non-cited violation of McGuire Unit 2 Operating License Condition 2.C.4 for failure to implement and maintain their Fire Protection Program as described in design basis document MCS-1465.00-00-008, Plant Design Basis Specification for Fire Protection. Specifically, the licensee failed to take prompt, adequate corrective action to ensure installation of an emergency light for a local operator manual action at Breaker 2EMXB-2A. The licensee entered the issue into the corrective action program and issued a night order informing Operations staff to carry flashlights until the light can be installed. This finding is more than minor because it is associated with the reactor safety Mitigating Systems cornerstone attribute of protection against external factors (i.e., fire) and it affects the objective of ensuring reliability and capability of systems that respond to initiating events. The inspectors determined the finding was of very low safety significance (Green) based on the high likelihood of operators completing the task using flashlights. This finding has a cross-cutting aspect of Human Performance in the area of Resources (H.2.c), because the licensee failed to ensure the modification package was accurate to reflect the correct breaker that required an emergency light as described in the corrective action |
| 05000369/FIN-2009007-02 | 2009Q2 | Mcguire McGuire | Pertinent Fire Brigade Information and Guidance Not Identified in Fire Fighting Strategies | The inspectors identified a non-cited violation of Unit 2 Operating License Condition 2.C.4 and the Fire Protection Program as contained in design basis document MCS-1465.00-00-008, Plant Design Basis Specification for Fire Protection. Specifically, the licensee implemented a deficient fire pre-plan strategy in fire areas 10/12 which failed to provide pertinent information and guidance on alternate available communications to assist the fire brigade for a fire within the area as required by the licensing basis. The licensee entered the problem into their corrective action program and issued a night order informing Operations staff of the potential inability to use radios in fire areas 10/12. The finding is greater than minor because it affected the ability of the licensee to maintain communications for a fire in fire areas 10/12 and is associated with the Mitigating Systems cornerstone and respective attribute of protection against external factors, i.e. fire. The safety significance of the deficient fire pre-plan strategy was determined to be very low because the fire pre-plan strategy would not impede the fire brigades ability to extinguish a fire in the specified fire areas. This finding has a cross-cutting aspect in the area of Problem Identification & Resolution for the Corrective Action Program component (P.1c) because the licensee failed to thoroughly evaluate the previously identified problems associated with the fire preplans to ensure that the corrective actions were effective in identifying and correcting issues with the communications availability for the fire brigade. |
| 05000369/FIN-2012007-01 | 2012Q2 | Mcguire McGuire | Failure to Evaluate Potential Blocking of TDCA Pump Lube Oil Cooler During Certain Fire Events | The team identified a non-cited violation of McGuire Unit 1 and 2 Operating License Condition 2.C.4 for the licensees failure to evaluate potential blockage of the Turbine Driven Auxiliary Feedwater (TDCA) pump lube oil cooler when pump suction is aligned to the circulating water (RC) system. Specifically, during certain fire events causing loss of plant control, the team identified that if the RC system piping was aligned to the suction of the TDCA pump as in accordance with the licensing basis, it could result in blockage of cooling water flow for the TDCA pump lube oil cooler. Immediate actions by the licensee included performing a functional assessment and evaluating potential long term corrective actions. The licensee entered this issue in their corrective action program as PIP M-12-2174. The performance deficiency was determined to be more than minor because it was similar to IMC 0612 Appendix E question 3j in that, there was reasonable doubt as to the operability of the auxiliary feedwater system when suction was supplied from RC system. In addition, the finding was associated with the design control attribute of the Mitigating Systems Cornerstone and affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The finding was evaluated using IMC 0609, Attachment 4, Phase 1, and IMC 0609 Appendix F, Fire Protection Significance Determination Process , Attachment 1, Phase 1 and determined to be of low safety significance because it only affected the ability to reach and maintain cold shutdown. The team determined that no cross cutting aspect was applicable to this performance deficiency because this finding was not indicative of current licensee performance. |
| 05000369/FIN-2012007-02 | 2012Q2 | Mcguire McGuire | Inadequate Tornado Missile Protection for EDG Exhaust Ventilation System. | The team identified a non-cited violation of 10 CFR Part 50, Appendix B, Criterion III, Design Control, for the licensees failure to ensure adequate tornado missile protection for the emergency diesel generator (EDG) exhaust relief and backdraft dampers as required. Specifically, 12 inches of the upper portion of the EDG Building ventilation system exhaust dampers were exposed and not protected from a tornadogenerated missile. The licensee initiated compensatory measures in the form of concrete jersey barriers in front of each exhaust damper opening to provide additional shielding for the unprotected opening. The licensee entered this issue in their corrective action program as PIP M-12-2158. The performance deficiency was determined to be more than minor because it was associated with the Mitigating Systems Cornerstone attribute of Equipment Performance, and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, there was reasonable doubt the EDG ventilation exhaust would remain functional to support EDG operation in the event tornado-induced missiles damaged the exhaust backdraft relief dampers. The team performed a Phase 1 evaluation per Inspection Manual Chapter 0609, Attachment 4 and determined that the finding was potentially risk significant due to a seismic, flooding, or severe weather initiating events (e.g., tornadoes). Consequently, a Phase 3 analysis was performed by a senior reactor analyst, who determined that the risk significance of the issue was very low (i.e., ALERF < 1.0E-7). The team determined there was a cross cutting aspect in the area of Problem Identification and Resolution, in that the licensee did not thoroughly evaluate problems with adequate tornado missile protection such that the resolutions address causes and extent of conditions, as necessary. |
| 05000395/FIN-2007006-01 | 2007Q2 | Summer | Failure to Protect Cables Associated With Air Operated Valve IFV-3541 in FZ IB-25.1.2 | A noncompliance of very low safety significance with VCSNS Operating License Condition 2.C.(18) was identified for the licensees failure to protect or separate cabling associated with the Emergency Feedwater (EFW) pump discharge valve to the B Steam Generator routed through the Intermediate Building elevation 412 ft. (FZ IB- 25.1.2). The EFW pump discharge valve to the B Steam Generator was required to remain operational to achieve and maintain safe shutdown for a postulated fire in FZ IB- 25.1.2. The noncompliance met the criteria for NRC enforcement discretion. During review of procedure FEP-1.0, Enclosure B, Part 32, in conjunction with FEP-2.0, the team identified that the licensee utilized a local OMA to manually throttle open Air Operated Valve (AOV) IFV-3541 to prevent spurious operation due to potential fire damage during a postulated fire in FZ IB-25.1.2. AOV IFV-3541, the motor driven (MD) EFW pump discharge valve to the B Steam Generator, is normally open and is required to remain open to establish the EFW flowpath to the B Steam Generator from the MD EFW pumps. The FPER requires the A train (safe shutdown train) of EFW for SSD for a fire in FZ IB-25.1.2. Cables EFW102B and EFW146B for AOV IFV-3541 are located in IB-25.1.2 while the AOV itself is located on the mezzanine level of the adjacent FZ IB-25.1.3. This mezzanine is not physically independent of IB-25.1.2. The licensee failed to protect cables EFW102B and EFW146B from potential fire damage in IB-25.1.2. In lieu of protecting the required cables from fire damage, which could prevent modulation of the AOV and defeat the SSD strategy, the licensee instead took local control of the valve using a local OMA. The team performed a walk through of this local OMA to determine its feasibility per the criteria in Enclosure 2 to NRC IP 71111.05TTP, Fire Protection - NFPA 805 Transition Period (Triennial). Since the OMA would be performed in the adjacent FZ, smoke migration to this zone was a concern. The team determined the action to be feasible because the operator would be using a self-contained breathing apparatus (SCBA) and hand-held radio. Also, the two adjacent FZs are part of a very large FA, IB-25 (with a low fire hazard loading), and it would take time for a fire to grow large enough to create a significant amount of smoke where it could become a concern. Fire Area, IB-25.1.2 has area-wide automatic fire detection and suppression (sprinklers) which would most likely control the fire before damage to the cables would occur. |